Filed pursuant to Rule 424(b)1
Registration Statement No. 333-113556
[CMS ENERGY LOGO]
Prospectus
$300,000,000
CMS ENERGY CORPORATION
Exchange Offer for all Outstanding
7.75% Senior Notes due 2010
--------------------------------------------------------------------------------
THE EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON
SEPTEMBER 29, 2004 UNLESS WE EXTEND IT.
--------------------------------------------------------------------------------
Terms of the Exchange Offer
-----------------------
We are offering to exchange new registered 7.75% Senior Notes due 2010 for all
of our old unregistered 7.75% Senior Notes due 2010.
The terms of the new notes will be identical in all material respects to the
terms of the old notes, except that the registration rights and related
liquidated damages provisions and the transfer restrictions applicable to the
old notes will not be applicable to the new notes. The new notes will have the
same financial terms and covenants as the old notes, and will be subject to the
same business and financial risks. Any outstanding old notes not validly
tendered will remain subject to existing transfer restrictions.
Subject to the satisfaction or waiver of specified conditions, we will exchange
the new notes for all old notes that are validly tendered and not withdrawn by
you at any time prior to the expiration of the Exchange Offer as described in
this prospectus.
The new notes will not be listed on any securities exchange or included in any
automatic quotation system.
We will not receive any proceeds for the exchange.
We are not asking you for a proxy and you are requested not to send us a proxy.
--------------------------------------------------------------------------------
THIS INVESTMENT INVOLVES RISK. SEE "RISK FACTORS" BEGINNING ON PAGE 14.
--------------------------------------------------------------------------------
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.
The date of this prospectus is August 26, 2004
TABLE OF CONTENTS
PAGE
----
Important Notice about Information in this Prospectus.......................................... 1
Where You Can Find More Information............................................................ 1
Forward-Looking Statements and Information..................................................... 2
Summary........................................................................................ 4
Risk Factors................................................................................... 14
Use of Proceeds................................................................................ 24
Ratio of Earnings to Fixed Charges............................................................. 24
Description of the New Notes................................................................... 24
Ratings........................................................................................ 43
The Exchange Offer............................................................................. 43
Management's Discussion and Analysis of Financial Condition
and Results of Operations for the Six Months Ended June 30, 2004............................... 52
Management's Discussion and Analysis of Financial Condition
and Results of Operations for the Fiscal Year Ended December 31, 2003.......................... 87
Our Business................................................................................... 120
Legal Proceedings.............................................................................. 131
Our Management................................................................................. 134
Affiliate Relationships and Transactions....................................................... 141
Certain United States Federal Income Tax Consequences.......................................... 141
Plan of Distribution........................................................................... 144
Legal Opinion.................................................................................. 144
Experts........................................................................................ 144
Glossary....................................................................................... 146
Index to Consolidated Financial Statements..................................................... F-1
IMPORTANT NOTICE ABOUT INFORMATION IN THIS PROSPECTUS
You should rely only on the information contained in this prospectus or to
which we have referred you. We have not authorized anyone to provide you with
information that is different or to make any representations about us or the
transactions we discuss in this prospectus. If you receive information about
these matters that is not included in this prospectus, you must not rely on that
information. This document may only be used where it is legal to sell these
securities. The information in this document may only be accurate on the date of
this document.
WHERE YOU CAN FIND MORE INFORMATION
We file reports, proxy statements and other information with the SEC under
File No. 1-9513. Our SEC filings are also available over the Internet at the
SEC's web site at http://www.sec.gov. You may also read and copy any document we
file at the SEC's public reference room at 450 Fifth Street N.W., Room 1024,
Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for more
information on the public reference rooms and their copy charges. You may also
inspect our SEC reports and other information at the New York Stock Exchange, 20
Broad Street, New York, New York 10005. You can find additional information
about us, including our Annual Report on Form 10-K/A for the year ended December
31, 2003, our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004
and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 on our
Web site at http://www.cmsenergy.com. The information on this Web site is not a
part of this prospectus.
We have filed with the SEC a registration statement on Form S-4 under the
Securities Act, and the rules and regulations promulgated under the Securities
Act of 1933 (the "SECURITIES ACT"), with respect to the new notes offered for
exchange under this prospectus. This prospectus, which constitutes part of that
registration statement, does not contain all of the information set forth in the
registration statement and the attached exhibits and schedules. The statements
contained in this prospectus as to the contents of any contract, agreement or
other document that is filed as an exhibit to the registration statement are not
necessarily complete. Accordingly, each of those statements is
1
qualified in all respects by reference to the full text of the contract,
agreement or document filed as an exhibit to the registration statement or
otherwise filed with the SEC.
FORWARD-LOOKING STATEMENTS AND INFORMATION
This prospectus contains forward-looking statements as defined in Rule
3b-6 of the Securities Exchange Act of 1934, as amended, Rule 175 of the
Securities Act of 1933, as amended, and relevant legal decisions. Our intention
with the use of such words as "may," "could," "anticipates," "believes,"
"estimates," "expects," "intends," "plans," and other similar words is to
identify forward-looking statements that involve risk and uncertainty. We
designed this discussion of potential risks and uncertainties to highlight
important factors that may impact our business and financial outlook. We have no
obligation to update or revise forward-looking statements regardless of whether
new information, future events or any other factors affect the information
contained in the statements. These forward-looking statements are subject to
various factors that could cause our actual results to differ materially from
the results anticipated in these statements. Such factors include our inability
to predict and/or control:
- the efficient sale of non-strategic and under-performing domestic
and international assets and discontinuation of certain operations;
- capital and financial market conditions, including the current price
of our common stock and the effect on our pension plan, interest
rates and availability of financing to us, to Consumers Energy
Company ("CONSUMERS"), a wholly owned subsidiary, or any of their
affiliates and to the energy industry;
- ability to access the capital markets successfully;
- market perception of the energy industry, us and Consumers or any of
their affiliates;
- our and Consumers' or any of their affiliates' securities ratings;
- currency fluctuations, transfer restrictions and exchange controls;
- factors affecting utility and diversified energy operations such as
unusual weather conditions, catastrophic weather-related damage,
unscheduled generation outages, maintenance or repairs or electric
transmission or gas pipeline system constraints;
- international, national, regional and local economic, competitive
and regulatory policies, conditions and developments;
- adverse regulatory or legal decisions, including environmental laws
and regulations;
- the impact of adverse natural gas prices on the Midland Cogeneration
Venture Limited Partnership (the "MCV PARTNERSHIP") investment,
regulatory decisions concerning the MCV Partnership resource
conservation plan ("RCP"), and regulatory decisions that limit our
recovery of capacity and fixed energy payments;
- federal regulation of electric sales and transmission of
electricity, including re-examination by federal regulators of the
market-based sales authorizations by which our subsidiaries
participate in wholesale power markets without price restrictions
and proposals by the Federal Energy Regulatory Commission ("FERC")
to change the way it currently lets our subsidiaries and other
public utilities and natural gas companies interact with each other;
- energy markets, including the timing and extent of unanticipated
changes in commodity prices for oil, coal, natural gas, natural gas
liquids, electricity and certain related products due to lower or
higher demand, shortages, transportation problems or other
developments;
- potential disruption, expropriation or interruption of facilities or
operations due to accidents, war, terrorism, or changing political
conditions and the ability to obtain or maintain insurance coverage
for such events;
2
- nuclear power plant performance, decommissioning, policies,
procedures, incidents and regulation, including the availability of
spent nuclear fuel storage;
- technological developments in energy production, delivery and usage;
- achievement of capital expenditure and operating expense goals;
- changes in financial or regulatory accounting principles or
policies;
- outcome, cost, and other effects of legal and administrative
proceedings, settlements, investigations and claims, including
particularly claims, damages and fines resulting from round-trip
trading and inaccurate commodity price reporting, including an
investigation by the U.S. Department of Justice regarding round-trip
trading and price reporting;
- limitations on our ability to control the development or operation
of projects in which our subsidiaries have a minority interest;
- disruptions in the normal commercial insurance and surety bond
markets that may increase costs or reduce traditional insurance
coverage, particularly terrorism and sabotage insurance and
performance bonds;
- other business or investment considerations that may be disclosed
from time to time in our or Consumers' SEC filings or in other
publicly disseminated written documents; and
- other uncertainties, which are difficult to predict and many of
which are beyond our control.
The factors identified under "Risk Factors" on page 14 are also important
factors, but not necessarily all of the important factors, that could cause
actual results to differ materially from those expressed in any forward-looking
statement made by, or on behalf of, us or our subsidiaries.
3
SUMMARY
This summary may not contain all the information that may be important to
you. You should read this prospectus to which we refer you to in their entirety
before making an investment decision. The terms "CMS," "CMS ENERGY," "OUR," "US"
and "WE" as used in this prospectus refer to CMS Energy Corporation and its
subsidiaries as a combined entity, except where it is made clear that such term
means only CMS Energy Corporation.
In this document, "bcf" means billion cubic feet, "gWh" means
gigawatt-hour, "kWh" means kilowatt-hour, "mmbbls" means million barrels, "mmcf"
means million cubic feet and "MW" means megawatts.
CMS ENERGY CORPORATION
CMS Energy, formed in Michigan in 1987, is an integrated energy holding
company operating through subsidiaries in the United States and in selected
markets around the world. Its two principal wholly owned subsidiaries are
Consumers and CMS Enterprises Company ("ENTERPRISES"). Consumers is a public
utility that provides natural gas and/or electricity to almost 6.5 million of
Michigan's 10 million residents and serves customers in 61 of the 68 counties in
Michigan's Lower Peninsula. Enterprises, through subsidiaries, is engaged in
several energy businesses in the United States and in selected international
markets.
Our assets and services include: electric and natural gas utility
operations; independent power production; natural gas transmission, storage and
processing; international energy distribution; and marketing, services and
trading. Our principal businesses are:
- Consumers' electric utility, which owns and operates 30 electric
generating plants with an aggregate of 6,431 MW of capacity and
serves 1.77 million customers in Michigan's Lower Peninsula;
- Consumers' gas utility, which owns and operates over 27,463 miles of
transmission and distribution lines throughout the Lower Peninsula
of Michigan, providing natural gas to 1.67 million customers;
- CMS Generation Co. ("CMS GENERATION"), a wholly owned subsidiary of
Enterprises, that has ownership interests in independent power
plants with 6,766 gross MW (3,157 net MW) throughout the United
States and abroad. The plants are located in the U.S., Argentina,
Chile, Ghana, India, Jamaica, Morocco and the United Arab Emirates.
CMS Generation currently has ownership interests in the Shuweihat
power plant, which is under construction in the United Arab
Emirates, and the Saudi Petrochemical Company power plant, which is
in advanced development and will be located in the Kingdom of Saudi
Arabia. These plants total approximately 1,784 gross MW (420 net MW)
of electric generation; and
- CMS Gas Transmission Company ("CMS GAS TRANSMISSION"), is a wholly
owned subsidiary of Enterprises, that owns an interest in and
operates natural gas pipelines in various locations in North and
South America. The pipelines are located in the U.S., Argentina and
Chile. It also owns gathering systems and processing facilities.
In 2003, we had consolidated operating revenue of approximately $5.5
billion.
4
RECENT DEVELOPMENTS
SECOND QUARTER 2004 RESULTS OF OPERATIONS
IN MILLIONS (EXCEPT FOR PER SHARE AMOUNTS)
------------------------------------------
RESTATED
THREE MONTHS ENDED JUNE 30 2004 2003 CHANGE
------------------------------------------------------------ ------------ ------------ ------------
Net Income (Loss) Available to Common Stock ................ $ 16 $ (65) $ 81
Basic Earnings (Loss) Per Share ............................ $ 0.10 $ (0.45) $ 0.55
Diluted Earnings (Loss) Per Share .......................... $ 0.10 $ (0.45) $ 0.55
Electric utility ........................................... $ 27 $ 35 $ (8)
Gas utility ................................................ 1 5 (4)
Enterprises ................................................ 38 8 30
Corporate interest and other ............................... (50) (60) 10
Discontinued operations .................................... - (53) 53
------------ ------------ ------------
CMS Energy Net Income (Loss) Available to Common Stock ..... $ 16 $ (65) $ 81
============ ============ ============
For the three months ended June 30, 2004, our net income was $16 million,
compared to a loss of $65 million for the three months ended June 30, 2003. The
$81 million increase in net income primarily reflects:
- the absence of a $53 million loss from discontinued operations
recorded in 2003, comprised mainly of the loss on the sale of
Panhandle,
- the absence of a $31 million deferred tax asset valuation reserve
established in 2003,
- an $11 million increase in mark-to-market valuation adjustments on
interest rate swaps and power contracts, and
- a $6 million reduction in funded benefits expense primarily due to
the postretirement benefit plans, other than pensions, for retired
employees ("OPEB") plans accounting for the Medicare Prescription
Drug, Improvement, and Modernization Act of 2003 and the positive
impact of prior year pension plan contributions on pension plan
asset returns.
These increases were partially offset by:
- the absence of a $30 million Michigan Single Business Tax refund
received in 2003, and
- a reduction in the Utility's net income resulting primarily from
industrial and commercial customers choosing different electricity
suppliers and decreased gas deliveries caused primarily by milder
weather.
IN MILLIONS (EXCEPT FOR PER SHARE AMOUNTS)
------------------------------------------
RESTATED
SIX MONTHS ENDED JUNE 30 2004 2003 CHANGE
------------------------------------------------------------ ------------ ------------ ------------
Net Income Available to Common Stock ....................... $ 9 $ 17 $ (8)
Basic Earnings Per Share ................................... $ 0.06 $ 0.12 $ (0.06)
Diluted Earnings Per Share ................................. $ 0.06 $ 0.14 $ (0.08)
Electric utility ........................................... $ 75 $ 86 $ (11)
Gas utility ................................................ 57 59 (2)
Enterprises ................................................ (23) 29 (52)
Corporate interest and other ............................... (98) (111) 13
Discontinued operations .................................... (2) (22) 20
Accounting changes ......................................... - (24) 24
------------ ------------ ------------
CMS Energy Net Income Available to Common Stock ............ $ 9 $ 17 $ (8)
============ ============ ============
For the six months ended June 30, 2004, CMS Energy's net income was $9
million, compared to net income of $17 million for the six months ended June 30,
2003. The $8 million change reflects:
- an $81 million charge to earnings related to the sale of our Loy
Yang A power plant ("LOY YANG");
- the absence of a $30 million Michigan Single Business Tax refund
received in 2003; and
5
- a reduction in the Utility's net income resulting primarily from
industrial and commercial customers choosing different electricity
suppliers and decreased gas deliveries caused primarily by milder
weather.
These losses were partially offset by:
- the exclusion in 2004 of a $24 million charge for changes in
accounting that occurred in the first quarter of 2003;
- the absence of a $31 million deferred tax asset valuation reserve
established in 2003;
- the decrease of $20 million in the net loss from discontinued
operations resulting from the sale of Panhandle and other businesses
in 2003;
- a $31 million increase in mark-to-market valuation adjustments on
interest rate swaps and power contracts; and
- a $13 million reduction in funded benefits expense primarily due to
the OPEB plans accounting for the Medicare Prescription Drug,
Improvement, and Modernization Act of 2003 and the positive impact
of prior year pension plan contributions on pension plan asset
returns.
SALE OF AUSTRALIAN PIPELINES
On August 17, 2004 we sold our interests in a business located in
Australia comprised of a pipeline, processing facilities, and a gas storage
facility ("PARMELIA") and a pipeline business located in Australia in which we
held a 39.7 percent ownership interest ("GOLDFIELDS") to the Australian Pipeline
Trust ("APT") for approximately $206 million Australian (approximately $147
million in U.S. dollars).
SALE OF LOY YANG
In April 2004, we and our partners sold the 2,000-megawatt Loy Yang power
plant and adjacent coal mine located in Victoria, Australia for approximately
$3.5 billion Australian (approximately $2.6 billion in U.S. dollars), including
$145 million Australian for the project equity. We owned 49.6 percent of Loy
Yang. NRG Energy Inc. and Horizon Energy Australia Investments each owned about
25 percent of Loy Yang. CMS Energy's share of the proceeds was approximately $71
million Australian (approximately $44 million in U.S. dollars), subject to
closing adjustments and transaction costs. We recognized an $81 million
after-tax impairment charge in the first quarter of 2004, primarily related to
prior currency translation adjustments.
CONSOLIDATION OF THE MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP AND
THE FIRST MIDLAND LIMITED PARTNERSHIP
Under revised FASB Interpretation No. 46 "Consolidation of Variable
Interest Entities," we determined that we are the primary beneficiary of both
the MCV Partnership and the First Midland Limited Partnership ("FMLP"). We have
a 49 percent partnership interest in the MCV Partnership and a 46.4 percent
partnership interest in the FMLP. Consumers is the primary purchaser of power
from the MCV Partnership through a long-term power purchase agreement. In
addition, the FMLP holds a 75.5 percent lessor interest in the MCV Partnership's
facility (the "MCV FACILITY"), which results in Consumers holding a 35 percent
lessor interest in the MCV Facility. Collectively, these interests make us the
primary beneficiary of these entities. As such, we consolidated their assets,
liabilities and activities into our financial statements for the first time as
of and for the quarter ended March 31, 2004. These partnerships had third-party
obligations totaling $728 million at June 30, 2004. Property, plant and
equipment serving as collateral for these obligations had a carrying value of
$1.453 billion at June 30, 2004. The creditors of these partnerships do not have
recourse to the general credit of CMS Energy.
RECENT FINANCINGS AND SECURITIES OFFERINGS
We have initiated several transactions with various financial
institutions, lenders, banks and others to provide liquidity:
- As of August 3, 2004, we obtained an amended and restated $300
million secured revolving credit facility to replace both our $190
million facility and $185 million letter of credit facility. The
amended facility carries a three-year term and provides for a lower
interest rate.
6
- As of August 3, 2004, Consumers obtained an amended and restated
$500 million secured revolving credit facility to replace its $400
million facility. The amended facility carries a three-year term and
provides for a lower interest rate.
- On August 17, 2004, Consumers issued $800 million of first mortgage
bonds (the "BONDS") in a private placement to institutional
investors in three separate series. The $150 million Series K Bonds
will mature on August 15, 2009 and will bear interest at the rate of
4.40%. The $300 million Series L Bonds will mature on February 15,
2012 and will bear interest at the rate of 5.00%. The $350 million
Series M Bonds will mature on August 15, 2016 and will bear interest
at the rate of 5.50%.
7
THE OLD NOTES
The Old Notes................ On July 17, 2003 we sold $300 million principal
amount of our 7.75% Senior Notes due 2010 (the
"OLD NOTES"). The old notes were offered to
qualified institutional buyers under Rule 144A.
Registration Rights
Agreement.................... We executed a Registration Rights Agreement
that provides that we would grant certain
registration and exchange rights to old note
holders (the "REGISTRATION RIGHTS AGREEMENT").
As a result, we have filed a registration
statement with the SEC that will permit you to
exchange the old notes for new notes that are
registered under the Securities Act. The
transfer restrictions and liquidated damages
provisions will be removed from the new notes.
We are conducting the Exchange Offer to satisfy
our obligations with respect to certain
exchange and registration rights. Except for a
few limited circumstances, these rights will
terminate when the Exchange Offer ends.
THE EXCHANGE OFFER
Securities Offered........... $300 million principal amount of our 7.75%
Senior Notes due 2010 (the "NEW NOTES").
Exchange Offer............... We are offering to exchange (the "EXCHANGE
OFFER") up to $300 million principal amount of
our 7.75% Senior Notes due 2010 that have been
registered under the Securities Act for a like
principal amount of our 7.75% Senior Notes due
2010.
The new notes will be offered for all of the
outstanding old notes. The terms of the new
notes will be identical to the terms of the old
notes, except that the registration rights and
related liquidated damages provisions and the
transfer restrictions are not applicable to the
new notes. The old notes may be tendered only
in integral amounts of $1,000.
Resale of New Notes.......... Based on SEC no action letters, we believe that
after the Exchange Offer you may offer and sell
the new notes without registration under the
Securities Act so long as:
- You acquire the new notes in the ordinary
course of business.
- When the Exchange Offer begins you do not
have an arrangement with another person to
participate in a distribution of the new
notes.
- You are not distributing and do not intend
to distribute the new notes.
When you tender the old notes we will ask you
to represent to us that:
- You are not our affiliate.
- You will acquire the new notes in the
ordinary course of business.
- When the Exchange Offer begins you are not
distributing and you do not plan to
distribute with anyone else the new notes.
8
If you are unable to make these
representations, you will be required to comply
with the registration and prospectus delivery
requirements under the Securities Act in
connection with any secondary resale
transaction.
If you are a broker-dealer and receive new
notes for your own account, you must
acknowledge that you will deliver a prospectus
if you resell the new notes. By acknowledging
your intent and delivering a prospectus you
will not be deemed to admit that you are an
"underwriter" under the Securities Act. You may
use this prospectus as it is amended from time
to time when you resell new notes that were
acquired from market-making or trading
activities. For a year after the Expiration
Date we will make this prospectus available to
any Broker-dealer in connection with such a
resale. See "Plan of Distribution."
If necessary, we will cooperate with you to
register and qualify the new notes for offer or
sale without any restrictions or limitations
under state "blue sky" laws.
Consequences of Failure to
Exchange Old Notes........... If you do not exchange your old notes during
the Exchange Offer you will no longer be
entitled to registration rights. You will not
be able to offer or sell the old notes unless
they are later registered, sold pursuant to an
exemption from registration or sold in a
transaction not subject to the Securities Act
or state securities laws. See "The Exchange
Offer--Consequences of Failure to Exchange."
Expiration Date.............. 5:00 p.m., EST on September 29, 2004 (the
"EXPIRATION DATE"). We may extend the exchange
offer.
Conditions to the Exchange
Offer........................ No minimum principal amount of old notes must
be tendered to complete the Exchange Offer.
However, the Exchange Offer is subject to
certain customary conditions that we may waive.
See "The Exchange Offer--Conditions." Other
than United States federal and state securities
laws we do not need to satisfy any regulatory
requirements or obtain any regulatory approval
to conduct the Exchange Offer.
Procedures for Tendering
Old Notes.................... If you wish to participate in the Exchange
Offer you must complete, sign and date the
letter of Transmittal (the "LETTER OF
TRANSMITTAL") or a facsimile copy and mail it
or deliver it to the Exchange Agent along with
any necessary documentation. Instructions and
the address of the Exchange Agent will be on
the Letter of Transmittal and can be found in
this prospectus. See "The Exchange
Offer--Procedures for Tendering" and;
"--Exchange Agent." You must also effect a
tender of old notes pursuant to the procedures
for book-entry transfer as described in this
prospectus. See "The Exchange Offer--Procedures
for Tendering."
Guaranteed Delivery
Procedures................... If you cannot tender the old notes, complete
the Letter of Transmittal or provide the
necessary documentation prior to the
termination of the Exchange Offer, you may
tender your old notes according to the
guaranteed delivery procedures set forth in
"The Exchange Offer--Guaranteed Delivery
Procedures."
9
Withdrawal Rights............ You may withdraw tendered old notes at any time
prior to the 5:00 p.m. EST on the Expiration
Date. You must send a written or facsimile
withdrawal notice to the Exchange Agent prior
to 5:00 p.m. EST on the Expiration Date.
Acceptance of Old Notes and
Delivery of New Notes........ All old notes properly tendered to the Exchange
Agent by 5:00 p.m. EST on the Expiration Date
will be accepted for exchange. The new notes
will be delivered promptly after the Expiration
Date. See "The Exchange Offer--Acceptance of
Old Notes for Exchange; Delivery of New Notes"
Certain United States Tax
Consequences ................ Exchanging old notes for the new notes will
not be a taxable exchange for United States
federal income tax purposes. See "Certain
United States Federal Income Tax Consequences."
Exchange Agent............... J.P. Morgan Trust Company, N.A. is the exchange
agent (the "EXCHANGE AGENT") for the Exchange
Offer.
Fees and Expenses............ We will pay all fees and expenses associated
with the Exchange Offer and compliance with the
Registration Rights Agreement.
Use of Proceeds.............. We will receive no cash proceeds in connection
with the issuance of the new notes pursuant to
the Exchange Offer. See "Use of Proceeds."
THE NEW NOTES
Issuer....................... CMS Energy Corporation.
Securities Offered........... $300 million aggregate principal amount of
7.75% Senior Notes due 2010 to be issued under
the senior debt indenture.
Maturity..................... August 1, 2010.
Interest Rate................ The new notes will bear interest at the rate of
7.75% per year, payable semiannually in arrears
on February 1 and August 1, commencing on
February 1, 2005, and at maturity.
Use of Proceeds.............. We will receive no cash proceeds in connection
with the issuance of the new notes pursuant to
the Exchange Offer. See "Use of Proceeds."
Optional Redemption.......... The new notes will be redeemable at our option,
in whole or in part, at any time or from time
to time, upon not less than 30 nor more than 60
days' notice before the redemption date by mail
to the Trustee, the paying agent and each
Holder of the new notes, for a price equal to
100% of the principal amount of the new notes
to be redeemed plus any accrued and unpaid
interest, and Applicable Premium owed, if any,
to the redemption date. See "Description of the
New Notes-- Optional Redemption."
Change in Control............ If a Change in Control (as defined under
"Description of the New Notes-- Purchase of
Notes Upon Change in Control") occurs, Holders
will have the right, at their option, to
require us to purchase any or all of their new
notes for cash. The cash price we are required
to pay is equal to 101% of the principal amount
of the new notes to be purchased plus accrued
and unpaid interest, if any, to the Change in
Control purchase date. See "Description of the
New Notes--Purchase of New Notes Upon Change in
Control."
10
Ratings...................... B+ by Standard & Poor's Ratings Group, a
division of The McGraw Hill Companies, Inc.
("S&P"), B3 by Moody's Investors Service, Inc.
("MOODY'S") and B+ by Fitch, Inc. ("FITCH").
See "Ratings."
Ranking...................... The new notes will be unsecured and
unsubordinated senior debt securities of ours
ranking equally with our other unsecured and
unsubordinated indebtedness. As of June 30,
2004, we had outstanding approximately $3.2
billion aggregate principal amount of
indebtedness, including approximately $178
million of subordinated indebtedness relating
to our convertible preferred securities and
$506 million of subordinated indebtedness
relating to Consumers' mandatorily redeemable
preferred securities, but excluding
approximately $4.5 billion of indebtedness of
our subsidiaries. None of our indebtedness
would be senior to the new notes. In August
2004, CMS Energy entered into the Fifth Amended
and Restated Credit Agreement in the amount of
approximately $300 million. This facility is
secured and the new notes would not be senior
to such indebtedness. As of August 17, 2004
there were approximately $164 million of
letters of credit outstanding under the Fifth
Amended and Restated Credit Agreement. The new
notes will be senior to approximately $178
million of subordinated indebtedness relating
to our convertible preferred securities. The
new notes will be structurally subordinated to
approximately $4.5 billion of our subsidiaries'
debt and approximately $506 million of
subordinated indebtedness relating to
Consumers' mandatorily redeemable preferred
securities.
Certain Covenants............ The senior debt indenture will contain
covenants that will, among other things, limit
our ability to pay dividends or distributions,
incur additional indebtedness, incur additional
liens, sell, transfer or dispose of certain
assets, enter into certain transactions with
affiliates or enter into certain mergers or
consolidations.
Form of New Notes............ One or more global securities held in the name
of DTC in a minimum denomination of $1,000 and
any integral multiple thereof.
Trustee and Paying Agent..... J.P. Morgan Trust Company, N.A.
Trading...................... The new notes will not be listed on any
securities exchange or included in any
automated quotation system. The new notes are
expected to be eligible for trading in the
Portal Market; however, no assurance can be
given as to the liquidity of or trading market
for the new notes.
11
SELECTED CONSOLIDATED FINANCIAL DATA
The following selected financial data have been derived from our audited
consolidated financial statements, which have been audited by Ernst & Young LLP,
independent registered public accounting firm, for the fiscal years ended
December 31, 2003, 2002, 2001 and 2000, except for amounts included from the
financial statements of the MCV Partnership and Jorf Lasfar Energy Company
S.C.A. ("JORF LASFAR") and by Arthur Andersen LLP, independent accountants (who
have ceased operations), for the fiscal year ended December 31, 1999. The MCV
Partnership represents an investment accounted for under the equity method of
accounting through December 31, 2003, which was audited by another independent
registered public accounting firm (the other auditors for 2001 and 2000 have
ceased operations), for the fiscal years ended December 31, 2003, 2002, 2001,
2000 and 1999. Jorf Lasfar represents an investment accounted for under the
equity method of accounting, which was audited by another independent registered
public accounting firm for the fiscal years ended December 31, 2003, 2002, 2001,
2000 and 1999. The following selected consolidated financial data for the six
months ended June 30, 2004 and 2003 have been derived from our unaudited
consolidated financial statements. Please refer to our financial statements for
the quarter ended June 30, 2004, which are found on pages F-2 through F-7 of
this prospectus. Please refer to our financial statements for the fiscal year
ended December 31, 2003, which are found on pages F-51 through F-60 of this
prospectus. The financial information set forth below should be read in
conjunction with our consolidated financial statements, related notes and other
financial information that can be found on pages F-2 through F-197 of this
prospectus. Operating results for the six months ended June 30, 2004 are not
necessarily indicative of results that may be expected for the entire year
ending December 31, 2004. See "Where You Can Find More Information."
SIX MONTHS ENDED
----------------
JUNE 30, YEAR ENDED DECEMBER 31,
-------- -----------------------
RESTATED RESTATED RESTATED RESTATED RESTATED
2004 2003 2003 2002 2001 2000 1999
--------- --------- ------- -------- -------- -------- --------
(DOLLARS IN MILLIONS (DOLLARS IN MILLIONS
EXCEPT PER SHARE EXCEPT PER SHARE AMOUNTS)
AMOUNTS)
INCOME STATEMENT DATA:
Operating revenue........................ $ 2,847 $ 3,094 $ 5,513 $ 8,673 $ 8,006 $ 6,623 $ 5,114
Earnings from equity method investees.... 60 97 164 92 172 213 136
Operating expenses....................... 2,614 2,779 5,082 8,690 8,027 6,342 4,549
Operating income......................... 293 412 595 75 151 494 701
Income (loss) from continuing
operations............................. 17 63 (43) (394) (327) (85) 191
Net income available to common
shareholder (loss)..................... $ 9 $ 17 $ (44) $ (650) $ (459) $ 5 $ 277
========= ========= ======= ======== ======== ======== ========
Earnings per average common share:
Income (loss) from continuing
operations
Basic.................................. $ 0.07 $ 0.43 $ (0.30) $ (2.84) $ (2.50) $ (0.76) $ 1.66
Income (loss) from continuing
operations
Diluted................................ 0.07 0.43 (0.30) (2.84) (2.50) (0.76) 1.66
CMS Energy Basic Net Income (Loss)....... 0.06 0.12 (0.30) (4.68) (3.51) 0.04 2.18(i)
CMS Energy Diluted Net Income (Loss)..... 0.06 0.14 (0.30) (4.68) (3.51) 0.04 2.17(i)
Dividends declared per average
common share:
CMS Energy............................... $ -- $ -- $ -- $ 1.09 $ 1.46 $ 1.46 $ 1.39
BALANCE SHEET DATA:
Cash and cash equivalents................ $ 696 $ 917 $ 532 $ 351 $ 123 $ 143 $ 132
Restricted cash.......................... 213 205 201 38 4 -- --
Net plant and property(a)................ 8,528 6,674 6,944 6,103 6,703 6,316 8,995
Total assets............................. 15,307 13,939 13,838 14,781 17,633 17,801 16,336
Long-term debt, including current
Maturities(a)............................ 6,676 6,594 6,529 5,990 6,846 6,271 7,503
Long-term debt - related parties......... 684 -- 684 -- -- -- --
Non-current portion of capital leases.... 338 119 58 116 71 49 88
Notes payable............................ -- -- -- 458 416 403 230
Other liabilities........................ 4,862 5,120 4,604 6,174 7,008 7,486 4,924
Minority interest........................ 740 43 73 38 43 82 222
Company-obligated mandatorily
redeemable trust preferred
securities of subsidiaries (b)......... -- 393 -- 393 694 694 474
Company obligated trust preferred
securities of Consumers'
subsidiaries (b)....................... -- 490 -- 490 520 395 395
12
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
-------- -----------------------
RESTATED RESTATED RESTATED RESTATED RESTATED
2004 2003 2003 2002 2001 2000 1999
--------- --------- ------- -------- -------- -------- --------
(DOLLARS IN MILLIONS (DOLLARS IN MILLIONS
EXCEPT PER SHARE EXCEPT PER SHARE AMOUNTS)
AMOUNTS)
Preferred stock.............................. 261 -- 261 -- -- -- --
Preferred stock of subsidiary................ $ 44 $ 44 $ 44 $ 44 $ 44 $ 44 $ 44
Common stockholders' equity.................. 1,702 1,136 1,585 1,078 1,991 2,377 2,456
OTHER DATA:
Cash Flow:
Provided by (Used in) operating activities... $ 481 $ 147 $ (251) $ 614 $ 372 $ 600 $ 917
Provided by (Used in) investing activities... (214) 292 203 829 (1,349) (1,220) (3,564)
Provided by (Used in) financing activities... (276) 125 230 (1,223) 967 629 2,678
Ratio of earnings to fixed charges and
preferred securities dividends and
distributions(c)............................ --(d) 1.13 --(e) --(f) --(g) --(h) 1.28
-----------------
(a) Under revised FASB Interpretation No. 46 "Consolidation of Variable
Interest Entities," we are the primary beneficiary of the MCV Partnership
and the FMLP. As a result, we have consolidated their assets, liabilities,
and activities into our financial statements for the first time as of and
for the quarter ended March 31, 2004. These partnerships have third-party
obligations totaling $728 million at June 30, 2004. Property, plant, and
equipment serving as collateral for these obligations has a carrying value
of $1.453 billion at June 30, 2004.
(b) CMS Energy and Consumers each formed various statutory wholly owned
business trusts for the sole purpose of issuing preferred securities and
lending the gross proceeds to the parent companies. The sole assets of the
trusts are debentures of the parent company with terms similar to those of
the preferred securities. As a result of the adoption of FASB
Interpretation No. 46 on December 31, 2003, we deconsolidated the trusts
that hold the mandatorily redeemable trust preferred securities.
Therefore, $490 million, previously reported by us as Company-obligated
mandatorily redeemable trust preferred securities of subsidiaries, plus
$16 million owed to the trusts and previously eliminated in consolidation,
is now included in the balance sheet as Long-term debt - related parties.
Additionally, $173 million, previously reported by us as Company-obligated
convertible trust preferred securities of subsidiaries, plus $5 million
owed to the trusts and previously eliminated in consolidation, is now
included in the balance sheet as Long-term debt - related parties.
(c) For the purpose of computing the ratio, earnings represent net income
before income taxes and income from equity method investees, net interest
charges and preferred dividends of subsidiary, the estimated interest
portion of lease rentals and distributed income of equity method
investees.
(d) For the six months ended June 30, 2004, fixed charges exceeded earnings by
$47 million. Earnings as defined include $125 million of asset impairment
charges.
(e) For the year ended December 31, 2003, fixed charges exceeded earnings by
$59 million. Earnings as defined include $95 million of asset impairment
charges.
(f) For the year ended December 31, 2002, fixed charges exceeded earnings by
$472 million. Earnings as defined include $602 million of asset impairment
charges.
(g) For the year ended December 31, 2001, fixed charges exceeded earnings by
$392 million. Earnings as defined include $323 million of asset impairment
charges.
(h) For the year ended December 31, 2000, fixed charges exceeded earnings by
$224 million. Earnings as defined include a $329 million pretax impairment
loss on the Loy Yang investment.
(i) Reflects the reallocation of net income and earnings per share as a result
of the premium on exchange of Class G Common Stock. As a result, CMS
Energy's basic and diluted earnings per share were reduced $0.26 and
$0.25, respectively, and Class G Common Stock's basic and diluted earnings
per share were increased $3.31.
13
RISK FACTORS
In considering whether to exchange the old notes for the new notes, you
should carefully consider all the information we have included in this
prospectus. In particular, you should carefully consider the risk factors
described below. In addition, please read the information in "Forward- Looking
Statements and Information" beginning on page 2 of this prospectus, and see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations for the Six Months Ended June 30, 2004" and "Management's Discussion
and Analysis of Financial Condition and Results of Operations for the Fiscal
Year Ended December 31, 2003." Also see "Condensed Notes to Consolidated
Financial Statements For the Six Months Ended June 30, 2004 -- Note 3
Uncertainties" and "Notes to Consolidated Financial Statements For the Fiscal
Year Ended December 31, 2003 -- Note 4 Uncertainties" where we describe
additional uncertainties associated with our business and the forward-looking
statements in this prospectus.
RISKS RELATING TO CMS ENERGY
WE DEPEND ON DIVIDENDS FROM OUR SUBSIDIARIES TO MEET OUR DEBT SERVICE
OBLIGATIONS. IF WE DO NOT RECEIVE ADEQUATE DIVIDENDS OR DISTRIBUTIONS FROM OUR
SUBSIDIARIES, WE MAY NOT BE ABLE TO MAKE PRINCIPAL OR INTEREST PAYMENTS ON THE
NEW NOTES.
Due to our holding company structure, we depend on dividends from our
subsidiaries to meet our debt obligations, including the payment of any
principal or interest on the new notes. None of these entities are or will be
obligated to pay any amounts due on the new notes. Therefore, the new notes are
effectively subordinated to the payment of interest, principal and preferred
distributions on the debt, preferred securities and other liabilities of
Consumers and Enterprises and each of their subsidiaries.
On June 2, 2003, the MPSC issued a financing order authorizing the
issuance of $554 million of securitization bonds. The order would prohibit
Consumers from paying any extraordinary dividends to us until further order of
the MPSC. Pursuant to the order, extraordinary dividends are considered any
amount over and above Consumers' earnings. On July 1, 2003, Consumers filed a
petition for rehearing and clarification of certain portions of the order with
the MPSC, including the portion dealing with dividend restrictions. In December
2003, the MPSC issued its order on rehearing, which rejected our requests for
rehearing and clarification and remanded the proceeding to the administrative
law judge ("ALJ") for additional proceedings. In March 2004, the ALJ conducted
the remanded hearings and the matter is presently before the MPSC awaiting a
decision.
In December 2003, the MPSC issued an order granting interim gas rate
relief in the amount of $19.34 million annually. In connection with this rate
relief, Consumers agreed to limit its dividends to CMS Energy to a maximum of
$190 million annually during the period in which Consumers receives the interim
relief. The MPSC stated in its order that it was not determining at that time
whether dividend restrictions should continue after the issuance of a final
order.
Restrictions contained in Consumers' preferred stock provisions and other
legal restrictions limit Consumers' ability to pay dividends or acquire its own
stock from us. As of June 30, 2004, the most restrictive provisions in its
financing documents allowed Consumers to pay an aggregate of $300 million in
dividends to us during any year.
For additional information concerning restrictions on Consumers' ability
to pay dividends to us, see "Description of the New Notes -- Primary Source of
Funds of CMS Energy; Restrictions on Sources of Dividends."
THE NEW NOTES ARE STRUCTURALLY SUBORDINATED TO THE DEBT AND PREFERRED STOCK OF
OUR SUBSIDIARIES.
Of the approximately $7.7 billion of our consolidated indebtedness as of
June 30, 2004, approximately $5.1 billion was indebtedness of our subsidiaries,
including $506 million of Consumers' mandatorily redeemable preferred
securities. Payments on that indebtedness and preferred stock are prior in right
of payment to dividends paid to us by our subsidiaries. See "Description of the
New Notes -- Structural Subordination."
14
WE HAVE SUBSTANTIAL INDEBTEDNESS THAT COULD LIMIT OUR FINANCIAL FLEXIBILITY AND
HENCE OUR ABILITY TO MEET OUR DEBT SERVICE OBLIGATIONS UNDER THE NEW NOTES.
As of June 30, 2004, we had outstanding approximately $3.2 billion
aggregate principal amount of indebtedness, including approximately $178 million
of subordinated indebtedness relating to our convertible preferred securities
and $506 million of subordinated indebtedness relating to Consumers' mandatorily
redeemable preferred securities but excluding approximately $4.5 billion of
indebtedness of our subsidiaries. None of such indebtedness would be senior to
the new notes. In August 2004, we entered into the Fifth Amended and Restated
Credit Agreement in the amount of approximately $300 million. This facility is
secured and the new notes would be effectively junior to such indebtedness to
the extent of the security pledged therefore. As of August 17, 2004, there were
approximately $164 million of letters of credit outstanding under the Fifth
Amended and Restated Credit Agreement. We and our subsidiaries may incur
additional indebtedness in the future.
The level of our present and future indebtedness could have several
important effects on our future operations, including, among others:
- a significant portion of our cash flow from operations will be
dedicated to the payment of principal and interest on our
indebtedness and will not be available for other purposes;
- covenants contained in our existing debt arrangements require us to
meet certain financial tests, which may affect our flexibility in
planning for, and reacting to, changes in our business;
- our ability to obtain additional financing for working capital,
capital expenditures, acquisitions, general corporate and other
purposes may be limited;
- we may be at a competitive disadvantage to our competitors that are
less leveraged; and
- our vulnerability to adverse economic and industry conditions may
increase.
Our ability to meet our debt service obligations and to reduce our total
indebtedness will be dependent upon our future performance, which will be
subject to general economic conditions, industry cycles and financial, business
and other factors affecting our operations, many of which are beyond our
control. We cannot assure you that our business will continue to generate
sufficient cash flow from operations to service our indebtedness. If we are
unable to generate sufficient cash flow from operations, we may be required to
sell additional assets or obtain additional financings. We also plan to
refinance a substantial amount of our indebtedness prior to its maturity. We
cannot assure you that any such refinancing will be possible or that additional
financing will be available on commercially acceptable terms or at all.
There can be no assurance that the requirements of our existing debt
arrangements or other indebtedness will be met in the future. Failure to comply
with such covenants may result in a default with respect to the related debt and
could lead to acceleration of such debt or any instruments evidencing
indebtedness that contain cross-acceleration or cross-default provisions.
In such a case, there can be no assurance that we would be able to refinance or
otherwise repay such indebtedness.
WE HAVE FINANCING NEEDS AND WE MAY BE UNABLE TO SUCCESSFULLY ACCESS BANK
FINANCING OR THE CAPITAL MARKETS.
As of June 30, 2004, we had approximately $395 million of debt maturities
in 2004 and 2005 excluding subsidiaries. These maturities include: approximately
$176 million of senior notes due in November 2004; $180 million of senior notes
due in January 2005; and approximately $39 million of general term notes that
mature at various times in 2004 and 2005. In addition, we expect to incur
significant costs for future environmental regulation compliance, especially
compliance with clean air laws. See "We could incur significant capital
expenditures to comply with environmental standards and face difficulty in
recovering these costs on a current basis" below. As of June 30, 2004 we had
incurred $489 million in capital expenditures to comply with these regulations
and future capital expenditures may total approximately $282 million between
2004 and 2009. We could also become subject to liquidity demands pursuant to
commercial commitments under guarantees, indemnities and letters of credit.
After giving effect to
15
recent issuances of securities, along with asset sales, capital markets or bank
financing and cash flow from operations, we believe, but can make no assurance,
that we will have sufficient liquidity to meet our debt maturities through 2005.
Management is actively pursuing plans to refinance debt and to sell assets.
There can be no assurances that this business plan will be successful and
failure to achieve its goals could have a material adverse effect on our
liquidity and operations.
We continue to explore financing opportunities to supplement our financial
improvement plan. These potential opportunities include: refinancing our bank
credit facilities; entering into leasing arrangements and/or vendor financing;
refinancing and issuing new capital markets debt, preferred and/or common
equity; and negotiating private placement debt. We cannot guarantee the capital
market's acceptance of our securities or predict the impact of factors beyond
our control, such as actions of rating agencies. If we are unable to access bank
financing or the capital markets to incur or refinance indebtedness, there could
be a material adverse effect upon our liquidity and operations.
Standard & Poor's Ratings Group, a division of The McGraw Hill Companies,
Inc. ("S&P"), has assigned the new notes a rating of B+, Moody's Investors
Service, Inc. has assigned the new notes a rating of B3 and Fitch, Inc. has
assigned the new notes a rating of B+. We cannot assure you that these credit
ratings will remain in effect for any given period of time or that one or more
of these ratings will not be lowered or withdrawn entirely by a rating agency.
We note that these credit ratings are not recommendations to buy, sell or hold
our securities. Each rating should be evaluated independently of any other
rating. Any future reduction or withdrawal of one or more of our credit ratings
could have a material adverse impact on our ability to access capital on
acceptable terms. We cannot assure you that any of our current ratings or those
of our affiliates, including Consumers, will remain in effect for any given
period of time or that a rating will not be lowered or withdrawn entirely by a
rating agency.
Consumers accesses debt and other capital from various sources and carries
its own credit ratings. Any downgrade or other event negatively affecting the
credit ratings of Consumers could make its cost of borrowing higher or access to
funding sources more limited, which in turn could increase the need of CMS
Energy to provide liquidity in the form of capital contributions or loans, thus
reducing the liquidity and borrowing availability of the consolidated group.
Further, any adverse developments relating to Consumers, which provides
dividends to us, that result in a lowering of Consumers' credit ratings could
have an adverse effect on our credit ratings. Any lowering of the ratings on the
new notes would likely reduce the market value of the new notes.
WE MAY BE ADVERSELY AFFECTED BY A REGULATORY INVESTIGATION AND LAWSUITS
REGARDING "ROUND TRIP" TRADING BY ONE OF OUR SUBSIDIARIES AS WELL AS CIVIL
LAWSUITS REGARDING PRICING INFORMATION THAT TWO OF OUR AFFILIATES PROVIDED TO
MARKET PUBLICATIONS.
As a result of round trip trading transactions at CMS Marketing Services
and Trading Company ("CMS MST"), we are under investigation by the United States
Department of Justice. We have received subpoenas from U.S. Attorneys Offices
regarding investigations of those trades. CMS Energy and Consumers have also
been named in numerous class action lawsuits by individuals who allege that they
purchased CMS Energy securities during a purported class period. These
complaints generally seek unspecified damages based on allegations that the
defendants violated United States securities laws and regulations by making
allegedly false and misleading statements about the company's business and
financial condition. The cases have been consolidated into a single lawsuit and
an amended and consolidated complaint was filed on May 1, 2003. The judge issued
an opinion and order dated March 31, 2004 in connection with various pending
motions, including the plaintiffs' motion to amend the complaint and the motions
to dismiss the complaint filed by us, Consumers and other defendants. The judge
directed the plaintiffs to file an amended complaint under seal and ordered an
expedited hearing on the motion to amend, which was held on May 12, 2004. At the
hearing, the judge ordered the plaintiffs to file an amended complaint deleting
certain counts related to purchasers of CMS Energy-related securities, which the
judge ordered dismissed with prejudice. The plaintiffs filed this complaint on
May 26, 2004. We, Consumers and the individual defendants filed new motions to
dismiss on June 21, 2004. A hearing on those motions occurred on August 2, 2004
and the judge has taken the matter under advisement.
Our Board of Directors has received a demand on behalf of a shareholder of
CMS Energy to commence civil actions (i) to remedy alleged breaches of fiduciary
duties by CMS Energy officers and directors in connection with round trip
trading at CMS MST and (ii) to recover damages sustained by CMS Energy as a
result of alleged insider
16
trades alleged to have been made by certain current and former officers of CMS
Energy and its subsidiaries. In December 2002, two new directors were appointed
to our Board of Directors. A special litigation committee was formed by the
Board of Directors in January 2003 to determine whether it is in the best
interest of CMS Energy to bring the action demanded by the shareholder. The
disinterested members of the Board of Directors appointed the two new directors
to serve on the special litigation committee.
On December 2, 2003, during the continuing review by the special
litigation committee, we were served with a derivative complaint filed by the
shareholder in the Circuit Court of Jackson County, Michigan in furtherance of
his demands. The date for CMS Energy and other defendants to answer or otherwise
respond to the complaint was extended to December 1, 2004, subject to such
further extensions as may be mutually agreed upon by the parties and authorized
by the court.
We have notified appropriate regulatory and governmental agencies that
some employees at CMS MST and CMS Field Services, Inc. (now Cantera Gas Company)
appeared to have provided inaccurate information regarding natural gas trades to
various energy industry publications which compile and report index prices. CMS
Energy is cooperating with an investigation by the United States Department of
Justice regarding this matter. On November 25, 2003, the CFTC issued a
settlement order regarding this matter. CMS MST and CMS Field Services, Inc.
agreed to pay a fine to the CFTC totaling $16 million. In the settlement, CMS
Energy neither admits nor denies the findings of the CFTC in the settlement
order.
We have also been named as a defendant in several gas industry civil
lawsuits regarding inaccurate gas trade reporting that include a lawsuit
alleging violation of the Commodities Exchange Act and certain antitrust laws.
We cannot predict the outcome of the United States Department of Justice
investigation and the lawsuits. It is possible that the outcome in one or more
of the investigation or the lawsuits could adversely affect our financial
condition, liquidity or results of operations.
WE MAY BE NEGATIVELY IMPACTED BY THE RESULTS OF AN EMPLOYEE BENEFIT PLAN
LAWSUIT.
We are a defendant, along with Consumers, CMS MST and certain named and
unnamed officers and directors, in two lawsuits brought as purported class
actions on behalf of participants and beneficiaries of our 401(k) plan. The two
cases, filed in July 2002 in the United States District Court for the Eastern
District of Michigan, were consolidated by the trial judge and an amended and
consolidated complaint has been filed. Plaintiffs allege breaches of fiduciary
duties under the Employee Retirement Income Security Act of 1974 ("ERISA") and
seek restitution on behalf of the plan with respect to a decline in value of the
shares of our common stock held in the plan. The plaintiffs also seek other
equitable relief and legal fees. The judge issued an opinion and order dated
March 31, 2004 in connection with the motions to dismiss filed by us, Consumers
and the individuals. The judge dismissed certain of the amended counts in the
plaintiffs' complaint and denied our motion to dismiss the other claims in the
complaint. We, Consumers and the individual defendants filed answers to the
amended complaint on May 14, 2004. A trial date has not been set, but is
expected to be no earlier than late in 2005.
We cannot predict the outcome of the ERISA litigation and it is possible
that an adverse outcome in this lawsuit could adversely affect our financial
condition, liquidity or results of operations.
REGULATORY CHANGES AND OTHER DEVELOPMENTS HAVE RESULTED AND WILL CONTINUE TO
RESULT IN INCREASED COMPETITION IN OUR DOMESTIC ENERGY BUSINESS. GENERALLY,
INCREASED COMPETITION THREATENS OUR MARKET SHARE IN CERTAIN SEGMENTS OF OUR
BUSINESS AND CAN REDUCE OUR PROFITABILITY.
Consumers has in the last several years experienced, and expects to
continue to experience, a significant increase in competition for generation
services with the introduction of retail open access in the State of Michigan.
Pursuant to the Customer Choice Act, as of January 1, 2002, all electric
customers have the choice of buying electric generation service from an
alternative electric supplier. We continue to lose industrial and commercial
customers to other electric suppliers without receiving compensation for
stranded costs caused by the lost sales. As of July 2004, we had lost 858 MW or
11 percent of our electric generation business to these alternative electric
suppliers. We expect the loss to be in the range of 900 MW to 1,100 MW by
year-end 2004. We cannot predict the total amount of electric supply load that
we may lose to competitor suppliers in the future.
17
ELECTRIC INDUSTRY REGULATION COULD ADVERSELY AFFECT OUR BUSINESS, INCLUDING OUR
ABILITY TO RECOVER OUR EXPENSES FROM OUR CUSTOMERS.
Federal and state regulation of electric utilities has changed
dramatically in the last two decades and could continue to change over the next
several years. These changes could adversely affect our business, financial
condition and profitability.
In June 2000, the Michigan Legislature enacted the Customer Choice Act
that became effective June 5, 2000. Pursuant to the Customer Choice Act:
- residential rates were reduced by five percent and then capped
through at least December 31, 2005; and
- small commercial and industrial customer rates were capped through
at least December 31, 2004.
Ultimately, the rate caps could extend until December 31, 2013 depending
upon whether or not Consumers exceeds the market power supply test established
by the legislation (a requirement that Consumers believes itself to be in
compliance with at this time). Under circumstances specified in the Customer
Choice Act, certain costs can be deferred for future recovery after the
expiration of the rate cap period. The rate caps could, however, result in
Consumers being unable to collect customer rates sufficient to fully recover its
cost of conducting business. Some of these costs may be beyond Consumers'
ability to control. In particular, if Consumers needs to purchase power supply
from wholesale suppliers during the period when retail rates are frozen or
capped, the rate restrictions imposed by the Customer Choice Act may make it
impossible for Consumers to fully recover the cost of purchased power and
associated transmission costs through the rates it charges its customers. As a
result, it is not certain that Consumers can maintain its profit margins in its
electric utility business during the period of the rate freeze or rate caps.
There are multiple proceedings pending before FERC involving transmission
rates, regional transmission organizations and standard market design for
electric bulk power markets and transmission. We cannot predict the impact of
these electric industry-restructuring proceedings on our financial position,
liquidity or results of operations.
PENDING UTILITY LEGISLATION IN MICHIGAN MAY AFFECT US IN WAYS WE CANNOT PREDICT.
In July 2004, as a result of legislative hearings, several bills were
introduced into the Michigan Senate that could change Michigan's Customer Choice
Act. The proposals include:
- requiring that rates be based on cost of service;
- establishing a defined Stranded Cost calculation method;
- allowing customers who stay with or switch to alternative electric
suppliers after December 31, 2005 to return to utility services, and
requiring them to pay current market rates upon return;
- establishing reliability standards that all electric suppliers must
follow;
- requiring utilities and alternative suppliers to maintain a 15
percent power reserve margin;
- creating a service charge to fund the Low Income and Energy
Efficiency Fund;
- giving kindergarten through twelfth-grade schools a discount of 10
percent to 20 percent on electric rates; and
- authorizing a service charge payable by all customers for meeting
Clean Air Act requirements.
Although we do not believe the terms of the pending bills would have a
material adverse effect on our business, the final form of any new utility
legislation may differ from the pending bills. We cannot predict whether these
or other measures will be enacted into law or their potential effect on us.
18
OUR ABILITY TO RECOVER OUR "NET" STRANDED COSTS IS UNCERTAIN AND MAY AFFECT OUR
FINANCIAL RESULTS.
The Customer Choice Act allows for the recovery, by an electric utility,
of the cost of implementing that Act's requirements and "net" Stranded Costs,
without defining the term. According to the MPSC, "net" Stranded Costs are to be
recovered from retail open access customers through a Stranded Cost transition
charge.
In 2002 and 2001, the MPSC issued orders finding that Consumers
experienced zero "net" Stranded Costs from 2000 to 2001. The MPSC also declined
to resolve numerous issues regarding the "net" Stranded Cost methodology in a
way that would allow a reliable prediction of the level of Stranded Costs for
future years. Consumers is currently in the process of appealing these orders
with the Michigan Court of Appeals and the Michigan Supreme Court.
In March 2003, Consumers filed an application with the MPSC seeking
approval of "net" Stranded Costs incurred in 2002 and for approval of a "net"
Stranded Cost recovery charge. In the application, Consumers' "net" Stranded
Costs incurred in 2002, including the cost of money, are estimated to be
approximately $47 million with the issuance of securitization bonds that include
Clean Air Act investments, or approximately $104 million without the issuance of
securitization bonds that include Clean Air Act investments. In July 2004, the
ALJ issued a proposal for decision in Consumers' 2002 "net" Stranded Cost case,
which recommended that the MPSC find that Consumers incurred "net" Stranded
Costs of $12 million. This recommendation includes the cost of money through
July 2004 and excludes Clean Air Act investments.
In April 2004, Consumers filed an application with the MPSC seeking
approval of "net" Stranded Costs incurred in 2003. Consumers also requested
interim relief for 2003 "net" Stranded Costs. In July 2004, Consumers revised
its request for approval of 2003 Stranded Costs incurred, including the cost of
money, to $69 million with the issuance of Securitization bonds that include
Clean Air Act investments, or $128 million without the issuance of
Securitization bonds that include Clean Air Act investments. The MPSC has
scheduled hearings for Consumers' 2003 Stranded Cost application for August
2004. In July 2004, the MPSC staff issued a position on Consumers' 2003 "net"
Stranded Cost application, which resulted in a Stranded Cost calculation of $52
million. The amount includes the cost of money, but excludes Clean Air Act
investments. We cannot predict how the MPSC will rule on Consumers' requests for
recoverability of 2002 and 2003 Stranded Costs or whether the MPSC will adopt a
Stranded Cost recovery method that will offset fully any associated margin loss
from retail open access.
We cannot predict the ability of Consumers to recover its "net" Stranded
Costs, including costs related to electric utility restructuring, and failure to
recover those "net" Stranded Costs could adversely affect our financial
condition.
WE COULD INCUR SIGNIFICANT CAPITAL EXPENDITURES TO COMPLY WITH ENVIRONMENTAL
STANDARDS AND FACE DIFFICULTY IN RECOVERING THESE COSTS ON A CURRENT BASIS.
We and our subsidiaries are subject to costly and increasingly stringent
environmental regulations. We expect that the cost of future environmental
compliance, especially compliance with clean air laws, will be significant.
In 1998, the Environmental Protection Agency ("EPA") issued regulations
requiring the State of Michigan to further limit nitrogen oxide emissions at our
coal-fired electric plants. The EPA and the State of Michigan regulations
require us to make significant capital expenditures estimated to be $771
million. As of June 30, 2004, Consumers has incurred $489 million in capital
expenditures to comply with the EPA regulations and anticipates that the
remaining $282 million of capital expenditures will be incurred between 2004 and
2009. Additionally, Consumers currently expects it will supplement its
compliance plan with the purchase of nitrogen oxide emissions credits for the
years 2004 through 2008. The cost of these credits based on the current market
is estimated to average $8 million per year; however, the market for nitrogen
oxide emissions credits and their price could change substantially. As new
environmental standards become effective, Consumers will need additional capital
expenditures to comply with the standards.
Based on the Customer Choice Act, beginning January 2004 an annual return
of and on these types of capital expenditures, to the extent they are above
depreciation levels, is expected to be recoverable from customers, subject to an
MPSC prudency hearing.
19
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants and potentially pay fines.
These and other required environmental expenditures, if not recovered from
customers in Consumers' rates, may require us to seek significant additional
financing to fund such expenditures and could strain our cash resources.
OUR PLANNED ASSET SALES MAY NOT BE ACHIEVED OR MAY RESULT IN ADDITIONAL
ACCOUNTING CHARGES.
We are executing an ongoing asset sales program encompassing the sale of
non-strategic and under-performing assets, the proceeds of which are being and
will be used primarily to reduce debt. While we have successfully sold several
of our major properties, including most recently Goldfields, Panhandle, Loy
Yang, Panhandle and CMS Field Services, Inc., there are a number of additional
assets we are targeting for disposal through 2005. We cannot assure you that we
will be successful in selling these assets, a number of which are located
outside the United States.
We are required by generally accepted accounting principles to
periodically review the carrying value of our assets, including those we are
targeting for sale. Market conditions, the operational characteristics of the
assets that may be sold and other factors could result in our recording
additional impairment charges for our assets, which could have an adverse effect
on our stockholders' equity and our access to additional financing. In addition,
we may be required to record impairment charges at the time we sell assets
depending on the sale prices we are able to secure.
WE RETAIN CONTINGENT LIABILITIES IN CONNECTION WITH OUR ASSET SALES.
The agreements we enter into for the sale of assets customarily include
provisions whereby we are required to:
- retain specified preexisting liabilities such as for taxes and
pensions;
- indemnify the buyers against specified risks, including the
inaccuracy of representations and warranties we make; and
- require payments to the buyers depending on the outcome of
post-closing adjustments, audits or other reviews.
Many of these contingent liabilities can remain open for extended periods
of time after the sales are closed. Depending on the extent to which the buyers
may ultimately seek to enforce their rights under these contractual provisions,
and the resolution of any disputes we may have concerning them, these
liabilities could have a material adverse effect on our financial condition,
liquidity and results of operations.
OUR REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO RISKS THAT ARE BEYOND OUR
CONTROL, INCLUDING BUT NOT LIMITED TO FUTURE TERRORIST ATTACKS OR RELATED ACTS
OF WAR.
The cost of repairing damage to our facilities due to storms, natural
disasters, wars, terrorist acts and other catastrophic events, in excess of
reserves established for such repairs, may adversely impact our results of
operations, financial condition and cash flows. The occurrence or risk of
occurrence of future terrorist activity and the high cost or potential
unavailability of insurance to cover such terrorist activity may impact our
results of operations and financial condition in unpredictable ways. These
actions could also result in disruptions of power and fuel markets. In addition,
our natural gas distribution system and pipelines could be directly or
indirectly harmed by future terrorist activity.
20
WE HAVE MADE SUBSTANTIAL INTERNATIONAL INVESTMENTS THAT ARE SUBJECT TO POSSIBLE
NATIONALIZATION, EXPROPRIATION OR INABILITY TO CONVERT CURRENCY.
Our investments in selected international markets in electric generating
facilities, natural gas pipelines and electric distribution systems face a
number of risks inherent in acquiring, developing and owning these types of
international facilities. Although we maintain insurance for various risk
exposures, including political risk from possible nationalization, expropriation
or inability to convert currency, we are exposed to some risks that include
local political and economic factors over which we have no control, such as
changes in foreign governmental and regulatory policies (including changes in
industrial regulation and control and changes in taxation), changing political
conditions and international monetary fluctuations. In some cases an investment
may have to be abandoned or disposed of at a loss. These factors could
significantly adversely affect the financial results of the affected subsidiary
and our financial position and results of operations.
International investments of the type we have made are subject to the risk
that they may be expropriated or that the required agreements, licenses, permits
and other approvals may be changed or terminated in violation of their terms.
These kinds of changes could result in a partial or total loss of our
investment.
The local foreign currency may be devalued, the conversion of the currency
may be restricted or prohibited or other actions, such as increases in taxes,
royalties or import duties, may be taken which adversely affect the value and
the recovery of our investment.
OUR OWNERSHIP OF A NUCLEAR GENERATING FACILITY CREATES RISK RELATING TO NUCLEAR
ENERGY.
Consumers owns the Palisades nuclear power plant and we are, therefore,
subject to the risks of nuclear generation and the storage and disposal of spent
fuel and other radioactive waste. The Nuclear Regulatory Commission ("NRC") has
broad authority under federal law to impose licensing and safety-related
requirements for the operation of nuclear generation facilities. In the event of
non-compliance, the NRC has the authority to impose fines or shut down a unit,
or both, depending upon its assessment of the severity of the situation, until
compliance is achieved. In addition, although we have no reason to anticipate a
serious nuclear incident at Consumers' plant, if an incident did occur, it could
harm our results of operations and financial condition. A major incident at a
nuclear facility anywhere in the world could cause the NRC to limit or prohibit
the operation or licensing of any domestic nuclear unit.
CONSUMERS CURRENTLY UNDERRECOVERS IN ITS RATES ITS PAYMENTS TO THE MCV
PARTNERSHIP FOR CAPACITY AND ENERGY, AND IS ALSO EXPOSED TO FUTURE CHANGES IN
THE MCV PARTNERSHIP'S FINANCIAL CONDITION THROUGH ITS EQUITY AND LESSOR
INVESTMENTS.
Consumers' power purchase agreement with the MCV Partnership ("PPA")
expires in 2025. We estimate that Consumers will incur estimated cash
underrecoveries of payments under the PPA aggregating $206 million through 2007.
For availability payments billed by the MCV Partnership after September 15,
2007, and not recovered from customers, Consumers would expect to claim a
"regulatory out" under the PPA. The effect of any such action would be to reduce
cash flow to the MCV Partnership, which could in turn have an adverse effect on
Consumers' equity and lessor interests in the MCV Facility.
Further, under the PPA, energy payments to the MCV Partnership are based
on the cost of coal burned at Consumers' coal plants and costs associated with
fuel inventory, operations and maintenance, and administrative and general
expenses associated with Consumers' coal plants. However, the MCV Partnership's
costs of producing electricity are tied, in large part, to the cost of natural
gas. Because natural gas prices have increased substantially in recent years,
while energy charge payments to the MCV Partnership have not, the MCV
Partnership's financial performance has been impacted negatively.
In February 2004, Consumers filed a RCP with the MPSC that is intended to
help conserve natural gas and thereby improve its investment in the MCV
Partnership. This plan seeks approval to:
- dispatch the MCV Facility based on natural gas market prices without
increased costs to electric customers;
21
- give Consumers a priority right to buy excess natural gas as a
result of the reduced dispatch of the MCV Facility; and
- fund $5 million annually for renewable energy sources such as wind
power projects.
The RCP would reduce the MCV Facility's annual natural gas consumption by
an estimated 30 to 40 billion cubic feet. This decrease in the quantity of
high-priced natural gas consumed by the MCV Facility would benefit Consumers'
ownership interest in the MCV Partnership. The amount of PPA capacity and fixed
energy payments recovered from retail electric customers would remain capped at
88.7 percent. Therefore, customers would not be charged for any increased power
supply costs, if they occur. Consumers and the MCV Partnership have reached an
agreement that the MCV Partnership will reimburse Consumers for any incremental
power costs incurred to replace the reduction in power dispatched from the MCV
Facility. Presently, Consumers is in settlement discussions with the parties to
the RCP filing. However, in July 2004, several qualifying facilities filed for a
stay on the RCP proceeding in the Ingham County Circuit Court after their
previous attempt to intervene on the proceeding was denied by the MPSC. On
August 11, 2004, the Judge granted the motion to stay the proceedings. We cannot
predict if or when the MPSC will approve the RCP or the outcome of the Ingham
County Circuit Court hearings.
We cannot estimate, at this time, the impact of these issues on Consumers'
future earnings or cash flow from its interest in the MCV Partnership. The
forward price of natural gas for the next 20 years and the MPSC decision in 2007
or later related to Consumers' recovery of capacity payments are the two most
significant variables in the analysis of the MCV Partnership's future financial
performance. Natural gas prices have historically been volatile and presently
there is no consensus in the marketplace on the price or range of prices of
natural gas beyond the next five years. Further, it is not presently possible
for us to predict the actions of the MPSC in 2007 or later. Even with an
approved RCP, if gas prices continue at present levels or increase, the
economics of operating the MCV Facility may be adverse enough to require
Consumers to recognize an impairment of its investment in the MCV Partnership.
For these reasons, at this time we cannot predict the impact of these issues on
Consumers' future earnings or cash flows or on the value of its equity interest
in the MCV Partnership.
CONSUMERS' ENERGY RISK MANAGEMENT STRATEGIES MAY NOT BE EFFECTIVE IN MANAGING
FUEL AND ELECTRICITY PRICING RISKS, WHICH COULD RESULT IN UNANTICIPATED
LIABILITIES TO CONSUMERS OR INCREASED VOLATILITY OF ITS EARNINGS.
Consumers is exposed to changes in market prices for natural gas, coal,
electricity and emission credits. Prices for natural gas, coal, electricity and
emission credits may fluctuate substantially over relatively short periods of
time and expose Consumers to commodity price risk. A substantial portion of
Consumers' operating expenses for its plants consists of the costs of obtaining
these commodities. Consumers manages these risks using established policies and
procedures, and it may use various contracts to manage these risks, including
swaps, options, futures and forward contracts. We cannot assure you that these
strategies will be successful in managing Consumers' pricing risk, or that they
will not result in net liabilities to Consumers as a result of future volatility
in these markets.
Natural gas prices in particular have historically been volatile. To
manage market risks associated with the volatility of natural gas prices, the
MCV Partnership maintains a gas hedging program. The MCV Partnership enters into
natural gas futures contracts, option contracts and over-the-counter swap
transactions in order to hedge against unfavorable changes in the market price
of natural gas in future months when gas is expected to be needed. These
financial instruments are being used principally to secure anticipated natural
gas requirements necessary for projected electric and steam sales, and to lock
in sales prices of natural gas previously obtained in order to optimize the MCV
Partnership's existing gas supply, storage, and transportation arrangements.
Consumers also routinely enters into contracts to offset its positions, such as
hedging exposure to the risks of demand, market effects of weather and changes
in commodity prices associated with its gas distribution business. Such
positions are taken in conjunction with the gas cost recovery mechanism, which
allows Consumers to recover prudently incurred costs associated with such
position. However, neither Consumers nor the MCV Partnership always hedges the
entire exposure of its operations from commodity price volatility. Furthermore,
the ability to hedge exposure to commodity price volatility depends on liquid
commodity markets. As a result, to the extent the commodity markets are
illiquid, Consumers may not be able to execute its risk management strategies,
which could result in greater open positions than we would prefer at a given
time. To the extent that open positions exist, fluctuating commodity prices can
improve or diminish our financial results and financial position.
22
In addition, Consumers currently has a power supply cost recovery
mechanism to recover the increased cost of fuel used to generate electricity
from its industrial and large commercial customers, but not from its residential
or small commercial customers. Therefore, to the extent that Consumers has not
hedged its fuel costs, it is exposed to changes in fuel prices to the extent
fuel for its electric generating facilities must be purchased on the open market
in order for Consumers to serve its residential and small commercial customers.
RISKS RELATED TO THE NEW NOTES
IF YOU FAIL TO EXCHANGE YOUR OLD NOTES, YOU MAY BE UNABLE TO SELL THEM.
Because we did not register the old notes under the Securities Act or any
state securities laws, and we do not intend to do so after the Exchange Offer,
the old notes may only be transferred in limited circumstances under applicable
securities laws. If the holders of the old notes do not exchange their old notes
in the Exchange Offer, they may lose their right to have their old notes
registered under the Securities Act, subject to some limitations. As a holder of
old notes after the Exchange Offer, you may be unable to sell your old notes.
WE MAY BE UNABLE TO RAISE THE FUNDS NECESSARY TO PURCHASE THE NEW NOTES UPON A
CHANGE IN CONTROL.
In the event of a Change in Control of CMS Energy, each Holder of new
notes may require us to purchase all or a portion of its new notes at a purchase
price equal to 101% of the principal amount thereof, plus accrued interest. Our
ability to purchase the new notes will be limited by the terms of our other debt
agreements and our ability to finance the purchase. It is expected that we will
issue additional debt with similar change of control provisions in the future.
If this occurs, the financial requirements for any purchases could be increased
significantly. In addition, the terms of any debt securities issued to purchase
debt under these change of control provisions may be unfavorable to us. We
cannot assure Holders of new notes that we will be able to finance these
purchase obligations or obtain consents to do so from Holders of new notes under
other debt agreements restricting these purchases.
THERE IS NO PUBLIC MARKET FOR THE NEW NOTES, SO YOU MAY BE UNABLE TO SELL THEM.
The new notes are new securities for which there is currently no market.
Consequently, the new notes will be relatively illiquid, and you may be unable
to sell them. We do not intend to apply for listing of the new notes on any
securities exchange or for the inclusion of the new notes in any automated
quotation system. Accordingly, we cannot assure you that a liquid market for the
new notes will develop.
23
USE OF PROCEEDS
The Exchange Offer is intended to satisfy our obligations under the
Registration Rights Agreement. We will not receive any cash proceeds from the
issuance of the new notes. The old notes that are surrendered in exchange for
the new notes will be retired and canceled and cannot be reissued. As a result,
the issuance of the new notes will not increase or decrease our indebtedness. We
have agreed to bear the expenses of the Exchange Offer to the extent indicated
in the Registration Rights Agreement. No underwriter is being used in connection
with the Exchange Offer. We used the net proceeds from the sale of the old notes
of approximately $288 million after deducting the offering discounts and
expenses, to discharge a portion of the $250 million tranche of the Second
Amended and Restated Senior Credit Agreement and to redeem a portion of our 6
3/4% Senior Notes Due 2004.
RATIO OF EARNINGS TO FIXED CHARGES
The ratio of earnings to fixed charges for the six months ended June 30,
2004 and each of the years ended December 31, 1999 through 2003 is as follows:
YEAR ENDED DECEMBER 31,
SIX MONTHS ENDED -----------------------
JUNE 30, 2004 2003 2002 2001 2000 1999
------------- ---- ---- ---- ---- ----
Ratio of earnings to fixed charges.................. --(1) --(2) --(3) --(4) --(5) 1.28
----------
(1) For the six months ended June 30, 2004, fixed charges exceeded earnings by
$47 million. Earnings as defined include $125 million of asset impairment
charges.
(2) For the year ended December 31, 2003, fixed charges exceeded earnings by
$59 million. Earnings as defined include $95 million of asset impairment
charges.
(3) For the year ended December 31, 2002, fixed charges exceeded earnings by
$472 million. Earnings as defined include $602 million of asset impairment
charges.
(4) For the year ended December 31, 2001, fixed charges exceeded earnings by
$392 million. Earnings as defined include $323 million of asset impairment
charges.
(5) For the year ended December 31, 2000, fixed charges exceeded earnings by
$224 million. Earnings as defined include a $329 million pretax impairment
loss on the Loy Yang investment.
For the purpose of computing the ratio, earnings represent net income
before income taxes, net interest charges and the estimated interest portion of
lease rentals and distributed income of equity method investees.
DESCRIPTION OF THE NEW NOTES
GENERAL
The new notes will be issued as a series of senior debentures under the
senior debt indenture as supplemented by the fourteenth supplemental indenture
thereto dated as of July 17, 2003 (the "SUPPLEMENTAL INDENTURE"), and will be
initially limited in aggregate principal amount to $300 million. The senior debt
indenture permits us to "re-open" this offering of the new notes without the
consent of the Holders of the new notes. Accordingly, the principal amount of
the new notes may be increased in the future on the same terms and conditions
and with the same CUSIP numbers as the new notes being offered by this
prospectus. The new notes will be unsecured and unsubordinated senior debt
securities of CMS Energy.
As of June 30, 2004 CMS Energy had outstanding approximately $2.6 billion
aggregate principal amount of indebtedness (excluding subsidiaries). None of
such indebtedness would be senior to the new notes. In August 2004, CMS Energy
entered into the Fifth Amended and Restated Credit Agreement in the amount of
approximately $300 million. This facility is secured and the new notes would not
be senior to such indebtedness. As of August 17, 2004,
24
there were approximately $164 million of letters of credit outstanding under the
Fifth Amended and Restated Credit Agreement. The new notes will be senior to
certain subordinated debentures in aggregate principal amount of approximately
$178 million, issued in connection with certain preferred securities outstanding
of subsidiary trusts. The new notes will rank equally in right of payment with
all other unsecured and unsubordinated senior indebtedness of CMS Energy
(excluding subsidiaries).
We may issue debt securities from time to time in one or more series under
the senior debt indenture. There is no limitation on the amount of debt
securities we may issue under the senior debt indenture.
The statements herein concerning the new notes and the senior debt
indenture are a summary and do not purport to be complete and are subject to,
and qualified in their entirety by, all of the provisions of the senior debt
indenture, which is incorporated herein by this reference. They make use of
defined terms and are qualified in their entirety by express reference to the
senior debt indenture, including the Supplemental Indenture, a copy of which
will be available upon request to the Trustee.
STRUCTURAL SUBORDINATION
CMS Energy is a holding company that conducts substantially all of its
operations through its subsidiaries. Its only significant assets are the capital
stock of its subsidiaries, and its subsidiaries generate substantially all of
its operating income and cash flow. As a result, dividends or advances from its
subsidiaries are the principal source of funds necessary to meet its debt
service obligations. Contractual provisions or laws, as well as its
subsidiaries' financial condition and operating requirements, may limit CMS
Energy's ability to obtain cash from its subsidiaries that it may require to pay
its debt service obligations, including payments on the new notes. In addition,
the new notes will be effectively subordinated to all of the liabilities of CMS
Energy's subsidiaries with regard to the assets and earnings of CMS Energy's
subsidiaries. The subsidiaries are separate and distinct legal entities and have
no obligation, contingent or otherwise, to pay any amounts due pursuant to the
new notes or to make any funds available therefore, whether by dividends, loans
or other payments. CMS Energy's rights and the rights of its creditors,
including Holders of new notes, to participate in the distribution of assets of
any subsidiary upon the latter's liquidation or reorganization will be subject
to prior claims of the subsidiaries' creditors, including trade creditors.
Of the approximately $7.7 billion of our consolidated indebtedness as of
June 30, 2004 approximately $5.1 billion was indebtedness of our subsidiaries
including $506 million of Consumers' mandatorily redeemable preferred
securities. Payments on that indebtedness and preferred stock of our
subsidiaries are prior in right of payment to dividends paid to us by our
subsidiaries.
PRIMARY SOURCE OF FUNDS OF CMS ENERGY; RESTRICTIONS ON SOURCES OF DIVIDENDS
The ability of CMS Energy to pay (i) dividends on its capital stock and
(ii) its indebtedness, including the new notes, depends and will depend
substantially upon timely receipt of sufficient dividends or other distributions
from its subsidiaries, in particular Consumers and Enterprises. Each of
Consumers' and Enterprises' ability to pay dividends on its common stock depends
upon its revenues, earnings and other factors. Consumers' revenues and earnings
will depend substantially upon rates authorized by the MPSC.
Consumers' Restated Articles of Incorporation ("ARTICLES") provide two
restrictions on its payment of dividends on its common stock. First, prior to
the payment of any common stock dividend, Consumers must reserve retained
earnings after giving effect to such dividend payment of at least (i) $7.50 per
share on all then outstanding shares of its preferred stock, (ii) in respect to
its Class A Preferred Stock, 7.5% of the aggregate amount established by its
Board of Directors to be payable on the shares of each series thereof in the
event of involuntary liquidation of Consumers and (iii) $7.50 per share on all
then outstanding shares of all other stock over which its preferred stock and
Class A Preferred Stock do not have preference as to the payment of dividends
and as to assets. Second, dividend payments during the 12 month period ending
with the month the proposed payment is to be paid are limited to: (i) 50% of net
income available for the payment of dividends during the base period, if the
ratio of common stock and surplus to total capitalization and surplus for 12
consecutive calendar months within the 14 calendar months immediately preceding
the proposed dividend payment (the "BASE PERIOD"), adjusted to reflect the
proposed dividend, is less than 20%; and (ii) 75% of net income available for
the payment of dividends during the base period
25
if the ratio of common stock and surplus to total capitalization and surplus for
the base period, adjusted to reflect the proposed dividend, is at least 20% but
less than 25%.
In addition, Consumers' indenture dated as of January 1, 1996, between
Consumers and The Bank of New York, as trustee (the "PREFERRED SECURITIES
INDENTURE"), and certain preferred securities guarantees by Consumers dated
January 23, 1996, September 11, 1997 and October 25, 1999 (collectively, the
"CONSUMERS PREFERRED SECURITIES GUARANTEES"), in connection with which the 8.36%
Trust Originated Preferred Securities of Consumers Power Company Financing I,
the 8.20% Trust Originated Preferred Securities of Consumers Energy Company
Financing II, the 9.25% Trust Originated Preferred Securities of Consumers
Energy Company Financing III and the 9.00% Trust Preferred Securities of
Consumers Energy Company Financing IV (collectively, the "CONSUMERS TRUST
PREFERRED SECURITIES") were issued, provide that Consumers shall not declare or
pay any dividend on, make any distributions with respect to, or redeem, purchase
or make a liquidation payment with respect to, any of its capital stock if (i)
there shall have occurred any event that would constitute an event of default
under the Preferred Securities Indenture or the trust agreements pursuant to
which the Consumers Trust Preferred Securities were issued, (ii) a default has
occurred with respect to its payment of any obligations under the Consumers
Preferred Securities Guarantees or certain Consumers common stock guarantees or
(iii) it gives notice of its election to extend the interest payment period on
the subordinated new notes issued under the Preferred Securities Indenture, at
any time for up to 20 consecutive quarters, provided, however, Consumers may
declare and pay stock dividends where the dividend stock is the same stock as
that on which the dividend is being paid.
Consumers' ability to pay dividends is also restricted by several existing
loan agreements. The loan agreements are:
- the Amended and Restated Credit Agreement dated as of August 3, 2004
among Consumers, Bank One, N.A., as agent, and the financial
institutions named therein; and
- the Term Loan Agreement dated as of November 7, 2003 among
Consumers, Bank One, N.A., as agent, and the financial institutions
named therein.
Pursuant to these loan agreements, so long as there exists no event of
default under these agreements, Consumers may pay dividends in an aggregate
amount not to exceed $300 million during any calendar year.
On June 2, 2003, the MPSC issued a financing order authorizing the
issuance of $554 million of securitization bonds. The order would prohibit
Consumers from paying any extraordinary dividends to us until further order of
the MPSC. Pursuant to the order, extraordinary dividends are considered any
amount over and above Consumers' earnings. The order also directed that the
securitization charges be designed such that retail open access customers would
pay a significantly smaller charge than would full service customers. On July 1,
2003, Consumers filed a petition for rehearing and clarification of certain
portions of the order with the MPSC, including the portion dealing with the
design of the securitization charges. In December 2003, the MPSC issued its
order on rehearing, which rejected our requests for rehearing and clarification
and remanded the proceeding to the ALJ for additional proceedings. In March
2004, the ALJ conducted the remanded hearings and the matter is presently before
the MPSC awaiting a decision.
In December 2003, the MPSC issued an order granting interim gas rate
relief in the amount of $19.34 million annually. In connection with this rate
relief, Consumers agreed to limit its dividends to CMS Energy to a maximum of
$190 million annually during the period in which Consumers receives the interim
relief. The MPSC stated in its order that it was not determining at that time
whether dividend restrictions should continue after the issuance of a final
order.
Consumers' Articles also prohibit the payment of cash dividends on its
common stock if Consumers is in arrears on preferred stock dividend payments.
In addition, Michigan law prohibits payment of a dividend if, after giving
it effect, Consumers or Enterprises would not be able to pay its debts as they
become due in the usual course of business, or its total assets would be less
than the sum of its total liabilities plus, unless the Articles permit
otherwise, the amount that would be needed, if Consumers or Enterprises were to
be dissolved at the time of the distribution, to satisfy the preferential rights
upon
26
dissolution of shareholders whose preferential rights are superior to those
receiving the distribution. Currently, it is Consumers' policy to pay annual
dividends equal to 80% of its annual consolidated net income. Consumers' Board
of Directors reserves the right to change this policy at any time.
PAYMENT AND MATURITY
The new notes will mature on August 1, 2010, and will bear interest at the
rate of 7.75% per year. At maturity, CMS Energy will pay the aggregate principal
amount of the new notes then outstanding. Each new note will bear interest from
the original date of issue, payable semiannually in arrears on February 1 and
August 1, commencing on February 1, 2005, and at maturity. Interest will be paid
to the person in whose name the new notes are registered at the close of
business on the first calendar day of the month in which the interest payment
date occurs. Interest payable on any interest payment date or on the date of
maturity will be the amount of interest accrued from and including the date of
original issuance or from and including the most recent interest payment date on
which interest has been paid or duly made available for payment to but excluding
such interest payment date or the date of maturity, as the case may be. Interest
will be computed on the basis of a 360-day year consisting of twelve 30 day
months.
The interest rate on the new notes will increase if:
- we do not file either:
- a registration statement to allow for an exchange offer; or
- a resale shelf registration statement for the new notes;
- the registration statement referred to above is not declared
effective on a timely basis; or
- other conditions summarized below are not satisfied.
You should refer to the description under the heading "The Exchange Offer"
for a more detailed description of the circumstances under which the interest
rate will increase.
In any case where any interest payment date, redemption date, repurchase
date or maturity date (including upon the occurrence of a Change in Control) of
any new note shall not be a Business Day (as defined herein) at any place of
payment, then payment of interest or principal (and premium, if any) need not be
made on such date, but may be made on the next succeeding Business Day at such
place of payment with the same force and effect as if made on the interest
payment date, redemption date, repurchase date or maturity date (including upon
the occurrence of a Change in Control); and no interest shall accrue on the
amount so payable for the period from and after such interest payment date,
redemption date, repurchase date or maturity date, as the case may be, to such
Business Day.
REGISTRATION, TRANSFER AND EXCHANGE
The new notes will be initially issued in the form of one or more new
notes in registered, global form, without coupons, in denominations of $1,000
and any integral multiple thereof as described under "Book-Entry System." The
global securities will be registered in the name of the nominee of DTC. Except
as described under "Book-Entry System," owners of beneficial interests in a
global new note will not be entitled to have new notes registered in their
names, will not receive or be entitled to receive physical delivery of any such
new notes and will not be considered the registered holder thereof under the
senior debt indenture.
OPTIONAL REDEMPTION
The new notes will be redeemable at CMS Energy's option, in whole or in
part, at any time or from time to time, at a redemption price equal to 100% of
the principal amount of such new notes being redeemed plus the Applicable
Premium (as defined below), if any, thereon at the time of redemption, together
with accrued interest, if any, thereon to the redemption date. In no event will
the redemption price be less than 100% of the principal amount of the new notes
plus accrued interest, if any, thereon to the redemption date.
27
The following definitions are used to determine the Applicable Premium:
"APPLICABLE PREMIUM" means, with respect to a new note (or portion thereof)
being redeemed at any time, the excess of (A) the present value at such time of
the principal amount of such new note (or portion thereof) being redeemed plus
all interest payments due on such new note (or portion thereof) after the
redemption date, which present value shall be computed using a discount rate
equal to the Treasury Rate plus 50 basis points, over (B) the principal amount
of such new note (or portion thereof) being redeemed at such time. For purposes
of this definition, the present values of interest and principal payments will
be determined in accordance with generally accepted principles of financial
analysis.
"TREASURY RATE" means the yield to maturity at the time of computation of United
States Treasury securities with a constant maturity (as compiled and published
in the most recent Federal Reserve Statistical Release H.15(519) (the
"STATISTICAL RELEASE")) which has become publicly available at least two
Business Days prior to the redemption date or, in case of defeasance, prior to
the date of deposit (or, if such Statistical Release is no longer published, any
publicly available source of similar market data) most nearly equal to the then
remaining average life to stated maturity of the new notes; provided, however,
that if the average life to stated maturity of the new notes is not equal to the
constant maturity of a United States Treasury security for which a weekly
average yield is given, the Treasury Rate shall be obtained by linear
interpolation (calculated to the nearest one-twelfth of a year) from the weekly
average yields of United States Treasury securities for which such yields are
given.
If the original redemption date is on or after a record date and on or
before the relevant interest payment date, the accrued and unpaid interest, if
any, will be paid to the person or entity in whose name the new note is
registered at the close of business on the record date, and no additional
interest will be payable to Holders whose new notes shall be subject to
redemption.
If less than all of the new notes are to be redeemed, the Trustee under
the senior debt indenture shall select, in such manner as it shall deem
appropriate and fair, the particular new notes or portions thereof to be
redeemed. Notice of redemption shall be given by mail not less than 30 nor more
than 60 days prior to the date fixed for redemption to the Holders of new notes
to be redeemed (which, as long as the new notes are held in the book-entry only
system, will be DTC (or its nominee) or a successor depositary); provided,
however, that the failure to duly give such notice by mail, or any defect
therein, shall not affect the validity of any proceedings for the redemption of
new notes as to which there shall have been no such failure or defect. On and
after the date fixed for redemption (unless CMS Energy shall default in the
payment of the new notes or portions thereof to be redeemed at the applicable
redemption price, together with accrued interest, if any, thereon to such date),
interest on the new notes or the portions thereof so called for redemption shall
cease to accrue.
No sinking fund is provided for the new notes.
PURCHASE OF NEW NOTES UPON CHANGE IN CONTROL
In the event of any Change in Control (as defined below) each Holder of a
new note will have the right, at such Holder's option, subject to the terms and
conditions of the senior debt indenture, to require CMS Energy to repurchase all
or any part of such Holder's new note on a date selected by CMS Energy that is
no earlier than 60 days nor later than 90 days (the "CHANGE IN CONTROL PURCHASE
DATE") after the mailing of written notice by CMS Energy of the occurrence of
such Change in Control, at a repurchase price payable in cash equal to 101% of
the principal amount of such new notes plus accrued interest, if any, thereon to
the Change in Control Purchase Date (the "CHANGE IN CONTROL PURCHASE PRICE").
Within 30 days after the Change in Control Purchase Date, CMS Energy is
obligated to mail to each Holder of a new note a notice regarding the Change in
Control, which notice shall state, among other things:
- that a Change in Control has occurred and that each such Holder has
the right to require CMS Energy to repurchase all or any part of
such Holder's new notes at the Change in Control Purchase Price;
- the Change in Control Purchase Price;
28
- the Change in Control Purchase Date;
- the name and address of the paying agent; and
- the procedures that Holders must follow to cause the new notes to be
repurchased.
To exercise this right, a Holder must deliver a written notice (the
"CHANGE IN CONTROL PURCHASE NOTICE") to the paying agent at its corporate trust
office in Detroit, Michigan, or any other office of the paying agent maintained
for such purposes, not later than 30 days prior to the Change in Control
Purchase Date. The Change in Control Purchase Notice shall state:
- the portion of the principal amount of any new notes to be
repurchased, which must be $1,000 or an integral multiple thereof;
- that such new notes are to be repurchased by CMS Energy pursuant to
the applicable change-in-control provisions of the senior debt
indenture; and
- unless the new notes are represented by one or more global
securities, the certificate numbers of the new notes to be
repurchased.
Any Change in Control Purchase Notice may be withdrawn by the Holder by a
written notice of withdrawal delivered to the paying agent not later than three
Business Days prior to the Change in Control Purchase Date. The notice of
withdrawal shall state the principal amount and, if applicable, the certificate
numbers of the new notes as to which the withdrawal notice relates and the
principal amount, if any, which remains subject to a Change in Control Purchase
Notice.
If a new note is represented by a global new note, DTC or its nominee will
be the holder of such new note and therefore will be the only entity that can
require CMS Energy to repurchase new notes upon a Change in Control. To obtain
repayment with respect to such new note upon a Change in Control, the beneficial
owner of such new note must provide to the broker or other entity through which
it holds the beneficial interest in such new note (1) the Change in Control
Purchase Notice signed by such beneficial owner, and such signature must be
guaranteed by a member firm of a registered national securities exchange or of
the National Association of Securities Dealers, Inc. ("NASD") or a commercial
bank or trust company having an office or correspondent in the United States and
(2) instructions to such broker or other entity to notify DTC of such beneficial
owner's desire to cause CMS Energy to repurchase such new notes. Such broker or
other entity will provide to the paying agent (1) a Change in Control Purchase
Notice received from such beneficial owner and (2) a certificate satisfactory to
the paying agent from such broker or other entity that it represents such
beneficial owner. Such broker or other entity will be responsible for disbursing
any payments it receives upon the repurchase of such new notes by CMS Energy.
Payment of the Change in Control Purchase Price for a new note in
registered, certificated form (a "CERTIFICATED NEW NOTE") for which a Change in
Control Purchase Notice has been delivered and not withdrawn is conditioned upon
delivery of such certificated new note (together with necessary endorsements) to
the paying agent at its office in Detroit, Michigan, or any other office of the
paying agent maintained for such purpose, at any time (whether prior to, on or
after the Change in Control Purchase Date) after the delivery of such Change in
Control Purchase Notice. Payment of the Change in Control Purchase Price for
such certificated new note will be made promptly following the later of the
Change in Control Purchase Date or the time of delivery of such certificated new
note.
If the Paying Agent holds, in accordance with the terms of the senior debt
indenture, money sufficient to pay the Change in Control Purchase Price of a new
note on the Business Day following the Change in Control Purchase Date for such
new note, then, on and after such date, interest on such new note will cease to
accrue, whether or not such new note is delivered to the Paying Agent, and all
other rights of the Holder shall terminate (other than the right to receive the
Change in Control Purchase Price upon delivery of the new note).
Under the senior debt indenture, a "CHANGE IN CONTROL" means an event or
series of events by which:
29
- CMS Energy ceases to beneficially own, directly or indirectly, at
least 80% of the total voting power of all classes of Capital Stock
then outstanding of Consumers (whether arising from issuance of
securities of CMS Energy or Consumers, any direct or indirect
transfer of securities by CMS Energy or Consumers, any merger,
consolidation, liquidation or dissolution of CMS Energy or Consumers
or otherwise); or any "person" or "group" (as such terms are used in
Sections 13(d) and 14(d) of the Exchange Act) becomes the
"beneficial owner" (as such term is used in Rules 13d-3 and 13d-5
under the Exchange Act, except that a person or group shall be
deemed to have "beneficial ownership" of all shares that such person
or group has the right to acquire, whether such right is exercisable
immediately or only after the passage of time), directly or
indirectly, of more than 35% of the Voting Stock of CMS Energy; or
- CMS Energy consolidates with or merges into another corporation or
directly or indirectly conveys, transfers or leases all or
substantially all of its assets to any person, or any corporation
consolidates with or merges into CMS Energy, in either event
pursuant to a transaction in which the outstanding Voting Stock of
CMS Energy is changed into or exchanged for cash, securities or
other property, other than any such transaction where (A) the
outstanding Voting Stock of CMS Energy is changed into or exchanged
for Voting Stock of the surviving corporation and (B) the holders of
the Voting Stock of CMS Energy immediately prior to such transaction
retain, directly or indirectly, substantially proportionate
ownership of the Voting Stock of the surviving corporation
immediately after such transaction.
The senior debt indenture requires CMS Energy to comply with the
provisions of Regulation 14E and any other tender offer rules under the Exchange
Act which may then be applicable in connection with any offer by CMS Energy to
purchase new notes at the option of Holders upon a Change in Control. The Change
in Control purchase feature of the new notes may in certain circumstances make
more difficult or discourage a takeover of CMS Energy and, thus, the removal of
incumbent management. The Change in Control purchase feature, however, is not
the result of management's knowledge of any specific effort to accumulate shares
of its common stock or to obtain control of CMS Energy by means of a merger,
tender offer, solicitation or otherwise, or part of a plan by management to
adopt a series of anti-takeover provisions. Instead, the Change in Control
purchase feature is a term contained in many similar debt offerings and the
terms of such feature result from negotiations between CMS Energy and the
initial purchasers. Management has no present intention to propose any
anti-takeover measures although it is possible that CMS Energy could decide to
do so in the future.
No new note may be repurchased by CMS Energy as a result of a Change in
Control if there has occurred and is continuing an Event of Default described
under "Events of Default" below (other than a default in the payment of the
Change in Control Purchase Price with respect to the new notes). In addition,
CMS Energy's ability to purchase new notes may be limited by its financial
resources and its inability to raise the required funds because of restrictions
on issuance of securities contained in other contractual arrangements.
CERTAIN RESTRICTIVE COVENANTS
The senior debt indenture contains the covenants described below. Certain
capitalized terms used below are defined under the heading "Certain Definitions"
below.
LIMITATION ON RESTRICTED PAYMENTS
Under the terms of the senior debt indenture, so long as any of the new
notes are outstanding and until the new notes are rated BBB-- or above (or an
equivalent rating) by S&P and one Other Rating Agency, at which time CMS Energy
will be permanently released from the provisions of this "Limitation on
Restricted Payments," CMS Energy will not, and will not permit any of its
Restricted Subsidiaries, directly or indirectly, to:
- declare or pay any dividend or make any distribution on the Capital
Stock of CMS Energy to the direct or indirect holders of its Capital
Stock (except dividends or distributions payable solely in its
Non-Convertible Capital Stock or in options, warrants or other
rights to purchase such Non-Convertible Capital Stock and except
dividends or distributions payable to CMS Energy or a Subsidiary);
- purchase, redeem or otherwise acquire or retire for value any
Capital Stock of CMS Energy; or
30
- purchase, repurchase, redeem, defease or otherwise acquire or retire
for value, prior to scheduled maturity or scheduled repayment
thereof, any Subordinated Indebtedness (any such dividend,
distribution, purchase, redemption, repurchase, defeasing, other
acquisition or retirement being hereinafter referred to as a
"RESTRICTED PAYMENT"),
if at the time CMS Energy or such Subsidiary makes such Restricted Payment: (1)
an Event of Default, or an event that with the lapse of time or the giving of
notice or both would constitute an Event of Default, shall have occurred and be
continuing (or would result therefrom); or (2) the aggregate amount of such
Restricted Payment and all other Restricted Payments made since May 6, 1997
would exceed the sum of (a) $100,000,000 plus 100% of Consolidated Net Income
from May 6, 1997 to the end of the most recent fiscal quarter ending at least 45
days prior to the date of such Restricted Payment (or, in case such sum shall be
a deficit, minus 100% of the deficit) and (b) the aggregate Net Cash Proceeds
received by CMS Energy from the issue or sale of or contribution with respect to
its Capital Stock after May 6, 1997.
The foregoing provisions will not prohibit:
- dividends or other distributions paid in respect of any class of
Capital Stock issued by CMS Energy in connection with the
acquisition of any business or assets by CMS Energy or a Restricted
Subsidiary where the dividends or other distributions with respect
to such Capital Stock are payable solely from the net earnings of
such business or assets;
- any purchase or redemption of Capital Stock of CMS Energy made by
exchange for, or out of the proceeds of the substantially concurrent
sale of, Capital Stock of CMS Energy (other than Redeemable Stock or
Exchangeable Stock);
- dividends paid within 60 days after the date of declaration thereof
if at such date of declaration such dividends would have complied
with this covenant; or
- payments pursuant to the Tax Sharing Agreement.
LIMITATION ON CERTAIN LIENS
Under the terms of the senior debt indenture, so long as any of the new
notes are outstanding, CMS Energy shall not create, incur, assume or suffer to
exist any Lien, provided, that no event of default shall have occurred and be
continuing (or result therefrom) at the time of payment of such dividend upon or
with respect to any of its property of any character, including without
limitation any shares of Capital Stock of Consumers or Enterprises, without
making effective provision whereby the new notes shall be (so long as any such
other creditor shall be so secured) equally and ratably secured. The foregoing
restrictions shall not apply to (a) Liens securing Indebtedness of CMS Energy,
provided that on the date such Liens are created, and after giving effect to
such Indebtedness, the aggregate principal amount at maturity of all the secured
Indebtedness of CMS Energy at such date shall not exceed 5% of Consolidated Net
Tangible Assets or (b) certain liens for taxes, pledges to secure workman's
compensation, other statutory obligations and Support Obligations, certain
materialman's, mechanic's and similar liens and certain purchase money liens.
LIMITATION ON ASSET SALES
Under the terms of the senior debt indenture, so long as any of the new
notes are outstanding, CMS Energy may not sell, transfer or otherwise dispose of
any property or assets of CMS Energy, including Capital Stock of any
Consolidated Subsidiary, in one transaction or a series of transactions in an
amount which exceeds $50,000,000 (an "ASSET SALE") unless CMS Energy shall (1)
apply an amount equal to such excess Net Cash Proceeds to permanently repay
Indebtedness of a Consolidated Subsidiary or Indebtedness of CMS Energy which is
pari passu with the new notes, (2) invest an equal amount not so used in clause
(1) in property or assets of related business within 24 months after the date of
the Asset Sale (the "APPLICATION PERIOD") or (3) apply such excess Net Cash
Proceeds not so used in clause (1) or (2) (the "EXCESS PROCEEDS") to make an
offer, within 30 days after the end of the Application Period, to purchase from
the Holders on a pro rata basis an aggregate principal amount of new notes on
the relevant purchase date equal to the Excess Proceeds on such date, at a
purchase price equal to 100% of the
31
principal amount of the new notes on the relevant purchase date and unpaid
interest, if any, to the purchase date. CMS Energy shall only be required to
make an offer to purchase new notes from Holders pursuant to clause (3) if the
Excess Proceeds equal or exceed $25,000,000 at any given time.
The procedures to be followed by CMS Energy in making an offer to purchase
new notes from the Holders with Excess Proceeds, and the acceptance of such
offer by the Holders, shall be the same as those set forth above in "Purchase of
new notes Upon Change in Control" with respect to a Change in Control.
LIMITATION ON CONSOLIDATION, MERGER, SALE OR CONVEYANCE
In addition to the terms of the senior debt indenture relating to
consolidations or mergers described below under "Consolidation, Merger or Sale
of Assets", so long as any of the new notes are outstanding and until the new
notes are rated BBB-- or above (or an equivalent rating) by S&P and one Other
Rating Agency, at which time CMS Energy will be permanently released from the
provisions of this "Limitation on Consolidation, Merger, Sale or Conveyance"
(but not from the provisions described below which permit a consolidation or
merger provided that the surviving corporation assumes the obligations of CMS
Energy under the new notes and the senior debt indenture and is organized and
existing under the laws of the United States, any state thereof or the District
of Columbia), CMS Energy shall not consolidate with or merge into any other
Person or sell, lease or convey the property of CMS Energy in the entirety or
substantially as an entirety, unless (1) immediately after giving effect to such
transaction the Consolidated Net Worth of the surviving entity is at least equal
to the Consolidated Net Worth of CMS Energy immediately prior to the transaction
and (2) after giving effect to such transaction, the surviving entity would be
entitled to incur at least one dollar of additional Indebtedness (other than
revolving Indebtedness to banks) pursuant to the first paragraph under
"Limitation on Consolidated Indebtedness." Notwithstanding the foregoing
provisions, such a transaction may constitute a Change in Control as described
in "Purchase of new notes Upon Change in Control" and give rise to the right of
a Holder to require CMS Energy to repurchase all or part of such Holder's Note.
LIMITATION ON CONSOLIDATED INDEBTEDNESS
Under the terms of the senior debt indenture, so long as any of the new
notes are outstanding and until the new notes are rated BBB-- or above (or an
equivalent rating) by S&P and one Other Rating Agency, at which time CMS Energy
will be permanently released from the provisions of this "Limitation on
Consolidated Indebtedness," CMS Energy will not, and will not permit any of its
Consolidated Subsidiaries to, issue, create, assume, guarantee, incur or
otherwise become liable for (collectively, for this purpose, "ISSUE"), directly
or indirectly, any Indebtedness unless the Consolidated Coverage Ratio of CMS
Energy and its Consolidated Subsidiaries for the four consecutive fiscal
quarters immediately preceding the issuance of such Indebtedness (as shown by a
pro forma consolidated income statement of CMS Energy and its Consolidated
Subsidiaries for the four most recent fiscal quarters ending at least 30 days
prior to the issuance of such Indebtedness after giving effect to (1) the
issuance of such Indebtedness and (if applicable) the application of the net
proceeds thereof to refinance other Indebtedness as if such Indebtedness was
issued at the beginning of the period, (2) the issuance and retirement of any
other Indebtedness since the first day of the period as if such Indebtedness was
issued or retired at the beginning of the period and (3) the acquisition of any
company or business acquired by CMS Energy or any Subsidiary since the first day
of the period (including giving effect to the pro forma historical earnings of
such company or business), including any acquisition which will be consummated
contemporaneously with the issuance of such Indebtedness, as if in each case
such acquisition occurred at the beginning of the period) exceeds a ratio of 1.6
to 1.0.
The foregoing limitation is subject to exceptions for:
- Indebtedness of CMS Energy to banks not to exceed $1 billion in
aggregate outstanding principal amount at any time;
- Indebtedness outstanding on the date of the Supplemental Indenture
and certain refinancings thereof;
- certain refinancings and Indebtedness of CMS Energy to a Subsidiary
or by a Subsidiary to CMS Energy;
32
- Indebtedness of a Consolidated Subsidiary issued to acquire,
develop, improve, construct or provide working capital for a gas,
oil or electric generation, exploration, production, distribution,
storage or transmission facility and related assets; provided that
such Indebtedness is without recourse to any assets of CMS Energy,
Consumers, Enterprises, CMS Generation, CMS Electric and Gas, CMS
Gas Transmission, CMS MST or any other Designated Enterprises
Subsidiary;
- Indebtedness of a Person existing at the time at which such Person
became a Subsidiary and not incurred in connection with, or in
contemplation of, such Person becoming a Subsidiary;
- Indebtedness issued by CMS Energy not to exceed $150 million in
aggregate outstanding principal amount at any time; and
- Indebtedness of a Consolidated Subsidiary in respect of rate
reduction bonds issued to recover electric restructuring transition
costs of Consumers; provided that such Indebtedness is without
recourse to the assets of Consumers.
CERTAIN DEFINITIONS
Set forth below is a summary of certain defined terms used in the senior
debt indenture. Reference is made to the senior debt indenture for a full
definition of all terms as well as any other capitalized terms used herein and
not otherwise defined.
"BUSINESS DAY" means a day on which banking institutions in New York, New York
or Detroit, Michigan are not authorized or required by law or regulation to
close.
"CAPITAL LEASE OBLIGATION" of a Person means any obligation that is required to
be classified and accounted for as a capital lease on the face of a balance
sheet of such Person prepared in accordance with generally accepted accounting
principles; the amount of such obligation shall be the capitalized amount
thereof, determined in accordance with generally accepted accounting principles;
the stated maturity thereof shall be the date of the last payment of rent or any
other amount due under such lease prior to the first date upon which such lease
may be terminated by the lessee without payment of a penalty; and such
obligation shall be deemed secured by a Lien on any property or assets to which
such lease relates.
"CAPITAL STOCK" means any and all shares, interests, rights to purchase,
warrants, options, participations or other equivalents of or interests in
(however designated) corporate stock, including any Preferred Stock or letter
stock; provided that Hybrid Preferred Securities are not considered Capital
Stock for purposes of this definition.
"CMS ELECTRIC AND GAS" means CMS Electric and Gas Company, a Michigan
corporation and wholly-owned subsidiary of Enterprises.
"CONSOLIDATED ASSETS" means, at any date of determination, the aggregate assets
of CMS Energy and its Consolidated Subsidiaries determined on a consolidated
basis in accordance with generally accepted accounting principles.
"CONSOLIDATED COVERAGE RATIO" with respect to any period means the ratio of (1)
the aggregate amount of Operating Cash Flow for such period to (2) the aggregate
amount of Consolidated Interest Expense for such period.
"CONSOLIDATED CURRENT LIABILITIES" means, for any period, the aggregate amount
of liabilities of CMS Energy and its Consolidated Subsidiaries which may
properly be classified as current liabilities (including taxes accrued as
estimated), after (1) eliminating all inter-company items between CMS Energy and
any Consolidated Subsidiary and (2) deducting all current maturities of
long-term Indebtedness, all as determined in accordance with generally accepted
accounting principles.
"CONSOLIDATED INDEBTEDNESS" means, at any date of determination, the aggregate
Indebtedness of CMS Energy and its Consolidated Subsidiaries determined on a
consolidated basis in accordance with generally accepted accounting
33
principles; provided that Consolidated Indebtedness shall not include any
subordinated debt owned by any Hybrid Preferred Securities Subsidiary.
"CONSOLIDATED INTEREST EXPENSE" means, for any period, the total interest
expense in respect of Consolidated Indebtedness of CMS Energy and its
Consolidated Subsidiaries, including, without duplication:
- interest expense attributable to capital leases;
- amortization of debt discount;
- capitalized interest;
- cash and noncash interest payments;
- commissions, discounts and other fees and charges owed with respect
to letters of credit and bankers' acceptance financing;
- net costs under interest rate protection agreements (including
amortization of discount); and
- interest expense in respect of obligations of other Persons deemed
to be Indebtedness of CMS Energy or any Consolidated Subsidiaries
under the fifth or sixth bullet points of the definition of
Indebtedness;
provided, however, that Consolidated Interest Expense shall exclude (a) any
costs otherwise included in interest expense recognized on early retirement of
debt and (b) any interest expense in respect of any Indebtedness of any
Subsidiary of Consumers, CMS Generation, CMS Electric and Gas, CMS Gas
Transmission, CMS MST or any other Designated Enterprises Subsidiary, provided
that such Indebtedness is without recourse to any assets of CMS Energy,
Consumers, Enterprises, CMS Generation, CMS Electric and Gas, CMS Gas
Transmission, CMS MST or any other Designated Enterprises Subsidiary.
"CONSOLIDATED NET INCOME" means, for any period, the net income of CMS Energy
and its Consolidated Subsidiaries determined on a consolidated basis in
accordance with generally accepted accounting principles; provided, however,
that there shall not be included in such Consolidated Net Income:
- any net income of any Person if such Person is not a Subsidiary,
except that (A) CMS Energy's equity in the net income of any such
Person for such period shall be included in such Consolidated Net
Income up to the aggregate amount of cash actually distributed by
such Person during such period to CMS Energy or a Consolidated
Subsidiary as a dividend or other distribution and (B) CMS Energy's
equity in a net loss of any such Person for such period shall be
included in determining such Consolidated Net Income;
- any net income of any Person acquired by CMS Energy or a Subsidiary
in a pooling of interests transaction for any period prior to the
date of such acquisition;
- any gain or loss realized upon the sale or other disposition of any
property, plant or equipment of CMS Energy or its Consolidated
Subsidiaries which is not sold or otherwise disposed of in the
ordinary course of business and any gain or loss realized upon the
sale or other disposition of any Capital Stock of any Person; and
- any net income of any Subsidiary of Consumers, CMS Generation, CMS
Electric and Gas, CMS Gas Transmission, CMS MST or any other
Designated Enterprises Subsidiary whose interest expense is excluded
from Consolidated Interest Expense, provided, however, that for
purposes of this bullet point, any cash, dividends or distributions
of any such Subsidiary to CMS Energy shall be included in
calculating Consolidated Net Income.
"CONSOLIDATED NET TANGIBLE ASSETS" means, for any period, the total amount of
assets (less accumulated depreciation or amortization, allowances for doubtful
receivables, other applicable reserves and other properly deductible items) as
set forth on the most recently available quarterly or annual consolidated
balance sheet of CMS
34
Energy and its Consolidated Subsidiaries, determined on a consolidated basis in
accordance with generally accepted accounting principles, and after giving
effect to purchase accounting and after deducting therefrom, to the extent
otherwise included, the amounts of:
- Consolidated Current Liabilities;
- minority interests in Consolidated Subsidiaries held by Persons
other than CMS Energy or a Restricted Subsidiary;
- excess of cost over fair value of assets of businesses acquired, as
determined in good faith by the Board of Directors as evidenced by
Board resolutions;
- any revaluation or other write-up in value of assets subsequent to
December 31, 1996, as a result of a change in the method of
valuation in accordance with generally accepted accounting
principles;
- unamortized debt discount and expenses and other unamortized
deferred charges, goodwill, patents, trademarks, service marks,
trade names, copyrights, licenses organization or developmental
expenses and other intangible items;
- treasury stock; and
- any cash set apart and held in a sinking or other analogous fund
established for the purpose of redemption or other retirement of
Capital Stock to the extent such obligation is not reflected in
Consolidated Current Liabilities.
"CONSOLIDATED NET WORTH" of any Person means the total of the amounts shown on
the consolidated balance sheet of such Person and its consolidated subsidiaries,
determined on a consolidated basis in accordance with generally accepted
accounting principles, as of any date selected by such Person not more than 90
days prior to the taking of any action for the purpose of which the
determination is being made (and adjusted for any material events since such
date), as (1) the par or stated value of all outstanding Capital Stock plus (2)
paid-in capital or capital surplus relating to such Capital Stock plus (3) any
retained earnings or earned surplus less (A) any accumulated deficit, (B) any
amounts attributable to Redeemable Stock and (C) any amounts attributable to
Exchangeable Stock.
"CONSOLIDATED SUBSIDIARY" means any Subsidiary whose accounts are or are
required to be consolidated with the accounts of CMS Energy in accordance with
generally accepted accounting principles.
"DESIGNATED ENTERPRISES SUBSIDIARY" means any wholly-owned subsidiary of
Enterprises formed after the date of the Supplemental Indenture which is
designated a Designated Enterprises Subsidiary by the Board of Directors.
"EXCHANGEABLE STOCK" means any Capital Stock of a corporation that is
exchangeable or convertible into another security (other than Capital Stock of
such corporation that is neither Exchangeable Stock nor Redeemable Stock).
"HOLDER" OR "HOLDER" means the Person in whose name a new or old note, as the
case may be, is registered in the security register kept by CMS Energy for that
purpose.
"HYBRID PREFERRED SECURITIES" means any preferred securities issued by a Hybrid
Preferred Securities Subsidiary, where such preferred securities have the
following characteristics:
- such Hybrid Preferred Securities Subsidiary lends substantially all
of the proceeds from the issuance of such preferred securities to
CMS Energy or Consumers in exchange for subordinated debt issued by
CMS Energy or Consumers, respectively;
- such preferred securities contain terms providing for the deferral
of distributions corresponding to provisions providing for the
deferral of interest payments on such subordinated debt; and
35
- CMS Energy or Consumers (as the case may be) makes periodic interest
payments on such subordinated debt, which interest payments are in
turn used by the Hybrid Preferred Securities Subsidiary to make
corresponding payments to the holders of the Hybrid Preferred
Securities.
"HYBRID PREFERRED SECURITIES SUBSIDIARY" means any business trust (or similar
entity):
- all of the common equity interest of which is owned (either directly
or indirectly through one or more wholly-owned Subsidiaries of CMS
Energy or Consumers) at all times by CMS Energy or Consumers;
- that has been formed for the purpose of issuing Hybrid Preferred
Securities; and
- substantially all of the assets of which consist at all times solely
of subordinated debt issued by CMS Energy or Consumers (as the case
may be) and payments made from time to time on such subordinated
debt.
"INDEBTEDNESS" of any Person means, without duplication:
- the principal of and premium (if any) in respect of (A) indebtedness
of such Person for money borrowed and (B) indebtedness evidenced by
new notes, debentures, bonds or other similar instruments for the
payment of which such Person is responsible or liable;
- all Capital Lease Obligations of such Person;
- all obligations of such Person issued or assumed as the deferred
purchase price of property, all conditional sale obligations and all
obligations under any title retention agreement (but excluding trade
accounts payable arising in the ordinary course of business);
- all obligations of such Person for the reimbursement of any obligor
on any letter of credit, bankers' acceptance or similar credit
transaction (other than obligations with respect to letters of
credit securing obligations (other than obligations described in the
bullet points above) entered into in the ordinary course of business
of such Person to the extent such letters of credit are not drawn
upon or, if and to the extent drawn upon, such drawing is reimbursed
no later than the third Business Day following receipt by such
Person of a demand for reimbursement following payment on the letter
of credit);
- all obligations of the type referred to in the bullet points above
of other Persons and all dividends of other Persons for the payment
of which, in either case, such Person is responsible or liable as
obligor, guarantor or otherwise; and
- all obligations of the type referred to in the bullet points above
of other Persons secured by any Lien on any property or asset of
such Person (whether or not such obligation is assumed by such
Person), the amount of such obligation being deemed to be the lesser
of the value of such property or assets or the amount of the
obligation so secured.
"LIEN" means any lien, mortgage, pledge, security interest, conditional sale,
title retention agreement or other charge or encumbrance of any kind.
"NET CASH PROCEEDS" means (a) with respect to any Asset Sale, the aggregate
proceeds of such Asset Sale including the fair market value (as determined by
the Board of Directors and net of any associated debt and of any consideration
other than Capital Stock received in return) of property other than cash,
received by CMS Energy, net of (1) brokerage commissions and other fees and
expenses (including fees and expenses of counsel and investment bankers) related
to such Asset Sale, (2) provisions for all taxes (whether or not such taxes will
actually be paid or are payable) as a result of such Asset Sale without regard
to the consolidated results of operations of CMS Energy and its Restricted
Subsidiaries, taken as a whole, (3) payments made to repay Indebtedness or any
other obligation outstanding at the time of such Asset Sale that either (A) is
secured by a Lien on the property or assets sold or (B) is required to be paid
as a result of such sale and (4) appropriate amounts to be provided by CMS
Energy or any Restricted Subsidiary of CMS Energy as a reserve against any
liabilities associated with such Asset Sale, including, without limitation,
pension and other post-employment benefit liabilities, liabilities related to
environmental matters
36
and liabilities under any indemnification obligations associated with such Asset
Sale, all as determined in conformity with generally accepted accounting
principles and (b) with respect to any issuance or sale or contribution in
respect of Capital Stock, the aggregate proceeds of such issuance, sale or
contribution, including the fair market value (as determined by the Board of
Directors and net of any associated debt and of any consideration other than
Capital Stock received in return) of property other than cash, received by CMS
Energy, net of attorneys' fees, accountants' fees, underwriters' or placement
agents' fees, discounts or commissions and brokerage, consultant and other fees
incurred in connection with such issuance or sale and net of taxes paid or
payable as a result thereof, provided, however, that if such fair market value
as determined by the Board of Directors of property other than cash is greater
than $25 million, the value thereof shall be based upon an opinion from an
independent nationally recognized firm experienced in the appraisal or similar
review of similar types of transactions.
"NON-CONVERTIBLE CAPITAL STOCK" means, with respect to any corporation, any
non-convertible Capital Stock of such corporation and any Capital Stock of such
corporation convertible solely into non-convertible Capital Stock other than
Preferred Stock of such corporation; provided, however, that Non-Convertible
Capital Stock shall not include any Redeemable Stock or Exchangeable Stock.
"OPERATING CASH FLOW" means, for any period, with respect to CMS Energy and its
Consolidated Subsidiaries, the aggregate amount of Consolidated Net Income after
adding thereto Consolidated Interest Expense (adjusted to include costs
recognized on early retirement of debt), income taxes, depreciation expense,
amortization expense and any noncash amortization of debt issuance costs, any
nonrecurring, noncash charges to earnings and any negative accretion
recognition.
"OTHER RATING AGENCY" shall mean any one of Fitch, Inc. or Moody's Investors
Service, Inc., and any successor to any of these organizations that is a
nationally recognized statistical rating organization.
"PAYING AGENT" means any person authorized by CMS Energy to pay the principal of
(and premium, if any) or interest on any of the new notes on behalf of CMS
Energy. Initially, the paying agent is the Trustee under the senior debt
indenture.
"PERSON" means any individual, corporation, partnership, joint venture,
association, joint-stock company, trust, unincorporated organization or
government or any agency or political subdivision of any government.
"PREFERRED STOCK" as applied to the Capital Stock of any corporation means
Capital Stock of any class or classes (however designated) that is preferred as
to the payment of dividends, or as to the distribution of assets upon any
voluntary or involuntary liquidation or dissolution of such corporation, over
shares of Capital Stock of any other class of such corporation; provided that
Hybrid Preferred Securities are not considered Preferred Stock for purposes of
this definition.
"REDEEMABLE STOCK" means any Capital Stock that by its terms or otherwise is
required to be redeemed prior to the first anniversary of the stated maturity of
the outstanding new notes or is redeemable at the option of the Holders thereof
at any time prior to the first anniversary of the stated maturity of the
outstanding new notes.
"RESTRICTED SUBSIDIARY" means any Subsidiary (other than Consumers and its
subsidiaries) of CMS Energy which, as of the date of CMS Energy's most recent
quarterly consolidated balance sheet, constituted at least 10% of the total
Consolidated Assets of CMS Energy and its Consolidated Subsidiaries and any
other Subsidiary which from time to time is designated a Restricted Subsidiary
by the Board of Directors, provided that no Subsidiary may be designated a
Restricted Subsidiary if, immediately after giving effect thereto, an Event of
Default or event that, with the lapse of time or giving of notice or both, would
constitute an Event of Default would exist or CMS Energy and its Restricted
Subsidiaries could not incur at least one dollar of additional Indebtedness
pursuant to the first paragraph under "Description of the new notes --
Limitation on Consolidated Indebtedness," and (1) any such Subsidiary so
designated as a Restricted Subsidiary must be organized under the laws of the
United States or any State thereof, (2) more than 80% of the Voting Stock of
such Subsidiary must be owned of record and beneficially by CMS Energy or a
Restricted Subsidiary and (3) such Restricted Subsidiary must be a Consolidated
Subsidiary.
"S&P" shall mean Standard & Poor's Ratings Group, a division of The McGraw-Hill
Companies, Inc., and any successor thereto which is a nationally recognized
statistical rating organization, or if such entity shall cease to rate
37
the new notes or shall cease to exist and there shall be no such successor
thereto, any other nationally recognized statistical rating organization
selected by CMS Energy which is acceptable to the Trustee.
"SUBORDINATED INDEBTEDNESS" means any Indebtedness of CMS Energy (whether
outstanding on the date of the Supplemental Indenture or thereafter incurred),
which is contractually subordinated or junior in right of payment to the new
notes.
"SUBSIDIARY" means a corporation more than 50% of the outstanding voting stock
of which is owned, directly or indirectly, by CMS Energy or by one or more other
Subsidiaries, or by CMS Energy and one or more other Subsidiaries. For the
purposes of this definition, "voting stock" means stock which ordinarily has
voting power for the election of directors, whether at all times or only so long
as no senior class of stock has such voting power by reason of any contingency.
"SUPPORT OBLIGATIONS" means, for any person, without duplication, any financial
obligation, contingent or otherwise, of such person guaranteeing or otherwise
supporting any debt or other obligation of any other person in any manner,
whether directly or indirectly, and including, without limitation, any
obligation of such person, direct or indirect:
- to purchase or pay (or advance or supply funds for the purchase or
payment of) such debt or to purchase (or to advance or supply funds
for the purchase of) any security for the payment of such debt;
- to purchase property, securities or services for the purpose of
assuring the owner of such debt of the payment of such debt;
- to maintain working capital, equity capital, available cash or other
financial statement condition of the primary obligor so as to enable
the primary obligor to pay such debt;
- to provide equity capital under or in respect of equity subscription
arrangements (to the extent that such obligation to provide equity
capital does not otherwise constitute debt); or
- to perform, or arrange for the performance of, any non-monetary
obligations or non-funded debt payment obligations of the primary
obligor.
"TAX SHARING AGREEMENT" means the Amended and Restated Agreement for the
Allocation of Income Tax Liabilities and Benefits, dated January 1, 1994, as
amended or supplemented from time to time, by and among CMS Energy, each of the
members of the Consolidated Group (as defined therein), and each of the
corporations that become members of the Consolidated Group.
"VOTING STOCK" means securities of any class or classes the holders of which are
ordinarily, in the absence of contingencies, entitled to vote for corporate
directors (or persons performing similar functions).
EVENTS OF DEFAULT
The occurrence of any of the following events with respect to the new notes
will constitute an "EVENT OF DEFAULT" with respect to the new notes:
- default for 30 days in the payment of any interest on any of the new
notes;
- default in the payment when due of any of the principal of or the
premium, if any, on any of the new notes, whether at maturity, upon
redemption, acceleration, purchase by CMS Energy at the option of
the Holders or otherwise;
- default for 60 days by CMS Energy in the observance or performance
of any other covenant or agreement contained in the senior debt
indenture relating to the new notes after written notice thereof as
provided in the senior debt indenture;
38
- certain events of bankruptcy, insolvency or reorganization relating
to CMS Energy or Consumers;
- entry of final judgments against CMS Energy or Consumers aggregating
in excess of $25,000,000 which remain undischarged or unbonded for
60 days;
- a default resulting in the acceleration of indebtedness of CMS
Energy or Consumers in excess of $25,000,000, which acceleration has
not been rescinded or annulled within ten days after written notice
of such default as provided in the senior debt indenture;
- a default in our obligation to redeem new notes after we exercised
our redemption option; or
- a default in our obligation to purchase new notes upon the
occurrence of a Change in Control or exercise by a Holder of its
option to require us to purchase such Holder's new notes.
If an Event of Default on the new notes shall have occurred and be
continuing, either the Trustee or the Holders of not less than 25% in aggregate
principal amount of the new notes then outstanding may declare the principal of
all the new notes and the premium thereon and interest, if any, accrued thereon
to be due and payable immediately.
The senior debt indenture provides that the Trustee will be under no
obligation to exercise any of its rights or powers under the senior debt
indenture at the request, order or direction of the Holders of the new notes,
unless such Holders shall have offered to the Trustee reasonable indemnity.
Subject to such provisions for indemnity and certain other limitations contained
in the senior debt indenture, the Holders of a majority in aggregate principal
amount of the senior debentures of each affected series then outstanding (voting
as one class) will have the right to direct the time, method and place of
conducting any proceeding for any remedy available to the trustee, or exercising
any trust or power conferred on the Trustee, with respect to the senior
debentures of such affected series.
The senior debt indenture provides that no Holders of new notes may
institute any action against CMS Energy under the senior debt indenture (except
actions for payment of overdue principal, premium or interest) unless such
Holder previously shall have given to the Trustee written notice of default and
continuance thereof and unless the Holders of not less than 25% in aggregate
principal amount of senior debentures of the affected series then outstanding
(voting as one class) shall have requested the Trustee to institute such action
and shall have offered the Trustee reasonable indemnity, the Trustee shall not
have instituted such action within 60 days of such request and the Trustee shall
not have received direction inconsistent with such request by the Holders of a
majority in aggregate principal amount of the senior debentures of the affected
series then outstanding (voting as one class).
The senior debt indenture requires CMS Energy to furnish to the Trustee
annually a statement as to CMS Energy's compliance with all conditions and
covenants under the senior debt indenture. The senior debt indenture provides
that the Trustee may withhold notice to the Holders of the new notes of any
default affecting such new notes (except defaults as to payment of principal,
premium or interest on the new notes) if it considers such withholding to be in
the interests of the Holders of the new notes.
CONSOLIDATION, MERGER OR SALE OF ASSETS
The senior debt indenture provides that CMS Energy may consolidate with or
merge into, or sell, lease or convey its property as an entirety or
substantially as an entirety to, any other corporation if the new corporation
assumes the obligations of CMS Energy under the new notes and the Supplemental
Indenture and is organized and existing under the laws of the United States, any
U.S. State or the District of Columbia. Notwithstanding the foregoing
provisions, such a transaction may constitute a Change in Control as described
in "Purchase of New Notes Upon Change in Control".
MODIFICATION AND WAIVER
CMS Energy and the relevant trustee may enter into supplemental indentures
without the consent of the Holders of the new notes to establish the form and
terms of any series of securities under the senior debt indenture.
39
CMS Energy and the relevant trustee, with the consent of the Holders of at
least a majority in total principal amount of senior debentures of all series
then outstanding and affected (voting as one class), to change in any manner the
provisions of the senior debt indenture or modify in any manner the rights of
the holders of the senior debentures of each such affected series. CMS Energy
and the relevant trustee may not, without the consent of the holders of each
senior debenture affected, enter into any supplemental indenture to:
- change the time of payment of the principal;
- reduce the principal amount of such senior debenture;
- reduce the rate or change the time of payment of interest on such
senior debenture;
- reduce the amount payable on any securities issued originally at a
discount upon acceleration or provable in bankruptcy;
- impair the right to institute suit for the enforcement of any
payment on any senior debenture when due;
- reduce the redemption price or Change in Control Purchase Price for
the new notes or change the terms applicable to redemption or
purchase in a manner adverse to the Holder;
- make any change that adversely affects the right to exchange any
debt security, including the new notes, or decreases the exchange
rate of any exchangeable debt security; or
- waive any default in any payment of redemption price or Change in
Control Purchase Price with respect to the new notes.
In addition, no such modification may reduce the percentage in principal
amount of the senior debenture of the affected series, the consent of whose
holders is required for any such modification or for any waiver provided for in
the senior debt indenture.
Prior to the acceleration of the maturity of any senior debenture, the
holders, voting as one class, of a majority in total principal amount of the
senior debentures with respect to which a default or event of default shall have
occurred and be continuing may on behalf of the holders of all such affected
senior debentures waive any past default or event of default and its
consequences, except a default or an event of default in respect of a covenant
or provision of the senior debt indenture or of any senior debenture which
cannot be modified or amended without the consent of the holders of each senior
debenture affected.
DEFEASANCE, COVENANT DEFEASANCE AND DISCHARGE
The senior debt indenture provides that, at the option of CMS Energy:
- CMS Energy will be discharged from all obligations in respect of the
new notes (except for certain obligations to register the transfer
of or exchange of the new notes, to replace stolen, lost or
mutilated new notes, to maintain paying agencies and to maintain the
trust described below); or
- CMS Energy need not comply with certain restrictive covenants of the
senior debt indenture (including those described under
"Consolidation, Merger or Sale of Assets"),
if CMS Energy in each case irrevocably deposits in trust with the relevant
trustee money and/or securities backed by the full faith and credit of the
United States which, through the payment of the principal thereof and the
interest thereon in accordance with their terms, will provide money in an amount
sufficient to pay all the principal and interest on the new notes on the stated
maturities of such new notes in accordance with the terms thereof.
To exercise this option, CMS Energy is required to deliver to the relevant
trustee an opinion of independent counsel to the effect that:
40
- the exercise of such option would not cause the Holders of the new
notes to recognize income, gain or loss for United States federal
income tax purposes as a result of such defeasance, and such Holders
will be subject to United States federal income tax on the same
amounts, in the same manner and at the same times as would have been
the case if such defeasance had not occurred; and
- in the case of a discharge as described above, such opinion is to be
accompanied by a private letter ruling to the same effect received
from the Internal Revenue Service, a revenue ruling to such effect
pertaining to a comparable form of transaction published by the
Internal Revenue Service or appropriate evidence that since the date
of the senior debt indenture there has been a change in the
applicable federal income tax law.
In the event:
- CMS Energy exercises its option to effect a covenant defeasance with
respect to the new notes as described above;
- the new notes are thereafter declared due and payable because of the
occurrence of any event of default other than an event of default
caused by failing to comply with the covenants which are defeased;
or
- the amount of money and securities on deposit with the relevant
trustee would be insufficient to pay amounts due on the new notes at
the time of the acceleration resulting from such event of default,
CMS Energy would remain liable for such amounts.
THE TRUSTEE
J.P. Morgan Trust Company, N.A. (the "TRUSTEE") is the Trustee and paying
agent under the senior debt indenture for the new notes. CMS Energy and its
affiliates maintain lending depositary and other normal banking relationship
with J.P. Morgan Trust Company, N.A. J.P. Morgan Trust Company, N.A. is also a
lender to CMS Energy and its affiliates.
GOVERNING LAW
The senior debt indenture, the Supplemental Indenture and the new notes
will be governed by, and construed in accordance with, the laws of the State of
Michigan unless the laws of another jurisdiction shall mandatorily apply.
BOOK-ENTRY SYSTEM
The new notes will be represented by one or more global securities. Each
global security will be deposited with, or on behalf of, DTC and be registered
in the name of a nominee of DTC. Except under circumstances described below, the
new notes will not be issued in definitive form.
The following is based upon information furnished by DTC:
DTC is a limited-purpose trust company organized under the New York
Banking Law, a "banking organization" within the meaning of the New York Banking
Law, a member of the Federal Reserve System, a "clearing corporation" within the
meaning of the New York Uniform Commercial Code, and a "clearing agency"
registered pursuant to the provisions of Section 17A of the Exchange Act. DTC
holds securities that its participants ("PARTICIPANTS") deposit with DTC. DTC
also facilitates the settlement among participants of securities transactions,
such as transfers and pledges, in deposited securities through electronic
computerized book-entry changes in participants' accounts, thereby eliminating
the need for physical movement of securities certificates. Direct participants
("DIRECT PARTICIPANTS") include securities brokers and dealers, banks, trust
companies, clearing corporations, and certain other organizations. DTC is owned
by a number of its direct participants and by the New York Stock Exchange, Inc.,
the American Stock Exchange, Inc., and the National Association of Securities
Dealers, Inc. Access to the DTC system is also available to others such as
securities brokers and dealers, banks and trust companies that clear through or
maintain a custodial relationship with a direct participant, either directly or
indirectly. The rules applicable to DTC and its participants are on file with
the SEC.
41
Investors who purchase new notes in offshore transactions in reliance on
Regulation S under the Securities Act may hold their interest in a global
security directly through Euroclear Bank S.A./N.V., as operator of the Euroclear
System ("EUROCLEAR"), and Clearstream Banking, societe anonyme ("CLEARSTREAM"),
if they are participants in such systems, or indirectly through organizations
that are participants in such systems. Euroclear and Clearstream will hold
interests in the global securities on behalf of their participants through their
respective depositaries, which in turn will hold such interests in the global
securities in customers' securities accounts in the depositaries' names on the
books of DTC.
Upon the issuance of a global security, DTC will credit on its book-entry
registration and transfer system the accounts of persons designated by the
initial purchaser with the respective principal amounts of the new notes
represented by the global security. Ownership of beneficial interests in a
global security will be limited to participants or persons that may hold
interests through participants. Ownership of beneficial interests in a global
security will be shown on, and the transfer of that ownership will be effected
only through, records maintained by DTC or its nominee (with respect to
interests of persons other than participants). The laws of some states require
that some purchasers of securities take physical delivery of the securities in
definitive form. Such limits and such laws may impair the ability to transfer
beneficial interests in a global security.
So long as DTC or its nominee is the registered owner of a global
security, DTC or its nominee, as the case may be, will be considered the sole
owner or Holder of the new notes represented by that global security for all
purposes under the senior debt indenture. Except as provided below, owners of
beneficial interests in a global security will not be entitled to have new notes
represented by that global security registered in their names, will not receive
or be entitled to receive physical delivery of new notes in definitive form and
will not be considered the owners or Holders thereof under the senior debt
indenture. Principal and interest payments, if any, on new notes registered in
the name of DTC or its nominee will be made to DTC or its nominee, as the case
may be, as the registered owner of the relevant global security. Neither we, the
Trustee, any paying agent or the security registrar for the new notes will have
any responsibility or liability for any aspect of the records relating to nor
payments made on account of beneficial interests in a global security or for
maintaining, supervising or reviewing any records relating to such beneficial
interests.
We expect that DTC or its nominee, upon receipt of any payment of
principal or interest, will credit immediately participants' accounts with
payments in amounts proportionate to their respective beneficial interests in
the principal amount of the relevant global security as shown on the records of
DTC or its nominee. We also expect that payments by participants to owners of
beneficial interests in a global security held through these participants will
be governed by standing instructions and customary practices, as is the case
with securities held for the accounts of customers in bearer form or registered
in "street name," and will be the responsibility of the participants.
Unless and until they are exchanged in whole or in part for new notes in
definitive form, the global securities may not be transferred except as a whole
by DTC to a nominee of DTC or by a nominee of DTC to DTC or another nominee of
DTC. Transfers between participants in DTC will be effected in the ordinary way
in accordance with DTC rules and will be settled in same-day funds. Transfers
between participants in Euroclear and Clearstream will be effected in the
ordinary way in accordance with their respective rules and operating procedures.
Cross-market transfers between DTC, on the one hand, and directly or
indirectly through Euroclear or Clearstream participants, on the other, will be
effected in DTC in accordance with DTC rules on behalf of Euroclear or
Clearstream, as the case may be, by its respective depositary; however, such
cross-market transactions will require delivery of instructions to Euroclear or
Clearstream, as the case may be, by the counterparty in such system in
accordance with its rules and procedures and within its established deadlines
(Brussels time). Euroclear or Clearstream, as the case may be, will, if the
transaction meets its settlement requirements, deliver instructions to its
respective depositary to take action to effect final settlement on its behalf by
delivering or receiving interests in the global securities in DTC, and making or
receiving payment in accordance with normal procedures for same-day funds
settlement applicable to DTC. Euroclear participants and Clearstream
participants may not deliver instructions directly to the depositaries for
Euroclear or Clearstream.
Because of time zone differences, the securities account of a Euroclear or
Clearstream participant purchasing an interest in the global securities from a
DTC participant will be credited during the securities settlement processing
42
day (which must be a business day for Euroclear or Clearstream, as the case may
be) immediately following the DTC settlement date, and such credit of any
transactions interests in the global securities settled during such processing
day will be reported to the relevant Euroclear or Clearstream participant on
such day. Cash received by Euroclear or Clearstream as a result of sales of
interests in the global securities by or through a Euroclear or Clearstream
participant to a DTC participant will be received with value on the DTC
settlement date, but will be available in the relevant Euroclear or Clearstream
cash account only as of the business day following settlement in DTC.
If DTC at any time is unwilling or unable to continue as a depositary,
defaults in the performance of its duties as depositary or ceases to be a
clearing agency registered under the Exchange Act or other applicable statute or
regulation, and a successor depositary is not appointed by us within 90 days, we
will issue new notes in definitive form in exchange for the global securities
relating to the new notes. In addition, we may at any time and in our sole
discretion determine not to have the new notes or portions of the new notes
represented by one or more global securities and, in that event, will issue
individual new notes in exchange for the global security or securities
representing the new notes. Further, if we so specify with respect to any new
notes, an owner of a beneficial interest in a global security representing the
new notes may, on terms acceptable to us and the depositary for the global
security, receive individual new notes in exchange for the beneficial interest.
In any such instance, an owner of a beneficial interest in a global security
will be entitled to physical delivery in definitive form of new notes
represented by the global security equal in principal amount to the beneficial
interest, and to have the new notes registered in its name. new notes so issued
in definitive form will be issued as registered new notes in denominations of
$1,000 and integral multiples thereof, unless otherwise specified by us.
LISTING
The new notes will be eligible to be traded on the Portal Market of the
National Association of Securities Dealers, Inc. at the time of issuance.
RATINGS
S&P has assigned each series of old notes a rating of B+, Moody's has
assigned each series of old notes a rating of B3 and Fitch has assigned each
series of old notes a rating of B+. The terms of the new notes will be identical
in all material respects to the terms of the old notes, except that the
registration rights and related liquidated damages provisions and the transfer
restrictions applicable to the old notes will not be applicable to the new
notes. The new notes will have the same financial terms and covenants as the old
notes, and will be subject to the same business and financial risks. The ratings
mentioned above reflect only the views of such ratings agencies, and do not
constitute a recommendation to buy, sell or hold securities. In general, ratings
address credit risk. Each rating should be evaluated independently of any other
rating. An explanation of the significance of such ratings may be obtained only
from such rating agencies at the following addresses: Standard & Poor's, 25
Broadway, New York, New York 10004; Moody's Investors Service, Inc., 99 Church
Street, New York, New York 10007; and Fitch, Inc., 1 State Street Plaza, New
York, New York 10004. The security rating may be subject to revision or
withdrawal at any time by the assigning rating organization, and, accordingly,
there can be no assurance that such ratings will remain in effect for any period
of time or that they will not be revised downward or withdrawn entirely by the
rating agencies if, in their judgment, circumstances warrant. Neither CMS nor
the Initial Purchasers have undertaken any responsibility to oppose any proposed
downward revision or withdrawal of a rating on the old notes. Any such downward
revision or withdrawal of such ratings may have an adverse effect on the market
price of the new notes.
THE EXCHANGE OFFER
PURPOSE OF THE EXCHANGE OFFER
We initially sold the old notes in a private offering to Citigroup Global
Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Deutsche
Bank Securities Inc. (the "INITIAL PURCHASERS") pursuant to a purchase agreement
between us and them. The Initial Purchasers resold the old notes to qualified
institutional buyers in reliance on, and subject to the restrictions imposed
under, Rule 144A under the Securities Act. As of the date of this prospectus,
$300 million of the old notes are outstanding.
43
EXCHANGE OFFER REGISTRATION
In connection with the private offering of the old notes, we entered into
a registration rights agreement with the Initial Purchasers pursuant to which we
agreed, for the benefit of the Holders of the old notes, at our cost to:
- within 240 days following the original issue date of the old notes,
prepare and file with the SEC an Exchange Offer registration
statement with respect to a proposed Exchange Offer and the issuance
and delivery to the Holders, in exchange for the old notes of new
notes, which will have terms identical in all material respects to
the old notes, except that the new notes will not contain terms with
respect to transfer restrictions and will not provide for the
payment of additional interest under the circumstances described
below;
- use our reasonable best efforts to cause the exchange offer
registration statement to be declared effective under the Securities
Act within 330 days of the original issue date of the new notes;
- use our reasonable best efforts to keep the exchange offer
registration statement effective until the closing of the Exchange
Offer; and
- use our reasonable best efforts to cause the Exchange Offer to be
consummated not later than 30 days following the effectiveness of
the exchange offer registration statement.
The new notes will be issued under the Indenture. Upon the effectiveness
of the exchange offer registration statement, we will offer the new notes in
exchange for surrender of the old notes. We will keep the Exchange Offer open
for not less than 20 business days after the date notice of the Exchange Offer
is mailed to the Holders of the old notes, or longer if required by applicable
law.
For each old note surrendered to us pursuant to the Exchange Offer and not
withdrawn by the Holder, the Holder of the old note will receive a new note
having a principal amount equal to that of the surrendered old note. Interest on
each new note will accrue from the last date on which interest was paid on the
old note surrendered in exchange or, if no interest has been paid on that old
note, from the original issue date of the new notes.
SEC INTERPRETATIONS
Based on existing interpretations of the Securities Act by the staff of
the SEC in several no-action letters to third parties, and subject to the
immediately following sentence, we believe that the new notes issued pursuant to
the Exchange Offer may be offered for resale, resold or otherwise transferred by
the Holders, other than Holders who are broker-dealers, without further
compliance with the registration and prospectus delivery provisions of the
Securities Act. Any purchaser of new notes, however, who is our affiliate or who
intends to participate in the Exchange Offer for the purpose of distributing the
new notes, or any participating broker-dealer who purchased the new notes for
its own account, other than as a result of market-making activities or other
trading activities, to resell pursuant to Rule 144A or any other available
exemption under the Securities Act:
- will not be able to rely on the interpretations by the staff of the
SEC;
- will not be able to tender its old notes in the Exchange Offer; and
- must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with any sale or
transfer of the new notes, unless the sale or transfer is made under
an exemption from those requirements.
We do not intend to seek our own interpretation regarding the Exchange
Offer, and we cannot assure you that the staff of the SEC would make a similar
determination with respect to the new notes as it has in other interpretations
to third parties.
Each Holder of old notes, other than specified Holders, who wishes to
exchange such old notes for the related new notes in the Exchange Offer will be
required to make representations that:
44
- it is not our affiliate;
- the old notes being exchanged, and any new notes to be received by
it, have been or will be acquired in the ordinary course of its
business; and
- it has no arrangement or understanding with any person to
participate in the distribution, within the meaning of the
Securities Act, of the new notes.
In addition, in connection with resales of new notes, any participating
broker-dealer must deliver a prospectus meeting the requirements of the
Securities Act. The staff of the SEC has taken the position that participating
broker-dealers may fulfill their prospectus delivery requirements with respect
to the new notes, other than a resale of an unsold allotment from the original
sale of the new notes, with the prospectus contained in the exchange offer
registration statement. Under the registration rights agreement, we have agreed,
for a period of one year following the consummation of the Exchange Offer, to
make available a prospectus meeting the requirements of the Securities Act to
any participating broker-dealer for use in connection with any resale of any new
notes acquired in the Exchange Offer.
SHELF REGISTRATION
If:
(1) we are not permitted to consummate the Exchange Offer because the
Exchange Offer is not permitted by applicable law or SEC policy; or
(2) upon notice to us by any Holder in specified circumstances, and
(3) we are eligible to use Securities Act Form S-3
we will, in addition to or instead of effecting the registration of
the new notes pursuant to the exchange offer registration statement, as
the case may be,
(1) on or prior to 180 days after the earlier of any event in (1) or
(2) above, file with the SEC a shelf registration statement covering
resales of the old notes;
(2) use our reasonable best efforts to cause the shelf registration
statement to be declared effective under the Securities Act not later than
270 days after the date of any event in (1) or (2) above;
(3) use our reasonable best efforts to keep the shelf registration
statement effective for two years; and
(4) use our reasonable best efforts to ensure that the shelf
registration statement and any amendment to the shelf registration
statement and any prospectus included in the shelf registration statement
conforms with the requirements of the Securities Act.
We will, in the event of the filing of a shelf registration statement,
provide to each Holder of old notes that are covered by the shelf registration
statement copies of the prospectus that is a part of the shelf registration
statement and notify each Holder when the shelf registration statement has
become effective. A Holder of old notes that sells the old notes pursuant to the
shelf registration statement generally will be required to be named as a selling
security holder in the related prospectus, to deliver information to be used in
connection with the shelf registration, and to deliver a prospectus to
purchasers, will be subject to the civil liability provisions under the
Securities Act in connection with the sales and will be bound by the provisions
of the registration rights agreement that are applicable to the Holder,
including indemnification obligations.
45
ADDITIONAL INTEREST
We are making this Exchange Offer to satisfy our obligations and your
registration rights under the registration rights agreement. If a registration
default occurs, which means one of the following events occurs:
- the exchange offer registration statement is not filed with the SEC
on or prior to the 240th calendar day following the original issue
date of the old notes;
- the exchange offer registration statement is not declared effective
on or prior to the 330th calendar day following the original issue
date of the old notes;
- the Exchange Offer is not consummated on or prior to the 30th
calendar day following effectiveness of the exchange offer
registration statement;
- if required, a shelf registration statement with respect to the old
notes is not filed with the SEC on or prior to the date specified
above;
- if required, a shelf registration statement with respect to the old
notes is not declared effective on or prior to the date specified
above; or
- either the exchange offer registration statement or a shelf
registration statement has been filed and declared effective but
after its effective date ceases to be effective or is unusable for
its intended purpose without being succeeded within 15 business days
by a post-effective amendment to such registration statement that
cures such failure and that is itself declared effective by the SEC
within five business days;
then additional interest will accrue on the old notes, from and including the
date on which any such registration default shall occur to, but excluding, the
date on which the registration default has been cured, at the rate of 0.25% per
annum during the 90-day period immediately following the occurrence of such
registration default and shall increase by 0.25% per annum at the end of each
subsequent 90-day period, but in no event shall such rate exceed 0.50% per
annum. We will have no other liabilities for monetary damages with respect to
our registration obligations. The receipt of additional interest will be the
sole monetary remedy available to a Holder if we fail to meet these obligations.
EXPIRATION DATE; EXTENSIONS; AMENDMENTS; TERMINATION
The term "EXPIRATION DATE" shall mean September 29, 2004 unless we, in our
sole discretion, extend the Exchange Offer, in which case the term "EXPIRATION
DATE" shall mean the latest date to which the Exchange Offer is extended.
To extend the Expiration Date, we will notify the Exchange Agent of any
extension by oral or written notice and will notify the holders of the old notes
by means of a press release or other public announcement prior to 9:00 a.m., New
York City time, on the next business day after the previously scheduled
Expiration Date. Such announcement may state that we are extending the Exchange
Offer for a specified period of time.
We reserve the right :
- to delay acceptance of any old notes, extend the Exchange Offer or
terminate the Exchange Offer and not permit acceptance of the old
notes not previously accepted if any of the conditions set forth
herein under "--Conditions" shall have occurred and shall not have
been waived by us, by giving oral or written notice of such delay,
extension or termination to the Exchange Agent, or
- to amend the terms of the Exchange Offer in any manner deemed by it
to be advantageous to the holders of the old notes.
46
Any such delay in acceptance, extension, termination or amendment will be
followed as promptly as practicable by oral or written notice thereof to
the Exchange Agent. If the Exchange Offer is amended in a manner
determined by us to constitute a material change, we will promptly
disclose such amendment in a manner reasonably calculated to inform the
holders of the old notes of such amendment.
Without limiting the manner in which we may choose to make public
announcement of any delay, extension, amendment or termination of the Exchange
Offer, we shall have no obligations to publish, advertise, or otherwise
communicate any such public announcement, other than by making a timely release
to an appropriate news agency.
INTEREST ON THE NEW NOTES
Interest on the new notes will accrue from the last date on which interest was
paid on the old notes, or, if no interest has been paid on such old notes, from
the date of issuance of the new notes. Interest on the new notes is payable
semiannually on February 1 and August 1 commencing August 1, 2004.
PROCEDURES FOR TENDERING
To tender in the Exchange Offer, a holder must complete, sign and date the
Letter of Transmittal, or a facsimile thereof, have the signatures thereon
medallion guaranteed if required by the Letter of Transmittal, and mail or
otherwise deliver such Letter of Transmittal or such facsimile, together with
any other required documents, to the Exchange Agent prior to 5:00 p.m., New York
City time, on the Expiration Date. In addition, either (i) a timely confirmation
of a book-entry transfer (a "BOOK-ENTRY CONFIRMATION") of such old notes into
the Exchange Agent's account at The Depositary (the "BOOK-ENTRY TRANSFER
FACILITY") pursuant to the procedure for book-entry transfer described below,
must be received by the Exchange Agent prior to the Expiration Date or (ii) the
holder must comply with the guaranteed delivery procedures described below. THE
METHOD OF DELIVERY OF LETTERS OF TRANSMITTAL AND ALL OTHER REQUIRED DOCUMENTS TO
THE EXCHANGE AGENT IS AT THE ELECTION AND RISK OF THE HOLDERS. IF SUCH DELIVERY
IS BY MAIL, IT IS RECOMMENDED THAT REGISTERED MAIL, PROPERLY INSURED, WITH
RETURN RECEIPT REQUESTED, BE USED. IN ALL CASES, SUFFICIENT TIME SHOULD BE
ALLOWED TO ASSURE TIMELY DELIVERY TO THE EXCHANGE AGENT BEFORE THE EXPIRATION
DATE. NO LETTERS OF TRANSMITTAL OR OTHER REQUIRED DOCUMENTS SHOULD BE SENT TO
CONSUMERS. Delivery of all documents must be made to the Exchange Agent at its
address set forth below. Holders may also request their respective brokers,
dealers, commercial banks, trust companies or nominees to effect such tender for
such holders.
The tender by a holder of old notes will constitute an agreement between
such holder and CMS in accordance with the terms and subject to the conditions
set forth herein and in the Letter of Transmittal. Any beneficial owner whose
old notes are registered in the name of a broker, dealer, commercial bank, trust
company or other nominee and who wishes to tender should contact such registered
holder promptly and instruct such registered holder to tender on his behalf.
Signatures on a Letter of Transmittal or a notice of withdrawal, as the
case may be, must be medallion guaranteed by any member firm of a registered
national securities exchange or of the National Association of Securities
Dealers, Inc., a commercial bank or trust company having an office or
correspondent in the United States or an "eligible guarantor" institution within
the meaning of Rule 17Ad-15 under the Exchange Act (each an "ELIGIBLE
INSTITUTION") unless the old notes tendered pursuant thereto are tendered for
the account of an Eligible Institution.
If the Letter of Transmittal is signed by trustees, executors,
administrators, guardians, attorneys-in-fact, officers of corporations, or
others acting in a fiduciary or representative capacity, such person should so
indicate when signing, and unless waived by CMS, evidence satisfactory to CMS of
their authority to so act must be submitted with the Letter of Transmittal.
All questions as to the validity, form, eligibility (including time of
receipt) and withdrawal of the tendered old notes will be determined by CMS, in
its sole discretion, which determination will be final and binding. CMS reserves
the absolute right to reject any and all old notes not properly tendered or any
old notes which, if accepted, would, in the opinion of counsel for CMS, be
unlawful. CMS also reserves the absolute right to waive any
47
irregularities or conditions of tender as to particular old notes. CMS's
interpretation of the terms and conditions of the Exchange Offer (including the
instructions in the Letter of Transmittal) will be final and binding on all
parties. Unless waived, any defects or irregularities in connection with tenders
of old notes must be cured within such time as CMS shall determine. Neither CMS,
the Exchange Agent nor any other person shall be under any duty to give
notification of defects or irregularities with respect to tenders of old notes,
nor shall any of them incur any liability for failure to give such notification.
Tenders of old notes will not be deemed to have been made until such
irregularities have been cured or waived. Any old notes received by the Exchange
Agent that are not properly tendered and as to which the defects or
irregularities have not been cured or waived will be returned without cost to
such holder by the Exchange Agent, unless otherwise provided in the Letter of
Transmittal, as soon as practicable following the Expiration Date.
In addition, CMS reserves the right, in its sole discretion, subject to
the provisions of the Indenture, to purchase or make offers for any old notes
that remain outstanding subsequent to the Expiration Date or, as set forth under
"--Conditions," to terminate the Exchange Offer in accordance with the terms of
the Registration Rights Agreement, and to the extent permitted by applicable
law, purchase old notes in the open market, in privately negotiated transactions
or otherwise. The terms of any such purchases or offers could differ from the
terms of the Exchange Offer.
ACCEPTANCE OF OLD NOTES FOR EXCHANGE; DELIVERY OF NEW NOTES
Upon satisfaction or waiver of all of the conditions to the Exchange
Offer, all old notes properly tendered will be accepted promptly after the
Expiration Date, and the new notes will be issued promptly after acceptance of
the old notes. See "--Conditions." For purposes of the Exchange Offer, the old
notes shall be deemed to have been accepted as validly tendered for exchange
when CMS gives oral or written notice to the Exchange Agent.
In all cases, issuance of new notes for old notes that are accepted for
exchange pursuant to the Exchange Offer will be made only after the Exchange
Agent has timely received a Book-Entry Confirmation of such old notes into its
account at the Book-Entry Transfer Facility and a properly completed and duly
executed Letter of Transmittal and all other required documents. If any tendered
old notes are not accepted for any reason set forth in the terms and conditions
of the Exchange Offer, such unaccepted or such nonexchanged old notes will be
credited to an account maintained with such Book- Entry Transfer Facility as
promptly as practicable after the expiration or termination of the Exchange
Offer.
BOOK-ENTRY TRANSFER
The Exchange Agent will make a request to establish an account with
respect to the old notes at the Book-Entry Transfer Facility for purposes of the
Exchange Offer within two business days after the date of this prospectus. Any
financial institution that is a participant in the Book-Entry Transfer
Facility's systems may make book-entry delivery of old notes by causing the
Book-Entry Transfer Facility to transfer such old notes into the Exchange
Agent's account at the Book-Entry Transfer Facility in accordance with such
Book-Entry Transfer Facility's procedures for transfer. However, the Letter of
Transmittal (or facsimile) thereof with any required signature guarantees and
any other required documents must, in any case, be transmitted to and received
by the Exchange Agent at one of the addresses set forth under "--Exchange Agent"
on or prior to the Expiration Date or the guaranteed delivery procedures
described below must be complied with.
GUARANTEED DELIVERY PROCEDURES
If the procedures for book-entry transfer cannot be completed on a timely
basis, a tender may be effected if:
- the tender is made through an Eligible Institution;
- prior to the Expiration Date, the Exchange Agent receives from such
Eligible Institution a properly completed and duly executed Letter
of Transmittal (or a facsimile thereof) and Notice of Guaranteed
Delivery, substantially in the form provided by CMS (by facsimile
transmission, mail or hand delivery), setting forth the name and
address of the holder of old notes and the amount of old notes
tendered, stating that the tender is being made thereby and
guaranteeing that within three New York Stock Exchange, Inc.
48
("NYSE") trading days after the date of execution of the Notice of
Guaranteed Delivery, a Book- Entry Confirmation and any other
documents required by the Letter of Transmittal will be deposited by
the Eligible Institution with the Exchange Agent, and
- a Book-Entry Confirmation and all other documents required by the
Letter of Transmittal are received by the Exchange Agent within
three NYSE trading days after the date of execution of the Notice of
Guaranteed Delivery.
WITHDRAWAL OF TENDERS
Tenders of old notes may be withdrawn at any time prior to 5:00 p.m., New
York City time, on the Expiration Date.
For a withdrawal to be effective, a written notice of withdrawal must be
received by the Exchange Agent prior to 5:00 p.m., New York City time, on the
Expiration Date at one of the addresses set forth under "--Exchange Agent." Any
such notice of withdrawal must specify:
- the name and number of the account at the Book-Entry Transfer
Facility from which the old notes were tendered;
- identify the principal amount of the old notes to be withdrawn; and
- specify the name and number of the account at the Book-Entry
Transfer Facility to be credited with the withdrawn old notes and
otherwise comply with the procedures of such Book-Entry Transfer
Facility.
All questions as to the validity, form and eligibility (including time of
receipt) of such notice will be determined by CMS, whose determination shall be
final and binding on all parties. Any old notes so withdrawn will be deemed not
to have been validly tendered for exchange for purposes of the Exchange Offer.
Any old notes which have been tendered for exchange but which are not exchanged
for any reason will be credited to an account maintained with such Book-Entry
Transfer Facility for the old notes as soon as practicable after withdrawal,
rejection of tender or termination of the Exchange Offer. Properly withdrawn old
notes may be retendered by following one of the procedures described under
"--Procedures for Tendering" and "--Book-Entry Transfer" at any time on or prior
to the Expiration Date.
CONDITIONS
Notwithstanding any other term of the Exchange Offer, old notes will not
be required to be accepted for exchange, nor will new notes be issued in
exchange for any old notes, and CMS may terminate or amend the Exchange Offer as
provided herein before the acceptance of such old notes, if, because of any
change in law, or applicable interpretations thereof by the SEC, CMS determines
that it is not permitted to effect the Exchange Offer. CMS has no obligation to,
and will not knowingly, permit acceptance of tenders of old notes from
affiliates of CMS or from any other holder or holders who are not eligible to
participate in the Exchange Offer under applicable law or interpretations
thereof by the staff of the SEC, or if the new notes to be received by such
holder or holders of old notes in the Exchange Offer, upon receipt, will not be
tradable by such holder without restriction under the Securities Act and the
Exchange Act and without material restrictions under the "blue sky" or
securities laws of substantially all of the states of the United States. Other
than the United States federal and state securities laws we do not need to
satisfy any regulatory requirements or obtain any regulatory approvals to
conduct the Exchange Offer.
EXCHANGE AGENT
J.P. Morgan Trust Company, N.A. has been appointed as Exchange Agent for
the Exchange Offer. Questions and requests for assistance and requests for
additional copies of this prospectus or of the Letter of Transmittal should be
directed to the Exchange Agent addressed as follows:
49
By Certified or Registered Mail: By Overnight Courier or Hand:
J.P. Morgan Trust Company, N.A. J.P. Morgan Trust Company, N.A.
Institutional Trust Services Institutional Trust Services
P.O. Box 2320 2001 Bryan Street, 9th Floor
Dallas, Texas 75221-2320 Dallas, Texas 75201
Attention: Frank Ivins Attention: Frank Ivins
Confirm By Telephone:
(800) 275-2048
FEES AND EXPENSES
The expenses of soliciting tenders pursuant to the Exchange Offer will be
borne by CMS. The principal solicitation for tenders pursuant to the Exchange
Offer is being made by mail; however, additional solicitations may be made by
telephone, facsimile or in person by officers and regular employees of CMS.
CMS will not make any payments to brokers, dealers or other persons
soliciting acceptances of the Exchange Offer. CMS, however, will pay the
Exchange Agent reasonable and customary fees for its services and will reimburse
the Exchange Agent for its reasonable out-of-pocket expenses in connection
therewith.
The expenses to be incurred in connection with the Exchange Offer will be
paid by CMS, including fees and expenses of the Exchange Agent and the Trustee,
and accounting, legal, printing and related fees and expenses.
CMS will pay all transfer taxes, if any, applicable to the exchange of old
notes pursuant to the Exchange Offer. If, however, new notes or old notes for
principal amounts not tendered or accepted for exchange are to be registered or
issued in the name of any person other than the registered holder of the old
notes tendered, or if tendered old notes are registered in the name of any
person other than the person signing the Letter of Transmittal, or if a transfer
tax is imposed for any reason other than the exchange of old notes pursuant to
the Exchange Offer, then the amount of any such transfer taxes (whether imposed
on the registered holder or any other persons) will be payable by the tendering
holder. If satisfactory evidence of payment of such taxes or exemption therefrom
is not submitted with the Letter of Transmittal, the amount of such transfer
taxes will be billed directly to such tendering holder.
RESALE OF NEW NOTES
Based on an interpretation by the staff of the SEC set forth in no-action
letters issued to third parties, CMS believes that new notes issued pursuant to
the Exchange Offer in exchange for old notes may be offered for resale, resold
and otherwise transferred by any owner of such new notes (other than any such
owner which is an "affiliate" of CMS within the meaning of Rule 405 under the
Securities Act) without compliance with the registration and prospectus delivery
provisions of the Securities Act, provided that such new notes are acquired in
the ordinary course of such owner's business and such owner does not intend to
participate, and has no arrangement or understanding with any person to
participate, in the distribution of such new notes. Any owner of old notes who
tenders in the Exchange Offer with the intention to participate, or for the
purpose of participating, in a distribution of the new notes may not rely on the
position of the staff of the SEC enunciated in Exxon Capital Holdings
Corporation (available May 13, 1988, as interpreted in the SEC's letter to
Shearman & Sterling dated July 2, 1993), Morgan Stanley & Co., Incorporated
(available June 5, 1991), Warnaco, Inc. (available June 5, 1991), and Epic
Properties, Inc. (available October 21, 1991) or similar no-action letters
(collectively the "NO-ACTION LETTERS") but rather must comply with the
registration and prospectus delivery requirements of the Securities Act in
connection with any resale transaction. In addition, any such resale transaction
should be covered by an effective registration statement containing the selling
security holders' information required by Item 507 of Regulation S-K of the
Securities Act. Each broker-dealer that receives new notes for its own account
in exchange for old notes, where such old notes were acquired by such
broker-dealer as a result of market-making activities or other trading
activities, may be a statutory underwriter and must acknowledge that it will
deliver a prospectus meeting the requirements of the Securities Act in
connection with any resale of such new notes.
By tendering in the Exchange Offer, each holder (or DTC participant, in
the case of tenders of interests in old notes held in a global security held by
DTC) will represent to CMS (which representation may be contained the
50
Letter of Transmittal) to the effect that (A) it is not an affiliate of CMS, (B)
it is not engaged in, and does not intend to engage in, and has no arrangement
or understanding with any person to participate in, a distribution of the new
notes to be issued in the Exchange Offer and (C) it is acquiring the new notes
in its ordinary course of business. Each holder will acknowledge and agree that
any broker-dealer and any such holder using the Exchange Offer to participate in
a distribution of the new notes acquired in the Exchange Offer (1) could not
under SEC policy as in effect on the date of the Registration Rights Agreements
rely on the position of the SEC enunciated in the No-Action Letters, and (2)
must comply with the registration and prospectus delivery requirements of the
Securities Act in connection with a secondary resale transaction and that such a
secondary resale transaction must be covered by an effective registration
statement containing the selling security holder information required by Item
507 or 508, as applicable, of Regulation S-K if the resales are of new notes
obtained by such holder in exchange for old notes acquired by such holder
directly from CMS or an affiliate thereof.
To comply with the securities laws of certain jurisdictions, it may be
necessary to qualify for sale or to register the new notes prior to offering or
selling such new notes. CMS has agreed, pursuant to the Registration Rights
Agreements and subject to certain specified limitations therein, to cooperate
with selling holders or underwriters in connection with the registration and
qualification of the new notes for offer or sale under the securities or "blue
sky" laws of such jurisdictions as may be necessary to permit the holders of new
notes to trade the new notes without any restrictions or limitations under the
securities laws of the several states of the United States.
CONSEQUENCES OF FAILURE TO EXCHANGE
Holders of old notes who do not exchange their old notes for new notes
pursuant to the Exchange Offer will continue to be subject to the restrictions
on transfer of such old notes as set forth in the legend thereon as a
consequence of the issuance of the old notes pursuant to exemptions from, or in
transactions not subject to, the registration requirements of the Securities Act
and applicable state securities laws. In general, the old notes may not be
registered under the Securities Act, except pursuant to a transaction not
subject to, the Securities Act and applicable state securities laws. CMS does
not currently anticipate that it will register the old notes under the
Securities Act. To the extent that old notes are tendered and accepted in the
Exchange Offer, the trading market for untendered and tendered but unaccepted
old notes could be adversely affected.
51
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED
JUNE 30, 2004
This Management's Discussion and Analysis of Financial Condition and
Results of Operations for the Six Months Ended June 30, 2004 (the "10-Q MD&A")
refers to CMS' Condensed Notes to Consolidated Financial Statements for the six
months ended June 30, 2004 and should be read in conjunction with such June 30,
2004 Financial Statements (the "JUNE 30, 2004 FINANCIAL STATEMENTS") beginning
on page F-2. The June 30, 2004 Financial Statements contain detailed information
that should be referred to in conjunction with the following 10-Q MD&A. The 10-Q
MD&A also describes material contingencies in CMS' Condensed Notes to the June
30, 2004 Financial Statements, and CMS encourages readers to review these Notes.
All Note references within the 10-Q MD&A refer to CMS' Condensed Notes to the
June 30, 2004 Financial Statements. Please refer to the Glossary beginning on
page 146 of this prospectus for definitions of certain capitalized terms used in
the 10-Q MD&A.
EXECUTIVE OVERVIEW
CMS Energy is an integrated energy company with a business strategy
focused primarily in Michigan. We are the parent holding company of Consumers
and Enterprises. Consumers is a combination electric and gas utility company
serving Michigan's Lower Peninsula. Enterprises, through various subsidiaries
and equity investments, is engaged in domestic and international diversified
energy businesses including: independent power production and natural gas
transmission, storage and processing. We manage our businesses by the nature of
services each provides and operate principally in three business segments:
electric utility, gas utility, and enterprises.
We earn our revenue and generate cash from operations by providing
electric and natural gas utility services, electric power generation, gas
transmission, storage, and processing. Our businesses are affected by weather,
especially during the key heating and cooling seasons, economic conditions,
particularly in Michigan, regulation and regulatory issues that primarily affect
our gas and electric utility operations, interest rates, our debt credit rating,
and energy commodity prices.
Our strategy involves rebuilding our balance sheet and refocusing on our
core strength: superior utility operation and service. Over the next few years,
we expect this strategy to reduce our parent company debt substantially, improve
our debt ratings, grow earnings at a mid-single digit rate, restore a meaningful
dividend, and position the company to make new investments consistent with our
strengths. In the near term, our new investments will focus on the utility.
We face important challenges in the future. We continue to lose industrial
and commercial customers to alternative electric suppliers without receiving
compensation for stranded costs caused by the lost sales. As of July 2004, we
have lost 858 MW or 11 percent of our electric load to these alternative
electric suppliers. Based on current trends, we predict load loss by year-end to
be in the range of 900 MW to 1,100 MW. However, no assurance can be made that
the actual load loss will be greater or less than that range. Existing state
legislation encourages competition and provides for recovery of stranded costs,
but the MPSC has not yet authorized stranded cost recovery. We continue to seek
resolution of this issue. In July 2004, several bills were introduced into the
Michigan Senate that could change Michigan's Customer Choice Act.
Further, higher natural gas prices have harmed the economics of the MCV
Partnership and we are seeking approval from the MPSC to change the way the
facility is used. Our proposal would reduce gas consumption by an estimated 30
to 40 bcf per year while improving the MCV Partnership's financial performance
with no change to customer rates. A portion of the benefits from the proposal
will support additional renewable resource development in Michigan. Resolving
the issue is critical for our shareowners and customers.
Our gas business faces market and regulatory uncertainties relating to gas
costs. We attempt to minimize these uncertainties by fully recovering what we
spend to purchase the gas through the GCR process. We currently have a GCR year
2003-2004 reconciliation on file with the MPSC.
52
We are focused on further reducing our business risk and leverage, while
growing the equity base of our company. Much of our asset sales program is
complete; we are engaged in selling the remaining businesses that are not
strategic to us. This creates volatility in earnings as we recognize foreign
currency translation account losses at the time of sale, but it is the right
strategic direction for our company. We are also working to resolve outstanding
litigation that stemmed from energy trading and gas index price reporting
activities in 2001 and earlier.
Our business plan is targeted at predictable earnings growth and debt
reduction. We are now over a year into our plan to reduce, by about half, the
debt of CMS Energy over a five-year period. The result of these efforts will be
a strong, reliable energy company that will be poised to take advantage of
opportunities for further growth.
RESTATEMENT OF 2003 FINANCIAL STATEMENTS
Our financial statements as of and for the three and six months ended June
30, 2003, as presented in this Form 10-Q, have been restated for the following
matters that were disclosed previously in Note 19, Quarterly Financial and
Common Stock Information (Unaudited), in our 2003 Form 10-K/A:
- International Energy Distribution, which includes SENECA and CPEE,
is no longer considered "discontinued operations," due to a change
in our expectations as to the timing of the sales,
- certain derivative accounting corrections at our equity affiliates,
and
- the net loss recorded in the second quarter of 2003 relating to the
sale of Panhandle, reflected as Discontinued Operations, was
understated by approximately $14 million, net of tax.
CONSOLIDATION OF VARIABLE INTEREST ENTITIES
Under Revised FASB Interpretation No. 46, we are the primary beneficiary
of several entities, most notably the MCV Partnership and the FMLP. As a result,
we have consolidated the assets, liabilities, and activities of these entities
into our financial statements as of and for the three and six months ended June
30, 2004. These entities are reported as equity method investments in our
financial statements as of and for the three and six months ended June 30, 2003.
Therefore, the consolidation of these entities had no impact on our consolidated
net income for the three and six months ended June 30, 2004. For additional
details, see Note 11, Implementation of New Accounting Standards.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
This Form 10-Q and other written and oral statements that we make contain
forward-looking statements as defined in Rule 3b-6 of the Exchange Act, as
amended, Rule 175 of the Securities Act of 1933, as amended, and relevant legal
decisions. Our intention with the use of such words as "may," "could,"
"anticipates," "believes," "estimates," "expects," "intends," "plans," and other
similar words is to identify forward-looking statements that involve risk and
uncertainty. We designed this discussion of potential risks and uncertainties to
highlight important factors that may impact our business and financial outlook.
We have no obligation to update or revise forward-looking statements regardless
of whether new information, future events or any other factors affect the
information contained in the statements. These forward-looking statements are
subject to various factors that could cause our actual results to differ
materially from the results anticipated in these statements. Such factors
include our inability to predict and/or control:
- the efficient sale of non-strategic or under-performing domestic or
international assets and discontinuation of certain operations,
- capital and financial market conditions, including the price of CMS
Energy Common Stock and the effect of such market conditions on the
Pension Plan, interest rates, and availability of financing to CMS
Energy, Consumers, or any of their affiliates, and the energy
industry,
- ability to access the capital markets successfully,
53
- market perception of the energy industry, CMS Energy, Consumers, or
any of their affiliates,
- credit ratings of CMS Energy, Consumers, or any of their affiliates,
- currency fluctuations, transfer restrictions, and exchange controls,
- factors affecting utility and diversified energy operations such as
unusual weather conditions, catastrophic weather-related damage,
unscheduled generation outages, maintenance or repairs,
environmental incidents, or electric transmission or gas pipeline
system constraints,
- international, national, regional, and local economic, competitive,
and regulatory policies, conditions and developments,
- adverse regulatory or legal decisions, including environmental laws
and regulations,
- the impact of adverse natural gas prices on the MCV Partnership
investment, regulatory decisions concerning the MCV Partnership RCP,
and regulatory decisions that limit our recovery of capacity and
fixed energy payments,
- federal regulation of electric sales and transmission of electricity
including re-examination by federal regulators of the market-based
sales authorizations by which our subsidiaries participate in
wholesale power markets without price restrictions, and proposals by
the FERC to change the way it currently lets our subsidiaries and
other public utilities and natural gas companies interact with each
other,
- energy markets, including the timing and extent of unanticipated
changes in commodity prices for oil, coal, natural gas, natural gas
liquids, electricity, and certain related products due to lower or
higher demand, shortages, transportation problems, or other
developments,
- potential disruption, expropriation or interruption of facilities or
operations due to accidents, war, terrorism, or changing political
conditions and the ability to obtain or maintain insurance coverage
for such events,
- nuclear power plant performance, decommissioning, policies,
procedures, incidents, and regulation, including the availability of
spent nuclear fuel storage,
- technological developments in energy production, delivery, and
usage,
- achievement of capital expenditure and operating expense goals,
- changes in financial or regulatory accounting principles or
policies,
- outcome, cost, and other effects of legal and administrative
proceedings, settlements, investigations and claims, including
particularly claims, damages, and fines resulting from round-trip
trading and inaccurate commodity price reporting, including
investigations by the DOJ regarding round-trip trading and price
reporting,
- limitations on our ability to control the development or operation
of projects in which our subsidiaries have a minority interest,
- disruptions in the normal commercial insurance and surety bond
markets that may increase costs or reduce traditional insurance
coverage, particularly terrorism and sabotage insurance and
performance bonds,
- other business or investment considerations that may be disclosed
from time to time in CMS Energy's or Consumers' SEC filings or in
other publicly issued written documents, and
- other uncertainties that are difficult to predict, and many of which
are beyond our control.
54
RESULTS OF OPERATIONS
Our business plan focuses on strengthening our balance sheet and improving
financial liquidity through debt reduction and aggressive cost management. The
sale of non-strategic and under-performing assets has generated cash to reduce
debt, reduced business risk, and will provide for more predictable future
earnings.
CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS
In Millions (except for per share amounts)
------------------------------------------
Restated
Three months ended June 30 2004 2003 Change
------------------------------------------------------ ------------ ------------ ------------
Net Income (Loss) Available to Common Stock $ 16 $ (65) $ 81
Basic Earnings (Loss) Per Share $ 0.10 $ (0.45) $ 0.55
Diluted Earnings (Loss) Per Share $ 0.10 $ (0.45) $ 0.55
------------ ------------ ------------
Electric utility $ 27 $ 35 $ (8)
Gas utility 1 5 (4)
Enterprises 38 8 30
Corporate interest and other (50) (60) 10
Discontinued operations - (53) 53
------------ ------------ ------------
CMS Energy Net Income (Loss) Available to Common Stock $ 16 $ (65) $ 81
============ ============ ============
For the three months ended June 30, 2004, our net income was $16 million,
compared to a loss of $65 million for the three months ended June 30, 2003. The
$81 million increase in net income primarily reflects:
- the absence of a $53 million loss from discontinued operations
recorded in 2003, comprised mainly of the loss on the sale of
Panhandle,
- the absence of a $31 million deferred tax asset valuation reserve
established in 2003,
- an $11 million increase in mark-to-market valuation adjustments on
interest rate swaps and power contracts, and
- a $6 million reduction in funded benefits expense primarily due to
the OPEB plans accounting for the Medicare Prescription Drug,
Improvement, and Modernization Act of 2003 and the positive impact
of prior year pension plan contributions on pension plan asset
returns.
These increases were partially offset by:
- the absence of a $30 million Michigan Single Business Tax refund
received in 2003, and
- a reduction in the Utility's net income resulting primarily from
industrial and commercial customers choosing different electricity
suppliers and decreased gas deliveries caused primarily by milder
weather.
For further information, see the individual results of operations for each
CMS Energy business segment within this MD&A.
55
In Millions (except for per share amounts)
------------------------------------------
Restated
Six months ended June 30 2004 2003 Change
----------------------------------------------- ------------ ------------ ------------
Net Income Available to Common Stock $ 9 $ 17 $ (8)
Basic Earnings Per Share $ 0.06 $ 0.12 $ (0.06)
Diluted Earnings Per Share $ 0.06 $ 0.14 $ (0.08)
------------ ------------ ------------
Electric utility $ 75 $ 86 $ (11)
Gas utility 57 59 (2)
Enterprises (23) 29 (52)
Corporate interest and other (98) (111) 13
Discontinued operations (2) (22) 20
Accounting changes - (24) 24
------------ ------------ ------------
CMS Energy Net Income Available to Common Stock $ 9 $ 17 $ (8)
============ ============ ============
For the six months ended June 30, 2004, our net income was $9 million,
compared to net income of $17 million for the six months ended June 30, 2003.
The $8 million decrease in income reflects:
- an $81 million charge to earnings related to the sale of Loy Yang,
- the absence of a $30 million Michigan Single Business Tax refund
received in 2003, and
- a reduction in the Utility's net income resulting primarily from
industrial and commercial customers choosing different electricity
suppliers and decreased gas deliveries caused primarily by milder
weather.
These decreases were partially offset by:
- the exclusion in 2004 of a $24 million charge for changes in
accounting that occurred in the first quarter of 2003,
- the absence of a $31 million deferred tax asset valuation reserve
established in 2003,
- the decrease of $20 million in the net loss from discontinued
operations resulting from the sale of Panhandle and other businesses
in 2003,
- a $31 million increase in mark-to-market valuation adjustments on
interest rate swaps and power contracts, and
- a $13 million reduction in funded benefits expense primarily due to
the OPEB plans accounting for the Medicare Prescription Drug,
Improvement, and Modernization Act of 2003 and the positive impact
of prior year pension plan contributions on pension plan asset
returns.
For further information, see the individual results of operations for each
CMS Energy business segment within this MD&A.
56
ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
June 30 2004 2003 Change
------------------ ---- ---- ------
Three months ended $ 27 $ 35 $ (8)
Six months ended $ 75 $ 86 $ (11)
==== ==== ======
Three Months Ended June 30, Six Months Ended
2004 vs. 2003 June 30, 2004 vs. 2003
--------------------------- ----------------------
Reasons for the change:
Electric deliveries $(10) $(20)
Power supply costs and related revenue (2) (8)
Other operating expenses, non-commodity
revenue and other income 13 26
General taxes (14) (10)
Fixed charges - (6)
Income taxes 5 7
---- ----
Total change $ (8) $(11)
==== ====
ELECTRIC DELIVERIES: Electric deliveries, including transactions with
other wholesale marketers, other electric utilities, and customers choosing
alternative suppliers increased 0.7 billion kWh or 7.2 percent and 1.0 billion
kWh or 5.4 percent for the three and six months ended June 30, 2004 versus the
same periods in 2003. The corresponding increases in electric delivery revenue
for both periods were offset by tariff revenue reductions and decreased sales
margins from deliveries to customers choosing alternative electric suppliers.
The tariff revenue reductions, which began January 1, 2004, were
equivalent to the Big Rock nuclear decommissioning surcharge in effect when our
electric retail rates were frozen from June 2000 through December 31, 2003. The
tariff revenue reductions were reclassified for capped customers as increases to
PSCR revenues. The increased PSCR revenues helped negate possible losses
attributable to the underrecovery of PSCR costs for these customers, primarily
the residential and small commercial classes. In fact, the revenue
reclassification contributed to the overrecovery of PSCR revenues in excess of
PSCR costs in these customer classes for the three and six months ended June 30,
2004. In 2004, to the extent we have PSCR overrecoveries, the overrecovery must
be reserved for possible future refund. The tariff revenue reductions have
decreased electric delivery revenues by approximately $9 million in the second
quarter of 2004, and $18 million in the first six months of 2004 versus 2003.
The tariff revenue reductions are expected to decrease electric delivery
revenues by $35 million for the full year of 2004 versus the full year of 2003.
For the three and six months ended June 30, 2004, the overall decline in
electric delivery revenues was offset partially by increased sales to
residential customers due to warmer weather versus the same periods in 2003.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our power supply cost
rate of recovery was a fixed amount per kWh, as required under the Customer
Choice Act. Therefore, power supply-related revenue in excess of actual power
supply costs increased operating income. By contrast, if power supply-related
revenues had been less than actual power supply costs, the impact would have
decreased operating income. In 2004, our recovery of power supply costs is no
longer fixed, but is instead restricted to a pre-defined limit for certain
customer classes. The customer classes that have a pre-defined limit, or cap, on
the level of power supply costs they can be charged are primarily the
residential and small commercial customer classes. In 2004, to the extent our
power supply-related revenues are in excess of actual power supply costs, this
former benefit is reserved for possible future refund. This change in the
treatment of excess power supply revenues over power supply costs decreased
operating income for the three and six months ended June 30, 2004 versus the
same periods in 2003.
OTHER OPERATING EXPENSES, NON-COMMODITY REVENUE AND OTHER INCOME: In the
three months ended June 30, 2004, other operating expenses decreased $1 million,
non-commodity revenue increased $1 million, and other income increased $11
million versus the same period in 2003. The increase in other income relates
primarily to interest income recognized in relation to capital expenditures in
excess of depreciation as allowed by the Customer Choice Act. This Act also
enabled us to defer depreciation expense on the excess of capital expenditures
57
over our depreciation base, contributing to a reduction in operating expenses
for the second quarter of 2004 versus the same period in 2003. Higher other
operating expenses substantially offset the reduction in electric depreciation
expense.
In the six months ended June 30, 2004, other operating expenses decreased
$6 million and other income increased $20 million versus the same period in
2003. The increase in other income relates primarily to interest income
recognized in relation to capital expenditures in excess of depreciation, as
allowed by the Customer Choice Act. Operating expense decreases reflect lower
benefit costs and our ability to defer depreciation expense on the excess of
capital expenditures over our depreciation base, as allowed by the Customer
Choice Act.
GENERAL TAXES: General taxes increased in the three and six months ended
June 30, 2004 versus the same periods in 2003 primarily due to reductions in the
MSBT expense in 2003. The 2003 reduction was primarily due to CMS Energy having
received approval to file consolidated tax returns for the years 2000 and 2001.
The taxable income for these years was lower than the amount used to make
estimated MSBT payments. These returns were filed in the second quarter of 2003.
FIXED CHARGES: Fixed charges increased in the six months ended June 30,
2004 versus the same periods in 2003 due to higher average debt levels,
partially offset by a reduction in the average rates of interest. The average
rate of interest dropped 79 basis points and 60 basis points for the three and
six month periods ended June 30, 2004 versus the same periods in 2003.
INCOME TAXES: In the three and six months ended June 30, 2004, income
taxes decreased versus the same periods in 2003 primarily due to lower earnings
by the electric utility, and the OPEB Medicare Part D federal subsidy that is
exempt from federal taxation.
GAS UTILITY RESULTS OF OPERATIONS
In Millions
------------------------------------------------------------------------------
June 30 2004 2003 Change
------------------ ---- ---- -----------
Three months ended $ 1 $ 5 $ (4)
Six months ended $ 57 $ 59 $ (2)
==== ==== ===========
Three Months Ended June 30, Six Months Ended June 30,
Reasons for the change: 2004 vs. 2003 2004 vs. 2003
----------------------------------------------- --------------------------- -------------------------
Gas deliveries $(7) $(21)
Gas rate increase 2 11
Gas wholesale and retail services and other gas
revenues 1 3
Operation and maintenance - (2)
General taxes, depreciation, and other income (3) 3
Fixed charges (2) (6)
Income taxes 5 10
--- ----
Total change $(4) $ (2)
=== ====
GAS DELIVERIES: For the three months ended June 30, 2004, the more
profitable non-transportation gas deliveries decreased 4.9 bcf or 13.6 percent
primarily due to milder weather. The less profitable transportation gas
deliveries increased 5.2 bcf or 21.0 percent due to increased MCV Facility
generation. Overall, gas deliveries, including miscellaneous transportation,
increased 0.3 bcf or 0.5 percent versus the same period in 2003.
For the six months ended June 30, 2004, gas deliveries, including
miscellaneous transportation, decreased 6.7 bcf or 2.9 percent versus the same
period in 2003 primarily due to milder weather.
58
GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate
order authorizing a $19 million annual increase to gas tariff rates. As a result
of this order, gas revenues increased for the three and six months ended June
30, 2004 versus the same periods in 2003.
GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: For the three
and six months ended June 30, 2004, wholesale and retail services and other gas
revenues increased due primarily to increased gas transportation and storage
revenues versus the same periods in 2003.
OPERATION AND MAINTENANCE: For the six months ended June 30, 2004,
increased expenditures on safety, reliability, and customer service were offset
partially by reduced benefit costs compared to the same period in 2003.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: For the three months ended
June 30, 2004 versus the same period in 2003, general tax expense increased $5
million due to higher MSBT expense and depreciation expense decreased $2
million. The increase in MSBT expense is primarily due to CMS Energy having
received approval to file consolidated tax returns for the years 2000 and 2001.
The taxable income for these years was lower than the amount used to make
estimated MSBT payments. These returns were filed in the second quarter of 2003.
The reduced depreciation expense relates to decreases in depreciation rates
authorized by the MPSC's December 2003 interim rate order.
For the six months ended June 30, 2004, general tax expense increased $4
million due to higher MSBT expense, depreciation expense decreased $8 million,
and other income decreased $1 million versus the same period in 2003. The
increase in MSBT expense is primarily due to CMS Energy having received approval
to file consolidated tax returns for the years 2000 and 2001. The taxable income
for these years was lower than the amount used to make estimated MSBT payments.
These returns were filed in the second quarter of 2003. The reduced depreciation
expense relates to decreases in depreciation rates authorized by the MPSC's
December 2003 interim rate order.
FIXED CHARGES: Fixed charges increased in the three and six months ended
June 30, 2004 versus the same periods in 2003 due to higher average debt levels,
partially offset by a reduction in the average rate of interest. The average
rate of interest dropped 79 basis points and 60 basis points for the three and
six month periods ended June 30, 2004 versus the same periods in 2003.
INCOME TAXES: For the three and six months ended June 30, 2004 versus the
same periods in 2003, income taxes decreased due to the income tax treatment of
items related to plant, property, and equipment as required by past MPSC
rulings, the decreased earnings of the gas utility, and the OPEB Medicare Part D
federal subsidy that is exempt from federal taxation.
59
ENTERPRISES RESULTS OF OPERATIONS
In Millions
------------
June 30 2004 2003 Change
------------------ ------------ ------------ ------------
Three months ended $ 38 $ 8 $ 30
Six months ended $ (23) $ 29 $ (52)
Three Months Ended June 30, Six Months Ended June 30,
2004 vs. 2003 2004 vs. 2003
Reasons for the change: --------------------------- -------------------------
Results of FASB Interpretation No. 46 Entities $ (5) $ (11)
Reasons for change excluding FIN No. 46:
Operating revenues (50) (403)
Cost of gas and purchased power 61 436
Earnings from equity method investees 10 (2)
Operation and maintenance 8 9
General taxes, depreciation, and other income (3) 2
Asset impairment charges 3 (127)
Fixed charges 19 18
Income taxes (13) 26
----- -----
Total change $ 30 $ (52)
===== =====
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES:
Due to the implementation of FIN No. 46, certain equity investments included in
equity earnings in 2003, were determined to be variable interest entities and
are now consolidated in our results of operations for 2004. The net decrease in
earnings, due to the results of these entities, was $5 million for the three
months ended June 30, 2004 and $11 million for the six months ended June 30,
2004. These decreases were primarily due to increased fuel and dispatch costs
for 2004.
OPERATING REVENUES AND COST OF GAS AND PURCHASED POWER: For the three
months ended June 30, 2004, operating revenues and related cost of gas and
purchased power decreased versus the same period in 2003 due to the continued
streamlining of CMS ERM.
For the six months ended June 30, 2004, operating revenues and related
cost of gas and purchased power decreased versus the same period in 2003. The
decrease was primarily the result of the sale of CMS ERM Wholesale Gas and Power
contracts and the absence of mark-to-market valuation adjustments associated
with these contracts.
EARNINGS FROM EQUITY METHOD INVESTEES: Earnings from equity method
investees increased due to mark-to-market valuation adjustments related to
interest rate swaps of $21 million for the three months ended June 30, 2004 and
$15 million for the six months ended June 30, 2004 versus the same periods in
2003. The increase from interest rate swaps was offset partially by the impact
of the Argentine government's natural gas export restrictions on the results of
GasAtacama, and a deferred tax credit at Jorf Lasfar in 2003.
OPERATION AND MAINTENANCE: For the three and six months ended June 30,
2004, operation and maintenance expense decreased versus the same period of
2003. Lower expenses in 2004 were primarily due to streamlining and business
reduction at CMS ERM.
GENERAL TAXES, DEPRECIATION AND OTHER INCOME, NET: For the three months
ended June 30, 2004, general tax, depreciation and other income decreased
operating income versus the same period in 2003, primarily as a result of
foreign exchange losses offset partially by lower depreciation and general taxes
due to the streamlining and business reduction at CMS ERM.
60
For the six months ended June 30, 2004, general tax, depreciation and
other income increased operating income versus the same period in 2003, as a
result of lower depreciation and general taxes due to the streamlining and
business reduction at CMS ERM.
ASSET IMPAIRMENT CHARGES: For the three months ended June 30, 2004, there
were no asset impairment charges versus the same period in 2003, which included
$3 million of asset impairment charges primarily at International Energy
Distribution.
For the six months ended June 30, 2004, asset impairment charges increased
versus the same period in 2003 due to an impairment charge recorded in 2004 to
recognize the reduction in fair value of Loy Yang.
FIXED CHARGES: For the three and six months ended June 30, 2004, versus
the same periods in 2003, fixed charges decreased due to lower average debt
levels and lower average interest rates primarily resulting from the payoff of a
short-term revolving credit line held by CMS Enterprises during 2003.
INCOME TAXES: For the three months ended June 30, 2004, income taxes
increased versus the same period in 2003 primarily due to higher earnings.
For the six months ended June 30, 2004, income taxes decreased versus the
same period in 2003 due to the impairment charge for Loy Yang.
OTHER RESULTS OF OPERATIONS
In Millions
----------------------------------------------------------------------
June 30 2004 2003 Change
------------------ ------------ ------------ ------------
Three months ended $ (50) $ (60) $ 10
Six months ended $ (98) $ (111) $ 13
For the three months ended June 30, 2004, corporate interest expense and
other net expenses were $50 million, a decrease of $10 million from the three
months ended June 30, 2003. The decrease reflects the absence of a $24 million
deferred tax asset valuation reserve established in 2003 and also reflects $10
million of lower interest expense. This decrease was offset partially by the
absence in 2004 of a $20 million MSBT refund amount that we received in 2003 and
a $4 million increase in operating expenses that were not billed to
subsidiaries.
For the six months ended June 30, 2004, corporate interest and other net
expenses were $98 million, a decrease of $13 million from the six months ended
June 30, 2003. The decrease reflects the absence of a $24 million deferred tax
asset valuation reserve established in 2003 and $8 million of lower interest
expense. This decrease was offset partially by the absence of a $20 million MSBT
refund in 2003.
OTHER: At June 30, 2004, Discontinued Operations includes Parmelia. At
June 30, 2003, Discontinued Operations included CMS Field Services, Marysville,
and Parmelia. For additional details, see Note 2, Discontinued Operations, Other
Asset Sales, Impairments, and Restructuring.
A $24 million loss for the cumulative effect of changes in accounting
principle was recognized in the first quarter of 2003; $23 million was due to
EITF Issue No. 02-03; $1 million was due to SFAS No. 143.
CRITICAL ACCOUNTING POLICIES
The following accounting policies are important to an understanding of our
results of operations and financial condition and should be considered an
integral part of our MD&A:
- use of estimates in accounting for long-lived assets, contingencies,
and equity method investments,
- accounting for the effects of industry regulation,
- accounting for financial and derivative instruments,
61
- accounting for international operations and foreign currency,
- accounting for pension and postretirement benefits,
- accounting for asset retirement obligations, and
- accounting for nuclear decommissioning costs.
For additional accounting policies, see Note 1, Corporate Structure and
Accounting Policies.
USE OF ESTIMATES AND ASSUMPTIONS
In preparing our financial statements, we use estimates and assumptions
that may affect reported amounts and disclosures. Accounting estimates are used
for asset valuations, depreciation, amortization, financial and derivative
instruments, employee benefits, and contingencies. For example, we estimate the
rate of return on plan assets and the cost of future health-care benefits to
determine our annual pension and other postretirement benefit costs. There are
risks and uncertainties that may cause actual results to differ from estimated
results, such as changes in the regulatory environment, competition, foreign
exchange, regulatory decisions, and lawsuits.
LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the
recoverability of long-lived assets and equity method investments involves
critical accounting estimates. Tests of impairment are performed periodically if
certain conditions that are other than temporary exist that may indicate the
carrying value may not be recoverable. Of our total assets, recorded at $15.307
billion at June 30, 2004, 61 percent represent long-lived assets and equity
method investments that are subject to this type of analysis. We base our
evaluations of impairment on such indicators as:
- the nature of the assets,
- projected future economic benefits,
- domestic and foreign regulatory and political environments,
- state and federal regulatory and political environments,
- historical and future cash flow and profitability measurements, and
- other external market conditions or factors.
If an event occurs or circumstances change in a manner that indicates the
recoverability of a long-lived asset should be assessed, we evaluate the asset
for impairment. An asset held-in-use is evaluated for impairment by calculating
the undiscounted future cash flows expected to result from the use of the asset
and its eventual disposition. If the undiscounted future cash flows are less
than the carrying amount, we recognize an impairment loss. The impairment loss
recognized is the amount by which the carrying amount exceeds the fair value. We
estimate the fair market value of the asset utilizing the best information
available. This information includes quoted market prices, market prices of
similar assets, and discounted future cash flow analyses. An asset considered
held-for-sale is recorded at the lower of its carrying amount or fair value,
less cost to sell.
We also assess our ability to recover the carrying amounts of our equity
method investments. This assessment requires us to determine the fair values of
our equity method investments. The determination of fair value is based on
valuation methodologies including discounted cash flows and the ability of the
investee to sustain an earnings capacity that justifies the carrying amount of
the investment. We also consider the existence of CMS Energy guarantees on
obligations of the investee or other commitments to provide further financial
support. If the fair value is less than the carrying value and the decline in
value is considered to be other than temporary, an appropriate write-down is
recorded.
62
Our assessments of fair value using these valuation methodologies
represent our best estimates at the time of the reviews and are consistent with
our internal planning. The estimates we use can change over time. If fair values
were estimated differently, they could have a material impact on our financial
statements.
In March 2004, we reduced the carrying amount of our investment in Loy
Yang to reflect its fair value. We completed the sale of Loy Yang in April 2004.
For additional details on asset sales, see Note 2, Discontinued Operations,
Other Asset Sales, Impairments, and Restructuring. We are still pursuing the
sale of our remaining non-strategic and under-performing assets, including some
assets that were not determined to be impaired. Upon the sale of these assets,
the proceeds realized may be materially different from the remaining carrying
values. Even though these assets have been identified for sale, we cannot
predict when, or make any assurances that, these asset sales will occur.
Further, we cannot predict the amount of cash or the value of consideration that
may be received.
CONTINGENCIES: We are involved in various regulatory and legal proceedings
that arise in the ordinary course of our business. We record a liability for
contingencies based upon our assessment that the occurrence is probable and,
where determinable, an estimate of the liability amount. The recording of
estimated liabilities for contingencies is guided by the principles in SFAS No.
5. We consider many factors in making these assessments, including history and
the specifics of each matter. The most significant of these contingencies are
our electric and gas environmental estimates, which are discussed in the
"Outlook" section included in this MD&A, and the potential underrecoveries from
our power purchase contract with the MCV Partnership.
MCV UNDERRECOVERIES: The MCV Partnership, which leases and operates the
MCV Facility, contracted to sell electricity to Consumers for a 35-year period
beginning in 1990 and to supply electricity and steam to Dow. We hold a 49
percent partnership interest in the MCV Partnership, and a 35 percent lessor
interest in the MCV Facility.
Under our PPA with the MCV Partnership, we pay a capacity charge based on
the availability of the MCV Facility whether or not electricity is actually
delivered to us; a variable energy charge for kWh delivered to us; and a fixed
energy charge based on availability up to 915 MW and based on delivery for the
remaining 325 MW of contract capacity. The cost that we incur under the MCV
Partnership PPA exceeds the recovery amount allowed by the MPSC. As a result, we
estimate cash underrecoveries of capacity and fixed energy payments will
aggregate $206 million from 2004 through 2007. For capacity and fixed energy
payments billed by the MCV Partnership after September 15, 2007, and not
recovered from customers, we expect to claim relief under a regulatory out
provision under the MCV Partnership PPA. This provision obligates Consumers to
pay the MCV Partnership only those capacity and energy charges that the MPSC has
authorized for recovery from electric customers. The effect of any such action
would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse
effect on our investment, and
- eliminate our underrecoveries for capacity and fixed energy
payments.
Further, under the PPA, variable energy payments to the MCV Partnership
are based on the cost of coal burned in our coal plants and our operations and
maintenance expenses. However, the MCV Partnership's costs of producing
electricity are tied to the cost of natural gas. Because natural gas prices have
increased substantially in recent years and the price the MCV Partnership can
charge us for energy has not, the MCV Partnership's financial performance has
been affected adversely.
As a result of returning to the PSCR process on January 1, 2004, we
returned to dispatching the MCV Facility on a fixed load basis, as permitted by
the MPSC, in order to maximize recovery from electric customers of our capacity
and fixed energy payments. This fixed load dispatch increases the MCV Facility's
output and electricity production costs, such as natural gas. As the spread
between the MCV Facility's variable electricity production costs and its energy
payment revenue widens, the MCV Partnership's financial performance and our
investment in the MCV Partnership is and will be affected adversely.
In February 2004, we filed the RCP with the MPSC that is intended to help
conserve natural gas and thereby improve our investment in the MCV Partnership,
without raising the costs paid by our electric customers. The plan's primary
objective is to dispatch the MCV Facility on the basis of natural gas market
prices, which will reduce the MCV Facility's annual production of electricity
and, as a result, reduce the MCV Facility's consumption of
63
natural gas by an estimated 30 to 40 bcf. This decrease in the quantity of
high-priced natural gas consumed by the MCV Facility will benefit Consumers'
ownership interest in the MCV Partnership. Presently, we are in settlement
discussions with the parties to the RCP filing. However, in July 2004, several
qualifying facilities filed for a stay on the RCP proceeding in the Ingham
County Circuit Court after their previous attempt to intervene on the proceeding
was denied by the MPSC. Hearings on the stay are scheduled for August 11, 2004.
We cannot predict if or when the MPSC will approve the RCP or the outcome of the
Ingham County Circuit Court hearings.
The two most significant variables in the analysis of the MCV
Partnership's future financial performance are the forward price of natural gas
for the next 20 years and the MPSC's decision in 2007 or beyond related to
limiting our recovery of capacity and fixed energy payments. Natural gas prices
have been volatile historically. Presently, there is no consensus in the
marketplace on the price or range of future prices of natural gas. Even with an
approved RCP, if gas prices continue at present levels or increase, the
economics of operating the MCV Facility may be adverse enough to require us to
recognize an impairment of our investment in the MCV Partnership. We presently
cannot predict the impact of these issues on our future earnings, cash flows, or
on the value of our investment in the MCV Partnership.
For additional details on the MCV Partnership, see Note 3, Uncertainties,
"Other Consumers' Electric Utility Uncertainties - The Midland Cogeneration
Venture."
ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES, AND
MARKET RISK INFORMATION
FINANCIAL INSTRUMENTS: We account for investments in debt and equity
securities using SFAS No. 115. Debt and equity securities can be classified into
one of three categories: held-to-maturity, trading, or available-for-sale
securities. Our debt securities are classified as held-to-maturity securities
and are reported at cost. Our investments in equity securities are classified as
available-for-sale securities. They are reported at fair value, with any
unrealized gains or losses resulting from changes in fair value reported in
equity as part of accumulated other comprehensive income and are excluded from
earnings unless such changes in fair value are determined to be other than
temporary. Unrealized gains or losses resulting from changes in the fair value
of our nuclear decommissioning investments are reflected in Regulatory
Liabilities. The fair value of our equity securities is determined from quoted
market prices.
DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133, as amended
and interpreted, to determine if certain contracts must be accounted for as
derivative instruments. The rules for determining whether a contract meets the
criteria for derivative accounting are numerous and complex. Moreover,
significant judgment is required to determine whether a contract requires
derivative accounting, and similar contracts can sometimes be accounted for
differently.
If a contract is accounted for as a derivative instrument, it is recorded
in the financial statements as an asset or a liability, at the fair value of the
contract. The recorded fair value of the contract is then adjusted quarterly to
reflect any change in the market value of the contract, a practice known as
marking the contract to market. Changes in the fair value of a derivative (that
is, gains or losses) are reported either in earnings or accumulated other
comprehensive income depending on whether the derivative qualifies for special
hedge accounting treatment.
The types of contracts we typically classify as derivative instruments are
interest rate swaps, foreign currency exchange contracts, electric call options,
gas fuel futures and options, gas fuel contracts containing volume optionality,
fixed priced weather-based gas supply call options, fixed price gas supply call
and put options, gas futures, gas and power swaps, and forward purchases and
sales. We generally do not account for electric capacity and energy contracts,
gas supply contracts, coal and nuclear fuel supply contracts, or purchase orders
for numerous supply items as derivatives.
The majority of our contracts are not subject to derivative accounting
because they qualify for the normal purchases and sales exception of SFAS No.
133, or are not derivatives because there is not an active market for the
commodity. Certain of our electric capacity and energy contracts are not
accounted for as derivatives due to the lack of an active energy market in the
state of Michigan, as defined by SFAS No. 133, and the significant
transportation costs that would be incurred to deliver the power under the
contracts to the closest active energy market at the Cinergy hub in Ohio. If an
active market develops in the future, we may be required to account for these
contracts
64
as derivatives. The mark-to-market impact on earnings related to these contracts
could be material to our financial statements.
Additionally, the MCV Partnership uses natural gas fuel contracts to buy
gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership
believes that its long-term natural gas contracts, which do not contain volume
optionality, qualify under SFAS No. 133 for the normal purchases and normal
sales exception. Therefore, these contracts are currently not recognized at fair
value on the balance sheet. Should significant changes in the level of the MCV
Facility operational dispatch or purchases of long-term gas occur, the MCV
Partnership would be required to re-evaluate its accounting treatment for these
long-term gas contracts. This re-evaluation may result in recording
mark-to-market activity on some contracts, which could add to earnings
volatility.
To determine the fair value of contracts that are accounted for as
derivative instruments, we use a combination of quoted market prices and
mathematical valuation models. Valuation models require various inputs,
including forward prices, volatilities, interest rates, and exercise periods.
Changes in forward prices or volatilities could change significantly the
calculated fair value of certain contracts. At June 30, 2004, we assumed a
market-based interest rate of 1 percent (a rate that is not significantly
different than the LIBOR rate) and volatility rates ranging between 54 percent
and 161 percent to calculate the fair value of our electric and gas options. At
June 30, 2004, we assumed market-based interest rates ranging between 1.37
percent and 4.50 percent and volatility rates ranging between 24 percent and 44
percent to calculate the fair value of the gas fuel derivative contracts held by
the MCV Partnership.
TRADING ACTIVITIES: CMS ERM enters into and owns energy contracts that are
related to activities considered an integral part of CMS Energy's ongoing
operations. The intent of holding these energy contracts is to optimize the
financial performance of our owned generating assets and to fulfill contractual
obligations. These contracts are classified as trading activities in accordance
with EITF Issue No. 02-03 and are accounted for using the criteria defined in
SFAS No. 133. Energy trading contracts that meet the definition of a derivative
are recorded as assets or liabilities in the financial statements at the fair
value of the contracts. Gains or losses arising from changes in fair value of
these contracts are recognized into earnings in the period in which the changes
occur. Energy trading contracts that do not meet the definition of a derivative
are accounted for as executory contracts (i.e., on an accrual basis).
The market prices we use to value our energy trading contracts reflect our
consideration of, among other things, closing exchange and over-the-counter
quotations. In certain contracts, long-term commitments may extend beyond the
period in which market quotations for such contracts are available. Mathematical
models are developed to determine various inputs into the fair value calculation
including price and other variables that may be required to calculate fair
value. Realized cash returns on these commitments may vary, either positively or
negatively, from the results estimated through application of the mathematical
model. Market prices are adjusted to reflect the impact of liquidating our
position in an orderly manner over a reasonable period of time under present
market conditions.
In connection with the market valuation of our energy trading contracts,
we maintain reserves for credit risks based on the financial condition of
counterparties. We also maintain credit policies that management believes will
minimize its overall credit risk with regard to our counterparties.
Determination of our counterparties' credit quality is based upon a number of
factors, including credit ratings, disclosed financial condition, and collateral
requirements. Where contractual terms permit, we employ standard agreements that
allow for netting of positive and negative exposures associated with a single
counterparty. Based on these policies, our current exposures, and our credit
reserves, we do not anticipate a material adverse effect on our financial
position or results of operations as a result of counterparty nonperformance.
The following tables provide a summary of the fair value of our energy
trading contracts as of June 30, 2004:
In Millions
-----------
Fair value of contracts outstanding as of December 31, 2003 $ 15
Fair value of new contracts when entered into during the period (a) (3)
Changes in fair value attributable to changes in valuation techniques and assumptions -
Contracts realized or otherwise settled during the period (11)
Other changes in fair value (b) 9
----
Fair value of contracts outstanding as of June 30, 2004 $ 10
====
65
(a) Reflects only the initial premium payments/(receipts) for new contracts. No
unrealized gains or losses were recognized at the inception of any new
contracts.
(b) Reflects changes in price and net increase/(decrease) of forward positions
as well as changes to mark-to-market and credit reserves.
Fair Value of Contracts at June 30, 2004 In Millions
---------------------------------------- -----------
Total Maturity (in years)
Source of Fair Value Fair Value Less than 1 1 to 3 4 to 5 Greater than 5
-------------------------- ---------- ----------- ---------- ---------- ---------------
Prices actively quoted $ (28) $ (1) $ (12) $ (15) $ -
Prices based on models and
other valuation methods 38 8 18 12 -
---------- ---------- ---------- ---------- ---------------
Total $ 10 $ 7 $ 6 $ (3) $ -
========== ========== ========== ========== ===============
MARKET RISK INFORMATION: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, currency exchange
rates, and equity security prices. We manage these risks using established
policies and procedures, under the direction of both an executive oversight
committee consisting of senior management representatives and a risk committee
consisting of business-unit managers. We may use various contracts to manage
these risks, including swaps, options, futures, and forward contracts.
Contracts used to manage market risks may be considered derivative
instruments that are subject to derivative and hedge accounting pursuant to SFAS
No. 133. We intend that any gains or losses on these contracts will be offset by
an opposite movement in the value of the item at risk. Risk management contracts
are classified as either trading or other than trading. These contracts contain
credit risk if the counterparties, including financial institutions and energy
marketers, fail to perform under the agreements. We minimize such risk by
performing financial credit reviews using, among other things, publicly
available credit ratings of such counterparties.
We perform sensitivity analyses to assess the potential loss in fair
value, cash flows, or future earnings based upon a hypothetical 10 percent
adverse change in market rates or prices. We do not believe that sensitivity
analyses alone provide an accurate or reliable method for monitoring and
controlling risks. Therefore, we use our experience and judgment to revise
strategies and modify assessments. Changes in excess of the amounts determined
in sensitivity analyses could occur if market rates or prices exceed the 10
percent shift used for the analyses. These risk sensitivities are shown in
"Interest Rate Risk," "Commodity Price Risk," "Trading Activity Commodity Price
Risk," "Currency Exchange Risk," and "Equity Securities Price Risk" within this
section.
Interest Rate Risk: We are exposed to interest rate risk resulting from
issuing fixed-rate and variable-rate financing instruments, and from interest
rate swap agreements. We use a combination of these instruments to manage this
risk as deemed appropriate, based upon market conditions. These strategies are
designed to provide and maintain a balance between risk and the lowest cost of
capital.
Interest Rate Risk Sensitivity Analysis (assuming a 10 percent adverse
change in market interest rates):
In Millions
-----------------------------------------------------------------------------------------------------
June 30, 2004 December 31, 2003
------------- -----------------
Variable-rate financing - before tax annual earnings exposure $ 1 $ 1
Fixed-rate financing - potential loss in fair value (a) 240 242
===== =====
(a) Fair value exposure could only be realized if we repurchased all of our
fixed-rate financing.
As discussed in "Electric Utility Business Uncertainties - Competition and
Regulatory Restructuring - Securitization" within this MD&A, we have filed an
application with the MPSC to securitize certain expenditures. Upon final
approval, we intend to use the proceeds from the Securitization to retire
higher-cost debt, which could include a portion of our current fixed-rate debt.
We do not believe that any adverse change in debt price and interest
66
rates would have a material adverse effect on either our consolidated financial
position, results of operations, or cash flows.
Certain equity method investees have issued interest rate swaps. These
instruments are not required to be included in the sensitivity analysis, but can
have an impact on financial results.
Commodity Price Risk: For purposes other than trading, we enter into
electric call options, fixed-priced weather-based gas supply call options, and
fixed-priced gas supply call and put options. Electric call options are
purchased to protect against the risk of fluctuations in the market price of
electricity, and to ensure a reliable source of capacity to meet our customers'
electric needs. Purchased electric call options give us the right, but not the
obligation, to purchase electricity at predetermined fixed prices. Purchases of
gas supply call options and weather-based gas supply call options, coupled with
the sale of gas supply put options, are used to purchase reasonably priced gas
supply. Purchases of gas supply call options give us the right, but not the
obligation, to purchase gas supply at predetermined fixed prices. Gas supply put
options sold give third-party suppliers the right, but not the obligation, to
sell gas supply to us at predetermined fixed prices. At June 30, 2004, we held
fixed-priced weather-based gas supply call options and fixed-price gas supply
call and put options.
The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for
generation, and to manage gas fuel costs. Some of these contracts contain volume
optionality and, therefore, are treated as derivative instruments. Also, the MCV
Partnership enters into natural gas futures contracts, option contracts, and
over-the-counter swap transactions in order to hedge against unfavorable changes
in the market price of natural gas in future months when gas is expected to be
needed. These financial instruments are being used principally to secure
anticipated natural gas requirements necessary for projected electric and steam
sales, and to lock in sales prices of natural gas previously obtained in order
to optimize the MCV Partnership's existing gas supply, storage, and
transportation arrangements.
Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse
change in market prices):
In Millions
----------------------------------
June 30, 2004 December 31, 2003
------------- -----------------
Potential reduction in fair value:
Gas supply option contracts $ 7 $ 1
Derivative contracts associated with Consumers' investment
in the MCV Partnership:
Gas fuel contracts 21 N/A
Gas fuel futures, options, and swaps 38 N/A
============= =================
During the six months ended June 30, 2004, we entered into additional
weather-based gas supply call options, as well as gas supply call and put option
contracts. As a result, the potential reduction in the fair value increased from
December 31, 2003 as shown in the table above. We did not perform a sensitivity
analysis for the derivative contracts held by the MCV Partnership as of December
31, 2003 because the MCV Partnership was not consolidated into our financial
statements until March 31, 2004, as discussed in Note 11, Implementation of New
Accounting Standards.
Trading Activity Commodity Price Risk: We are exposed to market
fluctuations in the price of energy commodities. We employ established policies
and procedures to manage these risks and may use various commodity derivatives,
including futures, options, and swap contracts. The prices of these energy
commodities can fluctuate because of, among other things, changes in the supply
of and demand for the commodities.
67
Trading Activity Commodity Price Risk Sensitivity Analysis (assuming a 10
percent adverse change in market prices):
In Millions
------------------------------------
June 30, 2004 December 31, 2003
-------------- -----------------
Potential reduction in fair value:
Gas-related swaps and forward contracts $ 3 $ 3
Electricity-related forward contracts 2 2
Electricity-related call option contracts 2 1
============= =================
Currency Exchange Risk: We are exposed to currency exchange risk arising
from investments in foreign operations as well as various international projects
in which we have an equity interest and which have debt denominated in U.S.
dollars. We typically use forward exchange contracts and other risk mitigating
instruments to hedge currency exchange rates. The impact of hedges on our
investments in foreign operations is reflected in accumulated other
comprehensive income as a component of the foreign currency translation
adjustment on the Consolidated Balance Sheets. Gains or losses from the
settlement of these hedges are maintained in the foreign currency translation
adjustment until we sell or liquidate the investments on which the hedges were
taken. At June 30, 2004, we had no foreign exchange hedging contracts
outstanding. As of June 30, 2004, the total foreign currency translation
adjustment was a net loss of $327 million, which included a net hedging loss of
$25 million, net of tax, related to settled contracts.
Equity Securities Price Risk: We are exposed to price risk associated with
investments in equity securities. As discussed in "Financial Instruments" within
this section, our investments in equity securities are classified as
available-for-sale securities. They are reported at fair value, with any
unrealized gains or losses resulting from changes in fair value reported in
equity as part of accumulated other comprehensive income and are excluded from
earnings unless such changes in fair value are determined to be other than
temporary. Unrealized gains or losses resulting from changes in the fair value
of our nuclear decommissioning investments are reflected in Regulatory
Liabilities. Our debt securities are classified as held-to-maturity securities
and have original maturity dates of approximately one year or less. Because of
the short maturity of these instruments, their carrying amounts approximate
their fair values.
Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent
adverse change in market prices):
In Millions
-------------- -----------------
June 30, 2004 December 31, 2003
-------------- -----------------
Potential reduction in fair value:
Nuclear decommissioning investments $ 54 $ 57
Other available-for-sale investments 7 7
============== =================
For additional details on market risk and derivative activities, see Note
6, Financial and Derivative Instruments.
INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY
We have investments in energy-related projects in selected markets around
the world. As a result of a change in business strategy, we have been selling
certain foreign investments. For additional details on the divestiture of
foreign investments, see Note 2, Discontinued Operations, Other Asset Sales,
Impairments, and Restructuring.
BALANCE SHEET: Our subsidiaries and affiliates whose functional currency
is other than the U.S. dollar translate their assets and liabilities into U.S.
dollars at the exchange rates in effect at the end of the fiscal period. Gains
or losses that result from this translation and gains or losses on long-term
intercompany foreign currency transactions are reflected as a component of
stockholders' equity in our Consolidated Balance Sheets as "Foreign Currency
Translation." As of June 30, 2004, cumulative foreign currency translation
decreased stockholders' equity by $327 million. We translate the revenue and
expense accounts of these subsidiaries and affiliates into U.S. dollars at the
average exchange rate during the period.
Australia: The Foreign Currency Translation component of stockholders'
equity at December 31, 2003 included an approximate $110 million unrealized net
foreign currency translation loss related to our investment in Loy Yang. In
March 2004, we recognized the foreign currency translation loss in earnings as a
component of the Loy Yang
68
impairment of approximately $81 million, recorded as a result of the sale of Loy
Yang that was completed in April 2004.
At June 30, 2004, the net foreign currency loss due to the exchange rate
of the Australian dollar recorded in the Foreign Currency Translation component
of stockholders' equity using an exchange rate of 1.45 Australian dollars per
U.S. dollar was $4 million. This foreign currency translation loss relates
primarily to our SCP and Parmelia investments. We are currently pursuing the
sale of these investments.
Argentina: In January 2002, the Republic of Argentina enacted the Public
Emergency and Foreign Exchange System Reform Act. This law repealed the fixed
exchange rate of one U.S. dollar to one Argentine peso, converted all
dollar-denominated utility tariffs and energy contract obligations into pesos at
the same one-to-one exchange rate, and directed the President of Argentina to
renegotiate such tariffs.
Effective April 30, 2002, we adopted the Argentine peso as the functional
currency for our Argentine investments. We had used previously the U.S. dollar
as the functional currency. As a result, we translated the assets and
liabilities of our Argentine entities into U.S. dollars using an exchange rate
of 3.45 pesos per U.S. dollar, and recorded an initial charge to the Foreign
Currency Translation component of stockholders' equity of $400 million.
While we cannot predict future peso-to-U.S. dollar exchange rates, we do
expect that these non-cash charges reduce substantially the risk of further
material balance sheet impacts when combined with anticipated proceeds from
international arbitration currently in progress, political risk insurance, and
the eventual sale of these assets. At June 30, 2004, the net foreign currency
loss due to the unfavorable exchange rate of the Argentine peso recorded in the
Foreign Currency Translation component of stockholders' equity using an exchange
rate of 2.97 pesos per U.S. dollar was $263 million. This amount also reflects
the effect of recording, at December 31, 2002, U.S. income taxes on temporary
differences between the book and tax bases of foreign investments, including the
foreign currency translation associated with our Argentine investments.
INCOME STATEMENT: We use the U.S. dollar as the functional currency of
subsidiaries operating in highly inflationary economies and of subsidiaries that
meet the U.S. dollar functional currency criteria outlined in SFAS No. 52. Gains
and losses that arise from transactions denominated in a currency other than the
U.S. dollar, except those that are hedged, are included in determining net
income.
HEDGING STRATEGY: We may use forward exchange and option contracts to
hedge certain receivables, payables, long-term debt, and equity value relating
to foreign investments. The purpose of our foreign currency hedging activities
is to reduce risk associated with adverse changes in currency exchange rates
that could affect cash flow materially. These contracts would not subject us to
risk from exchange rate movements because gains and losses on such contracts are
inversely correlated with the losses and gains, respectively, on the assets and
liabilities being hedged.
ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION
Because we are involved in a regulated industry, regulatory decisions
affect the timing and recognition of revenues and expenses. We use SFAS No. 71
to account for the effects of these regulatory decisions. As a result, we may
defer or recognize revenues and expenses differently than a non-regulated
entity.
For example, items that a non-regulated entity normally would expense, we
may record as regulatory assets if the actions of the regulator indicate such
expenses will be recovered in future rates. Conversely, items that non-regulated
entities may normally recognize as revenues, we may record as regulatory
liabilities if the actions of the regulator indicate they will require such
revenues be refunded to customers. Judgment is required to determine the
recoverability of items recorded as regulatory assets and liabilities. As of
June 30, 2004, we had $1.125 billion recorded as regulatory assets and $1.502
billion recorded as regulatory liabilities.
For additional details on industry regulation, see Note 1, Corporate
Structure and Accounting Policies, "Utility Regulation."
69
ACCOUNTING FOR PENSION AND OPEB
Pension: We have established external trust funds to provide retirement
pension benefits to our employees under a non-contributory, defined benefit
Pension Plan. We have implemented a cash balance plan for certain employees
hired after June 30, 2003. We use SFAS No. 87 to account for pension costs.
401(k): In our efforts to reduce costs, the employer's match for the
401(k) plan was suspended effective September 1, 2002. The employer's match for
the 401(k) plan is scheduled to resume on January 1, 2005.
OPEB: We provide postretirement health and life benefits under our OPEB
plan to substantially all our retired employees. We use SFAS No. 106 to account
for other postretirement benefit costs. Liabilities for both pension and OPEB
are recorded on the balance sheet at the present value of their future
obligations, net of any plan assets. The calculation of the liabilities and
associated expenses requires the expertise of actuaries. Many assumptions are
made including:
- life expectancies,
- present-value discount rates,
- expected long-term rate of return on plan assets,
- rate of compensation increases, and
- anticipated health care costs.
Any change in these assumptions can change significantly the liability and
associated expenses recognized in any given year.
The following table provides an estimate of our pension cost, OPEB cost,
and cash contributions for the next three years:
In Millions
-------------------------------------------------------------------
Expected Costs Pension Cost OPEB Cost Contributions
--------------- ------------ --------- -------------
2004 $ 21 $ 30 $ 63
2005 55 38 80
2006 75 34 114
============ ========= =============
Actual future pension cost and contributions will depend on future
investment performance, changes in future discount rates, and various other
factors related to the populations participating in the Pension Plan. As of June
30, 2004, we have a prepaid pension asset of $398 million, $20 million of which
is in Other current assets on our Consolidated Balance Sheet.
Lowering the expected long-term rate of return on the Pension Plan assets
by 0.25 percent (from 8.75 percent to 8.50 percent) would increase estimated
pension cost for 2004 by $2 million. Lowering the discount rate by 0.25 percent
(from 6.25 percent to 6.00 percent) would increase estimated pension cost for
2004 by $4 million.
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003
(the Act) was signed into law in December 2003. The Act establishes a
prescription drug benefit under Medicare (Medicare Part D) and a federal
subsidy, which is exempt from federal taxation, to sponsors of retiree health
care benefit plans that provide a benefit that is actuarially equivalent to
Medicare Part D.
We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004 in accordance with FASB Staff Position No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $158 million. The remeasurement resulted in
70
a reduction of OPEB cost of $6 million for the three months ended June 30, 2004,
$12 million for the six months ended June 30, 2004, and an expected total
reduction of $24 million for 2004.
For additional details on postretirement benefits, see Note 7, Retirement
Benefits and Note 11, Implementation of New Accounting Standards.
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
SFAS No. 143 became effective January 2003. It requires companies to
record the fair value of the cost to remove assets at the end of their useful
lives, if there is a legal obligation to remove them. We have legal obligations
to remove some of our assets, including our nuclear plants, at the end of their
useful lives. As required by SFAS No. 71, we accounted for the implementation of
this standard by recording regulatory assets and liabilities for regulated
entities instead of a cumulative effect of a change in accounting principle.
The fair value of ARO liabilities has been calculated using an expected
present value technique. This technique reflects assumptions, such as costs,
inflation, and profit margin that third parties would consider to assume the
settlement of the obligation. Fair value, to the extent possible, should include
a market risk premium for unforeseeable circumstances. No market risk premium
was included in our ARO fair value estimate since a reasonable estimate could
not be made.
If a reasonable estimate of fair value cannot be made in the period the
ARO is incurred, such as for assets with indeterminate lives, the liability is
recognized when a reasonable estimate of fair value can be made. Generally,
transmission and distribution assets have indeterminate lives. Retirement cash
flows cannot be determined and there is a low probability of a retirement date.
Therefore, no liability has been recorded for these assets. Also, no liability
has been recorded for assets that have insignificant cumulative disposal costs,
such as substation batteries. The measurement of the ARO liabilities for
Palisades and Big Rock are based on decommissioning studies, which largely
utilize third-party cost estimates. For additional details on ARO, see Note 10,
Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and the FERC regulate the recovery of costs to decommission our
Big Rock and Palisades nuclear plants. We have established external trust funds
to finance the decommissioning of both plants. We record the trust fund balances
as a non-current asset on our balance sheet.
Our decommissioning cost estimates for the Big Rock and Palisades plants
assume:
- each plant site will be restored to conform to the adjacent
landscape,
- all contaminated equipment and material will be removed and disposed
of in a licensed burial facility, and
- the site will be released for unrestricted use.
Independent contractors with expertise in decommissioning have helped us
develop decommissioning cost estimates. Various inflation rates for labor,
non-labor, and contaminated equipment disposal costs are used to escalate these
cost estimates to the future decommissioning cost. A portion of future
decommissioning cost will result from the failure of the DOE to remove fuel from
the sites, as required by the Nuclear Waste Policy Act of 1982.
The decommissioning trust funds include equities and fixed income
investments. Equities will be converted to fixed income investments during
decommissioning, and fixed income investments are converted to cash as needed.
In December 2000, funding of the Big Rock trust fund stopped because the
MPSC-authorized decommissioning surcharge collection period expired. The funds
provided by the trusts, additional customer surcharges, and potential funds from
the DOE litigation are all required to cover fully the decommissioning costs.
The costs of decommissioning these sites and the adequacy of the trust funds
could be affected by:
71
- variances from expected trust earnings,
- a lower recovery of costs from the DOE and lower rate recovery from
customers, and
- changes in decommissioning technology, regulations, estimates, or
assumptions.
Based on current projections, the current level of funds provided by the
trusts is not adequate to fully fund the decommissioning of Big Rock or
Palisades. This is due in part to the DOE's failure to accept the spent nuclear
fuel on schedule, and lower returns on the trust funds. We are attempting to
recover our additional costs for storing spent nuclear fuel through litigation.
We will also seek additional relief from the MPSC. For additional details on
nuclear decommissioning, see Note 3, Uncertainties, "Other Consumers' Electric
Utility Uncertainties - Nuclear Plant Decommissioning" and "Nuclear Matters."
CAPITAL RESOURCES AND LIQUIDITY
Our liquidity and capital requirements are a function of our results of
operations, capital expenditures, contractual obligations, debt maturities,
working capital needs, and collateral requirements. During the summer months, we
purchase natural gas and store it for resale primarily during the winter heating
season. The market price for natural gas has increased. Although our natural gas
purchases are recoverable from our customers, the amount paid for natural gas
stored as inventory could require additional liquidity due to the timing of the
cost recoveries. In addition, a few of our commodity suppliers have requested
advance payment or other forms of assurances, including margin calls, in
connection with maintenance of ongoing deliveries of gas and electricity.
Our current financial plan includes controlling our operating expenses and
capital expenditures, evaluating market conditions for financing opportunities,
and selling assets that are not consistent with our strategy. The sale of assets
is expected to generate cash in 2004; however, it is not critical to the
maintenance of sufficient corporate liquidity. We believe our current level of
cash and borrowing capacity, along with anticipated cash flows from operating
and investing activities, will be sufficient to meet our liquidity needs through
2005. We have not made a specific determination concerning the reinstatement of
the payment of common stock dividends. The Board of Directors may reconsider or
revise its dividend policy based upon certain conditions, including our results
of operations, financial condition, and capital requirements, as well as other
relevant factors.
CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash
needs. At June 30, 2004, $909 million consolidated cash was on hand, which
includes $213 million of restricted cash. For additional details on cash
equivalents and restricted cash, see Note 1, Corporate Structure and Accounting
Policies.
Our primary ongoing source of cash is dividends and other distributions
from our subsidiaries, including proceeds from asset sales. For the first six
months of 2004, Consumers paid $105 million in common stock dividends and
Enterprises paid $133 million in common stock dividends and other distributions
to CMS Energy.
SUMMARY OF CASH FLOWS:
In Millions
------------------------------------------------------------------------------
Six months ended June 30 2004 2003
---------------------------------------------------- ----------------------
Net cash provided by (used in):
Operating activities $ 481 $ 147
Investing activities (214) 292
Financing activities (276) 125
Effect of exchange rates on cash (1) 2
-------- -----------
Net increase (decrease) in cash and cash equivalents $ (10) $ 566
======== ===========
72
OPERATING ACTIVITIES:
For the six months ended June 30, 2004, net cash provided by operating
activities increased $334 million compared to the six months ended June 30, 2003
primarily due to an increase in accounts payable and accrued expenses of $364
million. The increase in accounts payable is mainly a result of the purchase of
natural gas at higher prices and fewer suppliers requiring advanced payments for
gas purchases. Also, CMS ERM had a minimal change in accounts payable in 2004
versus a large decrease in 2003 resulting from the sale of the wholesale gas and
power books. Accrued expenses increased as a result of the Revised FASB
Interpretation No. 46 consolidation of the MCV Partnership and the FMLP, a
smaller decrease in accrued taxes, and an increase in accrued refunds relating
to our 2002-2003 GCR case and potential overrecoveries from our return to the
PSCR process. For additional details regarding the PSCR process refer to
"Electric Utility Business Uncertainties - PSCR" within this MD&A.
Additionally, net cash provided by operating activities increased as a
result of a decrease in inventories of $83 million primarily resulting from gas
sales at higher prices combined with lower volumes of gas purchased. This was
offset by a greater increase in accounts receivable and accrued revenue of $43
million largely due to lower sales of accounts receivable resulting from our
improved liquidity.
INVESTING ACTIVITIES:
For the six months ended June 30, 2004, net cash from investing activities
decreased $506 million primarily due to a decrease in asset sale proceeds of
$660 million. This change was offset by a decrease in capital expenditures of
$24 million and a decrease in the amount of cash restricted of $155 million. In
2004, $12 million in cash was restricted compared to $167 million restricted in
2003. For additional details on restricted cash, see Note 1, Corporate Structure
and Accounting Policies, "Cash Equivalents and Restricted Cash."
FINANCING ACTIVITIES:
For the six months ended June 30, 2004, net cash from financing activities
decreased $401 million primarily due to a decrease of $397 million in net
proceeds from borrowings. For additional details on long-term debt activity, see
Note 4, Financings and Capitalization.
OBLIGATIONS AND COMMITMENTS
REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers issues short and
long-term securities under the FERC's authorization. For additional details of
Consumers' existing authorization, see Note 4, Financings and Capitalization.
LONG-TERM DEBT: The components of long-term debt are presented in Note 4,
Financings and Capitalization.
SHORT-TERM FINANCINGS: At June 30, 2004, CMS Energy had $207 million
available, Consumers had $376 million available, and the MCV Partnership had $50
million available in short-term credit facilities. The facilities are available
for general corporate purposes, working capital, and letters of credit. As of
August 3, 2004, CMS Energy obtained an amended and restated $300 million secured
revolving credit facility to replace both their $190 million facility and $185
million letter of credit facility. As of August 3, 2004, Consumers obtained an
amended and restated $500 million secured revolving credit facility to replace
their $400 million facility. The amended facilities carry three-year terms and
provide for lower interest rates. Additional details on short-term financings
are presented in Note 4, Financings and Capitalization.
OFF-BALANCE SHEET ARRANGEMENTS:
Non-recourse Debt: Our share of unconsolidated debt associated with
partnerships and joint ventures in which we have a minority interest is
non-recourse and totals $1.491 billion at June 30, 2004. The reduction in this
amount from March 31, 2004 is primarily due to the sale of Loy Yang, whose
non-recourse debt totaled $1.226 billion. The timing of the payments of
non-recourse debt only affects the cash flow and liquidity of the partnerships
and joint ventures.
73
Sale of Accounts Receivable: Under a revolving accounts receivable sales
program, we may sell up to $325 million of certain accounts receivable. For
additional details, see Note 4, Financings and Capitalization.
CONTINGENT COMMITMENTS: Our contingent commitments include guarantees,
indemnities, and letters of credit. Guarantees represent our guarantees of
performance, commitments, and liabilities of our consolidated and unconsolidated
subsidiaries, partnerships, and joint ventures. Indemnities are agreements to
reimburse other companies, such as an insurance company, if those companies have
to complete our contractual performance in a third-party contract. Banks, on our
behalf, issue letters of credit guaranteeing payment to a third party. Letters
of credit substitute the bank's credit for ours and reduce credit risk for the
third-party beneficiary. We monitor and approve these obligations and believe it
is unlikely that we would be required to perform or otherwise incur any material
losses associated with these guarantees. Our off-balance sheet commitments at
June 30, 2004, expire as follows:
Commercial Commitments In Millions
-----------------------------------------------------------------------------------------
Commitment Expiration
------------------------------------------------------
2009 and
Total 2004 2005 2006 2007 2008 Beyond
----- ---- ----- ---- ---- ---- -----------
Off-balance sheet:
Guarantees $ 199 $ 6 $ 36 $ 5 $ - $ - $ 152
Surety bonds and other
indemnifications (a) 28 1 - - - - 27
Letters of Credit (b) 235 23 184 5 5 5 13
----- ---- ----- ---- ---- ---- -----------
Total $ 462 $ 30 $ 220 $ 10 $ 5 $ 5 $ 192
===== ==== ===== ==== ==== ==== ===========
(a) The surety bonds are continuous in nature. The need for the bonds is
determined on an annual basis.
(b) At June 30, 2004, we had $169 million of cash held as collateral for letters
of credit. The cash that collateralizes the letters of credit is included in
Restricted cash on the Consolidated Balance Sheets.
DIVIDEND RESTRICTIONS: Under the provisions of its articles of
incorporation, at June 30, 2004, Consumers had $396 million of unrestricted
retained earnings available to pay common stock dividends. However, covenants in
Consumers' debt facilities cap common stock dividend payments at $300 million in
a calendar year. Consumers is also under an annual dividend cap of $190 million
imposed by the MPSC during the current interim gas rate relief period. For the
six months ended June 30, 2004, CMS Energy received $105 million of common stock
dividends from Consumers.
Our amended and restated $300 million credit facility restricts payments
of dividends on our common stock during a 12-month period to $75 million,
dependent on the aggregate amounts of unrestricted cash and unused commitments
under the facility.
For additional details on the cap on common stock dividends payable during
the current interim gas rate relief period, see Note 3, Uncertainties,
"Consumers' Gas Utility Rate Matters - 2003 Gas Rate Case."
OUTLOOK
CORPORATE OUTLOOK
During 2004, we are continuing to implement a utility-plus strategy that
focuses on growing a healthy utility and divesting under-performing or other
non-strategic assets. The strategy is designed to generate cash to pay down
debt, reduce business risk, and provide for more predictable future operating
revenues and earnings.
Consistent with our utility-plus strategy, we are pursuing the sale of
non-strategic and under-performing assets. Some of these assets are recorded at
estimates of their current fair value. Upon the sale of these assets, the
proceeds realized may be different from the recorded values if market conditions
have changed. Even though these assets have been identified for sale, we cannot
predict when, nor make any assurance that, these sales will occur. We anticipate
that the cash proceeds from these sales, if any, will be used to retire existing
debt.
74
As we continue to implement our utility-plus strategy and further reduce
our ownership of non-utility assets, the percentage of our future earnings
relating to our larger equity method investments, including Jorf Lasfar, may
increase and our total future earnings may depend more significantly upon the
performance of those investments. For additional details, see Note 8, Equity
Method Investments.
ELECTRIC UTILITY BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect electric deliveries to grow at
an average rate of approximately two percent per year based primarily on a
steadily growing customer base and economy. This growth rate includes both full
service sales and delivery service to customers who choose to buy generation
service from an alternative electric supplier, but excludes transactions with
other wholesale market participants and other electric utilities. This growth
rate reflects a long-range expected trend of growth. Growth from year to year
may vary from this trend due to customer response to fluctuations in weather
conditions and changes in economic conditions, including utilization and
expansion of manufacturing facilities. We experienced less growth than expected
in 2003 as a result of cooler than normal summer weather and a decline in
manufacturing activity in Michigan. In 2004, we project electric deliveries to
grow approximately two percent. This short-term outlook for 2004 assumes higher
levels of manufacturing activity than in 2003 and normal weather conditions
during the remainder of the year.
ELECTRIC UTILITY BUSINESS UNCERTAINTIES
Several electric business trends or uncertainties may affect our financial
results and condition. These trends or uncertainties have, or we reasonably
expect could have, a material impact on revenues or income from continuing
electric operations. Such trends and uncertainties include:
Environmental
- increasing capital expenditures and operating expenses for Clean Air
Act compliance, and
- potential environmental liabilities arising from various
environmental laws and regulations, including potential liability or
expenses relating to the Michigan Natural Resources and
Environmental Protection Acts and Superfund.
Restructuring
- response of the MPSC and Michigan legislature to electric industry
restructuring issues,
- ability to meet peak electric demand requirements at a reasonable
cost, without market disruption,
- ability to recover any of our net Stranded Costs under the
regulatory policies being followed by the MPSC,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer instead of an electric
transmission owner.
Regulatory
- effects of recommendations as a result of the August 14, 2003
blackout, including increased regulatory requirements and new
legislation,
- effects of the FERC supply margin assessment requirements for
electric market-based rate authority,
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel, and
- recovery of nuclear decommissioning costs. For additional details,
see "Accounting for Nuclear Decommissioning Costs" within this MD&A.
75
Other
- effects of commodity fuel prices such as natural gas and coal,
- pending litigation filed by PURPA qualifying facilities, and
- other pending litigation.
For additional details about these trends or uncertainties, see Note 3,
Uncertainties.
ELECTRIC ENVIRONMENTAL ESTIMATES: Our operations are subject to
environmental laws and regulations. Costs to operate our facilities in
compliance with these laws and regulations generally have been recovered in
customer rates.
Compliance with the federal Clean Air Act and resulting regulations has
been, and will continue to be, a significant focus for us. The Title I
provisions of the Clean Air Act require significant reductions in nitrogen oxide
emissions. To comply with the regulations, we expect to incur capital
expenditures totaling $771 million. The key assumptions included in the capital
expenditure estimate include:
- construction commodity prices, especially construction material and
labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- allowance for funds used during construction (AFUDC) rate.
Our current capital cost estimates include an escalation rate of 2.6
percent and an AFUDC capitalization rate of 8.9 percent. As of June 30, 2004, we
have incurred $489 million in capital expenditures to comply with these
regulations and anticipate that the remaining $282 million of capital
expenditures will be made between 2004 and 2009. These expenditures include
installing catalytic reduction technology at some of our coal-fired electric
plants. In addition to modifying the coal-fired electric plants, we expect to
purchase nitrogen oxide emissions credits for years 2004 through 2008. The cost
of these credits is estimated to average $8 million per year and is accounted
for as inventory.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants and potentially pay fines.
Additionally, the viability of certain plants remaining in operation could be
called into question.
The EPA has proposed a Clean Air Interstate Rule that would require
additional coal-fired electric plant emission controls for nitrogen oxides and
sulfur dioxide. If implemented, this rule would potentially require expenditures
equivalent to those efforts in progress required to reduce nitrogen oxide
emissions under the Title I provisions of the Clean Air Act. The rule proposes a
two-phase program to reduce emissions of sulfur dioxide by 70 percent and
nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two
alternative sets of rules to reduce emissions of mercury and nickel from
coal-fired and oil-fired electric plants. Until the proposed environmental rules
are finalized, an accurate cost of compliance cannot be determined.
Several bills have been introduced in the United States Congress that
would require reductions in emissions of greenhouse gases. We cannot predict
whether any federal mandatory greenhouse gas emission reduction rules ultimately
will be enacted, or the specific requirements of any such rules if they were to
become law.
76
To the extent that greenhouse gas emission reduction rules come into
effect, such mandatory emissions reduction requirements could have far-reaching
and significant implications for the energy sectors. We cannot estimate the
potential effect of United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows, or financial position
due to the speculative nature of the policy. We stay abreast of and engage in
the greenhouse gas policy developments and will continue to assess and respond
to their potential implications on our business operations.
In March 2004, the EPA changed the rules that govern generating plant
cooling water intake systems. The new rules require significant reduction in
fish killed by operating equipment. Some of our facilities will be required to
comply by 2006. We are studying the rules to determine the most cost-effective
solutions for compliance.
For additional details on electric environmental matters, see Note 3,
Uncertainties, "Consumers' Electric Utility Contingencies - Electric
Environmental Matters."
COMPETITION AND REGULATORY RESTRUCTURING: Michigan's Customer Choice Act
and other developments will continue to result in increased competition in the
electric business. Generally, increased competition reduces profitability and
threatens market share for generation services. As of January 1, 2002, the
Customer Choice Act allowed all of our electric customers to buy electric
generation service from us or from an alternative electric supplier. As a
result, alternative electric suppliers for generation services have entered our
market. As of July 2004, alternative electric suppliers are providing 858 MW of
generation supply to ROA customers. This amount represents 11 percent of our
distribution load and an increase of 49 percent compared to July 2003. Based on
current trends, we predict load loss by year-end to be in the range of 900 MW to
1,100 MW. However, no assurance can be made that the actual load loss will be
greater or less than that range.
In July 2004, as a result of legislative hearings, several bills were
introduced into the Michigan Senate that could change Michigan's Customer Choice
Act. The proposals include:
- requiring that rates be based on cost of service,
- establishing a defined Stranded Cost calculation method,
- allowing customers who stay with or switch to alternative electric
suppliers after December 31, 2005 to return to utility services, and
requiring them to pay current market rates upon return,
- establishing reliability standards that all electric suppliers must
follow,
- requiring utilities and alternative suppliers to maintain a 15
percent power reserve margin,
- creating a service charge to fund the Low Income and Energy
Efficiency Fund,
- giving kindergarten through twelfth-grade schools a discount of 10
percent to 20 percent on electric rates, and
- authorizing a service charge payable by all customers for meeting
Clean Air Act requirements.
Securitization: In March 2003, we filed an application with the MPSC
seeking approval to issue additional Securitization bonds. In June 2003, the
MPSC issued a financing order authorizing the issuance of Securitization bonds
in the amount of $554 million. We filed for rehearing and clarification on a
number of features in the financing order. If and when the MPSC issues an order
with favorable terms, then the order will become effective upon our acceptance.
Stranded Costs: To the extent we experience net Stranded Costs as
determined by the MPSC, the Customer Choice Act allows us to recover such costs
by collecting a transition surcharge from customers who switch to an alternative
electric supplier. We cannot predict whether the Stranded Cost recovery method
adopted by the MPSC will be applied in a manner that will offset fully any
associated margin loss.
77
In 2002 and 2001, the MPSC issued orders finding that we experienced zero
net Stranded Costs from 2000 to 2001. The MPSC also declined to resolve numerous
issues regarding the net Stranded Cost methodology in a way that would allow a
reliable prediction of the level of Stranded Costs for future years. We
currently are in the process of appealing these orders with the Michigan Court
of Appeals and the Michigan Supreme Court.
In March 2003, we filed an application with the MPSC seeking approval of
net Stranded Costs incurred in 2002, and for approval of a net Stranded Cost
recovery charge. Our net Stranded Costs incurred in 2002, including the cost of
money, are estimated to be $47 million with the issuance of Securitization bonds
that include Clean Air Act investments, or $104 million without the issuance of
Securitization bonds that include Clean Air Act investments. Once the MPSC
issues a final financing order on Securitization, we will know the amount of our
request for net Stranded Cost recovery for 2002. In July 2004, the ALJ issued a
proposal for decision in our 2002 net Stranded Cost case, which recommended that
the MPSC find that we incurred net Stranded Costs of $12 million. This
recommendation includes the cost of money through July 2004 and excludes Clean
Air Act investments.
In April 2004, we filed an application with the MPSC seeking approval of
net Stranded Costs incurred in 2003. We also requested interim relief for 2003
net Stranded Costs, but the ALJ declined to set a schedule that would allow
consideration of the interim request. In July 2004, we revised our request for
approval of 2003 Stranded Costs incurred, including the cost of money, to $69
million with the issuance of Securitization bonds that include Clean Air Act
investments, or $128 million without the issuance of Securitization bonds that
include Clean Air Act investments. In July 2004, the MPSC Staff issued a
position on our 2003 net Stranded Cost application, which resulted in a Stranded
Cost calculation of $52 million. The amount includes the cost of money, but
excludes Clean Air Act investments.
We cannot predict how the MPSC will rule on our requests for the recovery
of Stranded Costs. Therefore, we have not recorded regulatory assets to
recognize the future recovery of such costs.
Implementation Costs: Following an appeal and remand of initial MPSC
orders relating to 1999 implementation costs, the MPSC authorized the recovery
of all previously approved implementation costs for the years 1997 through 2001
by surcharges on all customers' bills phased in as rate caps expire. Authorized
recoverable implementation costs totaled $88 million. This total includes
carrying costs through 2003. Additional carrying costs will be added until
collection occurs. For additional information on rate caps, see "Rate Caps"
within this section.
Our applications for $7 million of implementation costs for 2002 and $1
million for 2003 are presently pending approval by the MPSC. Included in the
2002 request is $5 million related to our former participation in the
development of the Alliance RTO. Although we believe these implementation costs
and associated cost of money are fully recoverable in accordance with the
Customer Choice Act, we cannot predict the amounts the MPSC will approve as
recoverable.
In addition to seeking MPSC approval for these costs, we are pursuing
authorization at the FERC for the MISO to reimburse us for approximately $8
million, for implementation costs related to our former participation in the
development of the Alliance RTO which includes the $5 million pending approval
by the MPSC as part of 2002 implementation costs recovery. These costs have
generally either been expensed or approved as recoverable implementation costs
by the MPSC. The FERC has denied our request for reimbursement and we are
appealing the FERC ruling at the United States Court of Appeals for the District
of Columbia. We cannot predict the outcome of the appeal process or the ultimate
amount, if any, we will collect for Alliance RTO development costs.
Security Costs: The Customer Choice Act, as amended, allows for recovery
of new and enhanced security costs, as a result of federal and state regulatory
security requirements incurred before January 1, 2006. All retail customers,
except customers of alternative electric suppliers, would pay these charges. In
April 2004, we filed a security cost recovery case with the MPSC for $25 million
of costs for which regulatory treatment has not yet been granted through other
means. The requested amount includes reasonable and prudent security
enhancements through December 31, 2005. As of June 30, 2004, we have $7 million
in security costs recorded as a regulatory asset. The costs are for enhanced
security and insurance because of federal and state regulatory security
requirements imposed after the September 11, 2001 terrorist attacks. In July
2004, a settlement was reached with the parties to the case, which would provide
for full recovery of the requested security costs over a five-year period
78
beginning in 2004. We are presently awaiting approval from the MPSC. We cannot
predict how the MPSC will rule on our request for the recoverability of security
costs.
Rate Caps: The Customer Choice Act imposes certain limitations on electric
rates that could result in us being unable to collect our full cost of
conducting business from electric customers. Such limitations include:
- rate caps effective through December 31, 2004 for small commercial
and industrial customers, and
- rate caps effective through December 31, 2005 for residential
customers.
As a result, we may be unable to maintain our profit margins in our
electric utility business during the rate cap periods. In particular, if we need
to purchase power supply from wholesale suppliers while retail rates are capped,
the rate restrictions may preclude full recovery of purchased power and
associated transmission costs.
PSCR: The PSCR process provides for the reconciliation of actual power
supply costs with power supply revenues. This process provides for recovery of
all reasonable and prudent power supply costs actually incurred by us, including
the actual cost for fuel, and purchased and interchange power. In September
2003, we submitted a PSCR filing to the MPSC that reinstates the PSCR process
for customers whose rates are no longer frozen or capped as of January 1, 2004.
The proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers and, subject to the
overall rate caps, from other customers. We estimate the recovery of increased
power supply costs from large commercial and industrial customers to be
approximately $30 million in 2004. As allowed under current regulation, we
self-implemented the proposed PSCR charge on January 1, 2004. The revenues
received from the PSCR charge are also subject to subsequent reconciliation at
the end of the year after actual costs have been reviewed for reasonableness and
prudence. We cannot predict the outcome of this reconciliation proceeding.
Special Contracts: We entered into multi-year electric supply contracts
with certain industrial and commercial customers. The contracts provide
electricity at specially negotiated prices, usually at a discount from tariff
prices. As of July 2004, special contracts for approximately 630 MW of load are
in place, most of which are in effect through 2005. These include, new special
contracts with Dow Corning and Hemlock Semi-Conductor for 101 MW of load, which
received final approval from the MPSC in May 2004 and special contracts with
several hospitals totaling 52 MW of load, which received approval from the MPSC
in July 2004. We cannot predict whether additional special contracts will be
necessary, advisable, or approved.
Transmission Sale: In May 2002, we sold our electric transmission system
for $290 million to MTH. We are currently in arbitration with MTH regarding
property tax items used in establishing the selling price of our electric
transmission system. An unfavorable outcome could result in a reduction of sale
proceeds previously recognized by approximately $2 million to $3 million.
There are multiple proceedings and a proposed rulemaking pending before
the FERC regarding transmission pricing mechanisms and standard market design
for electric bulk power markets and transmission. The results of these
proceedings and proposed rulemakings could affect significantly:
- transmission cost trends,
- delivered power costs to us, and
- delivered power costs to our retail electric customers.
The financial impact of such proceedings, rulemaking, and trends are not
quantifiable currently. In addition, we are evaluating whether or not there may
be impacts on electric reliability associated with the outcomes of these various
transmission related proceedings. For example, Commonwealth Edison Company
received approval from the FERC to join the PJM RTO effective May 1, 2004 and
American Electric Power Service Corporation received approval from the FERC to
join the PJM RTO effective October 1, 2004. These integrations could create
different patterns of flow and power within the Midwest area and could affect
adversely our ability to provide reliable service to our customers.
79
August 14, 2003 Blackout: On August 14, 2003, the electric transmission
grid serving parts of the Midwest and the Northeast experienced a significant
disturbance that impacted electric service to millions of homes and businesses.
As a result, federal and state investigations regarding the cause of the
blackout were conducted. These investigations resulted in the NERC and the U.S.
and Canadian Power System Outage Task Force releasing electric operations
recommendations. Few of the recommendations apply directly to us, since we are
not a transmission owner. However, the recommendations could result in increased
transmission costs to us and require upgrades to our distribution system. The
financial impacts of these recommendations are not quantifiable currently.
We have complied with an MPSC order requiring Michigan utilities and
transmission companies to submit a report concerning relay settings on their
systems by May 10, 2004. In July 2004, the MPSC closed the docket concerning the
investigation into the August 14, 2003 blackout. Also, we have complied with the
FERC order requiring entities that own, operate, or control designated
transmission facilities to report on their vegetation management practices by
June 17, 2004. This FERC order affected a total of six miles of high voltage
lines located on or adjacent to some generating plant properties.
For additional details and material changes relating to the rate matters
and restructuring of the electric utility industry, see Note 3, Uncertainties,
"Consumers' Electric Utility Restructuring Matters," and "Consumers' Electric
Utility Rate Matters."
UNIT OUTAGE: In June 2004, our 638 MW Karn Unit 4 facility located in
Essexville, Michigan experienced a failure on the exciter. The exciter is a
device that provides the magnetic field to the main electric generator.
Replacement of the exciter is expected to take several months. In the interim,
we have installed a temporary replacement, which is rented from Detroit Edison.
However, under the agreement, Detroit Edison can recall the exciter at any time.
To hedge against 235 MW of this risk and ensure adequate reserve margins during
the summer peak periods, we have entered into two short-term capacity contracts.
As of July 2004, the rented exciter has been installed and the Karn unit is
operating effectively. The financial impacts of the unit outage are not
currently quantifiable.
FERC SUPPLY MARGIN ASSESSMENT: In April 2004, the FERC adopted two new
generation market power screens and modified measures to mitigate market power
where it is found. The screens will apply to all initial market-based rate
applications and reviews on an interim basis, which occur every three years.
Based on preliminary reviews, we believe that we will pass the established
screens.
PERFORMANCE STANDARDS: Electric distribution performance standards
developed by the MPSC became effective in February 2004. The standards relate to
restoration after outages, safety, and customer services. The MPSC order calls
for financial penalties in the form of customer credits if the standards for the
duration and frequency of outages are not met. We met or exceeded all approved
standards for year-end results for both 2002 and 2003. As of June 2004, we are
in compliance with the acceptable level of performance. We are a member of an
industry coalition that has appealed the customer credit portion of the
performance standards to the Michigan Court of Appeals. We cannot predict the
likely effects of the financial penalties, if any, nor can we predict the
outcome of the appeal. Likewise, we cannot predict our ability to meet the
standards in the future or the cost of future compliance.
For additional details on performance standards, see Note 3,
Uncertainties, "Consumers' Electric Utility Rate Matters - Performance
Standards."
80
GAS UTILITY BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect gas deliveries to grow at an
average rate of less than one percent per year. Actual gas deliveries in future
periods may be affected by:
- fluctuations in weather patterns,
- use by independent power producers,
- competition in sales and delivery,
- Michigan economic conditions,
- gas consumption per customer, and
- increases in gas commodity prices.
In February 2004, we filed an application with the MPSC for a Certificate
of public convenience and necessity for the construction of a 25-mile gas
transmission pipeline in northern Oakland County. The project is necessary to
meet peak load beginning in the winter of 2005 through 2006. If we are unable to
construct the pipeline due to local opposition, we will need to pursue more
costly alternatives or possibly curtail serving the system's load growth in that
area.
GAS UTILITY BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our financial
results and conditions. These trends or uncertainties could have a material
impact on net sales, revenues, or income from gas operations. The trends and
uncertainties include:
Environmental
- potential environmental remediation costs at a number of sites,
including sites formerly housing manufactured gas plant facilities.
Regulatory
- inadequate regulatory response to applications for requested rate
increases, and
- response to increases in gas costs, including adverse regulatory
response and reduced gas use by customers.
Other
- pipeline integrity maintenance and replacement costs, and
- other pending litigation.
We sell gas to retail customers under tariffs approved by the MPSC. These
tariffs measure the volume of gas delivered to customers (i.e. mcf). However, we
purchase gas for resale on a heating value (i.e. Btu) basis. The Btu content of
the gas purchased fluctuates and may result in customers using less gas for the
same heating requirement. We fully recover our cost to purchase gas through the
approved GCR. However, since the customer may use less gas on a volumetric
basis, the revenue from the distribution charge (the non-gas cost portion of the
customer bill) could be reduced. This could affect adversely our gas utility
earnings. The amount of any possible earnings loss due to fluctuating Btu
content in future periods cannot be estimated at this time.
In September 2002, the FERC issued an order rejecting our filing to assess
certain rates for non-physical gas title tracking services we provide. In
December 2003, the FERC ruled that no refunds were at issue and we reversed $4
million related to this matter. In January 2004, three companies filed with the
FERC for clarification or rehearing of the FERC's December 2003 order. In April
2004, the FERC issued its Order Granting Clarification. In that Order,
81
the FERC indicated that its December 2003 order was in error. It directed us to
file within 30 days a fair and equitable title-tracking fee and to make refunds,
with interest, to customers based on the difference between the accepted fee and
the fee paid. In response to the FERC's April 2004 order, we filed a Request for
Rehearing in May 2004. The FERC issued an Order Granting Rehearing for Further
Consideration in June 2004. We expect the FERC to issue an order on the merits
of this proceeding in the third quarter of 2004. We believe that with respect to
the FERC jurisdictional transportation, we have not charged any customers title
transfer fees, so no refunds are due. At this time, we cannot predict the
outcome of this proceeding.
GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. We expect our remaining remedial action costs to be between $37 million
and $90 million. Any significant change in assumptions, such as remediation
techniques, nature and extent of contamination, and legal and regulatory
requirements, could change the remedial action costs for the sites. For
additional details, see Note 3, Uncertainties, "Consumers' Gas Utility
Contingencies - Gas Environmental Matters."
GAS COST RECOVERY: The MPSC is required by law to allow us to charge
customers for our actual cost of purchased natural gas. The GCR process is
designed to allow us to recover all of our gas costs; however, the MPSC reviews
these costs for prudency in an annual reconciliation proceeding.
GCR YEAR 2002-2003: In March 2004, a settlement agreement was approved by
the MPSC that resulted in a GCR disallowance of $11 million for the GCR period.
For additional details, see Note 3, Uncertainties, "Consumers' Gas Utility Rate
Matters - Gas Cost Recovery."
GCR YEAR 2003-2004: In June 2004, we filed a reconciliation of GCR for the
12-months ended March 2004. We proposed to refund to our customers $28 million
of overrecovered gas cost, plus interest. The refund will be included in the
2004-2005 GCR plan year. The overrecovery includes the $11 million refund
settlement for the 2002-2003 GCR year, as well as refunds received by us from
our suppliers and required by the MPSC to be refunded to our customers.
GCR PLAN FOR YEAR 2004-2005: In December 2003, we filed an application
with the MPSC seeking approval of a GCR plan for the 12-month period of April
2004 through March 2005. The second quarter GCR adjustment resulted in a GCR
ceiling price of $6.57. In June 2004, the MPSC issued a final Order in our GCR
plan approving a settlement, which included a quarterly mechanism for setting a
GCR ceiling price. The mechanism did not change the current ceiling price of
$6.57. Actual gas costs and revenues will be subject to an annual reconciliation
proceeding. Our GCR factor for the billing month of August is $6.39 per mcf.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC
for a $156 million annual increase in our gas delivery and transportation rates
that included a 13.5 percent return on equity. In September 2003, we filed an
update to our gas rate case that lowered the requested revenue increase from
$156 million to $139 million and reduced the return on common equity from 13.5
percent to 12.75 percent. The MPSC authorized an interim gas rate increase of
$19 million annually. The interim increase is under bond and subject to refund
if the final rate relief is a lesser amount. The interim increase order includes
a $34 million reduction in book depreciation expense and related income taxes
effective only during the period of interim relief. The MPSC order allowed us to
increase our rates beginning December 19, 2003. As part of the interim rate
order, Consumers agreed to restrict dividend payments to its parent company, CMS
Energy, to a maximum of $190 million annually during the period of interim
relief. On March 5, 2004, the ALJ issued a Proposal for Decision recommending
that the MPSC not rely upon the projected test year data included in our filing,
which was supported by the MPSC Staff and the ALJ further recommended that the
application be dismissed. In response to the Proposal for Decision, the parties
have filed exceptions and replies to exceptions. The MPSC is not bound by the
ALJ's recommendation and will review the exceptions and replies to exceptions
prior to issuing an order on final rate relief.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our
gas utility plant depreciation case originally filed in June 2001. This case is
not affected by the 2003 gas rate case interim increase order which reduced book
depreciation expense and related income taxes only for the period that we
receive the interim relief.
82
The June 2001 depreciation case filing was based on December 2000 plant
balances and historical data. The December 2003 filing updates the gas
depreciation case to include December 2002 plant balances. The proposed
depreciation rates, if approved, would result in an annual increase of $12
million in depreciation expense based on December 2002 plant balances. In June
2004, the ALJ issued a Proposal for Decision recommending adoption of the
Michigan Attorney General's proposal to reduce our annual depreciation expense
by $52 million. In response to the Proposal for Decision, the parties filed
exceptions and are expected to file replies to exceptions. In our exceptions, we
proposed alternative depreciation rates that would result in an annual decrease
of $7 million in depreciation expense. The MPSC is not bound by the ALJ's
recommendation and will review the exceptions and replies to exceptions prior to
issuing an order on final depreciation rates.
OTHER CONSUMERS' OUTLOOK
CODE OF CONDUCT: In December 2000, the MPSC issued a new code of conduct
that applies to utilities and alternative electric suppliers. The code of
conduct seeks to prevent financial support, information sharing, and
preferential treatment between a utility's regulated and non-regulated services.
The new code of conduct is broadly written and could affect our:
- retail gas business energy related services,
- retail electric business energy related services,
- marketing of non-regulated services and equipment to Michigan
customers, and
- transfer pricing between our departments and affiliates.
We appealed the MPSC orders related to the code of conduct and sought a
deferral of the orders until the appeal was complete. We also sought waivers
available under the code of conduct to continue utility activities that provide
approximately $50 million in annual electric and gas revenues. In October 2002,
the MPSC denied waivers for three programs including the appliance service plan
offered by us, which generated $34 million in gas revenue in 2003. In March
2004, the Michigan Court of Appeals upheld the MPSC's implementation of the code
of conduct without modification. We filed an application for leave to appeal
with the Michigan Supreme Court, but we cannot predict whether the Michigan
Supreme Court will accept the case or the outcome of any appeal. In April 2004,
the Michigan Governor signed legislation that allows us to remain in the
appliance service business. In June 2004, the MPSC directed the parties to a
pending complaint case involving Consumers to file briefs discussing whether the
case is affected by the legislation.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The MCV Partnership estimates that the
decision will result in a refund to the MCV Partnership of approximately $35
million in taxes plus $9 million of interest. The Michigan Tax Tribunal decision
has been appealed to the Michigan Court of Appeals by the City of Midland and
the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals.
The MCV Partnership also has a pending case with the Michigan Tax Tribunal for
tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of
these proceedings; therefore, the above refund (net of approximately $15 million
of deferred expenses) has not been recognized in year-to-date 2004 earnings.
ENTERPRISES OUTLOOK
INDEPENDENT POWER PRODUCTION: We plan to complete the restructuring of our
IPP business by narrowing the focus of our operations to primarily North America
and the Middle East/North Africa. We will continue to sell designated assets and
investments that are under-performing or are not consistent with this focus.
CMS ERM: CMS ERM has streamlined its portfolio in order to reduce business
risk and outstanding credit guarantees. Our future activities will be centered
on fuel procurement activities and merchant power marketing in such a way as to
optimize the earnings from our IPP generation assets.
83
CMS GAS TRANSMISSION: CMS Gas Transmission continues to narrow its scope
of existing operations. We plan to continue to sell most of our international
assets and businesses. Future operations will be conducted mainly in Michigan.
In July 2004, we entered into a definitive agreement to sell our interests
in Parmelia and Goldfields to APT for approximately $208 million Australian
(approximately $145 million in U.S. dollars). The sale is subject to customary
closing conditions. We expect the sale to close in the third quarter of 2004.
In July 2003, CMS Gas Transmission completed the sale of CMS Field
Services to Cantera Natural Gas, Inc. for gross cash proceeds of approximately
$113 million, subject to post closing adjustments, and a $50 million face value
note of Cantera Natural Gas, Inc., which is not included in our consolidated
financial statements. The note is payable to CMS Energy for up to $50 million,
subject to the financial performance of the Fort Union and Bighorn natural gas
gathering systems from 2004 through 2008. The financial performance is dependent
primarily on the number of new wells connected and transportation volumes, with
certain EBITDA thresholds required to be achieved in order for us to receive
payments on the note. There may not be enough new wells connected in 2004 to
achieve the annual threshold and thus trigger a payment on the note for 2004.
UNCERTAINTIES: The results of operations and the financial position of our
diversified energy businesses may be affected by a number of trends or
uncertainties. Those that could have a material impact on our income, cash
flows, or balance sheet and credit improvement include:
- our ability to sell or to improve the performance of assets and
businesses in accordance with our business plan,
- changes in exchange rates or in local economic or political
conditions, particularly in Argentina, Venezuela, Brazil, and the
Middle East,
- changes in foreign laws or in governmental or regulatory policies
that could reduce significantly the tariffs charged and revenues
recognized by certain foreign subsidiaries, or increase expenses,
- imposition of stamp taxes on South American contracts that could
increase project expenses substantially,
- impact of any future rate cases, FERC actions, or orders on
regulated businesses,
- impact of ratings downgrades on our liquidity, operating costs, and
cost of capital, and
- impact of restrictions by the Argentine government on natural gas
exports to our GasAtacama plant.
OTHER OUTLOOK
LITIGATION AND REGULATORY INVESTIGATION: We are the subject of an
investigation by the DOJ regarding round-trip trading transactions by CMS MST.
Additionally, we are named as a party in various litigation including a
shareholder derivative lawsuit, a securities class action lawsuit, a class
action lawsuit alleging ERISA violations, several lawsuits regarding alleged
false natural gas price reporting, and a lawsuit surrounding the possible sale
of CMS Pipeline Assets. For additional details regarding these investigations
and litigation, see Note 3, Uncertainties.
NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES:
The FASB issued this Interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.
84
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46.
For entities that have not previously adopted FASB Interpretation No. 46,
Revised FASB Interpretation No. 46 provided an implementation deferral until the
first quarter of 2004. As of and for the quarter ended March 31, 2004, we
adopted Revised FASB Interpretation No. 46 for all entities.
We determined that we are the primary beneficiary of both the MCV
Partnership and the FMLP. We have a 49 percent partnership interest in the MCV
Partnership and a 46.4 percent partnership interest in the FMLP. Consumers is
the primary purchaser of power from the MCV Partnership through a long-term
power purchase agreement. In addition, the FMLP holds a 75.5 percent lessor
interest in the MCV Facility, which results in Consumers holding a 35 percent
lessor interest in the MCV Facility. Collectively, these interests make us the
primary beneficiary of these entities. As such, we consolidated their assets,
liabilities, and activities into our financial statements for the first time as
of and for the quarter ended March 31, 2004. These partnerships have third-party
obligations totaling $728 million at June 30, 2004. Property, plant, and
equipment serving as collateral for these obligations has a carrying value of
$1.453 billion at June 30, 2004. The creditors of these partnerships do not have
recourse to the general credit of CMS Energy.
At December 31, 2003, we determined that we are the primary beneficiary of
three other entities that are determined to be variable interest entities. We
have 50 percent partnership interest in the T.E.S. Filer City Station Limited
Partnership, the Grayling Generating Station Limited Partnership, and the
Genesee Power Station Limited Partnership. Additionally, we have operating and
management contracts and are the primary purchaser of power from each
partnership through long-term power purchase agreements. Collectively, these
interests make us the primary beneficiary as defined by the Interpretation.
Therefore, we consolidated these partnerships into our consolidated financial
statements for the first time as of December 31, 2003. These partnerships have
third-party obligations totaling $118 million at June 30, 2004. Property, plant,
and equipment serving as collateral for these obligations has a carrying value
of $169 million as of June 30, 2004. Other than outstanding letters of credit
and guarantees of $5 million, the creditors of these partnerships do not have
recourse to the general credit of CMS Energy.
We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company Obligated Trust Preferred
Securities totaling $663 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $684 million of long-term debt - related parties
and reflected an investment in related parties of $21 million.
We are not required to restate prior periods for the impact of this
accounting change.
Additionally, we have variable interest entities in which we are not the
primary beneficiary. FASB Interpretation No. 46 requires us to disclose certain
information about these entities. The chart below details our involvement in
these entities at June 30, 2004:
Investment Operating Total
Name (Ownership Nature of the Involvement Balance Agreement with Generating
Interest) Entity Country Date (In Millions) CMS Energy Capacity
--------------- ------------- ----------- ----------- ------------- -------------- ----------
Taweelah (40%) Generator United Arab 1999 $ 93 Yes 777 MW
Emirates
Generator -
Under
Jubail (25%) Construction Saudi Arabia 2001 $ - Yes 250 MW
Generator -
Under United Arab
Shuweihat (20%) Construction Emirates 2001 $ (16)(a) Yes 1,500 MW
------- -----
Total $ 77 2,527 MW
======= =====
85
(a) At June 30, 2004, we carried a negative investment in Shuweihat. The balance
is comprised of our investment of $3 million reduced by our proportionate share
of the negative fair value of derivative instruments of $19 million. We are
required to record the negative investment due to our future commitment to make
an equity investment in Shuweihat.
Our maximum exposure to loss through our interests in these variable
interest entities is limited to our investment balance of $77 million, and
letters of credit, guarantees, and indemnities relating to Taweelah and
Shuweihat totaling $129 million. Included in that total is a letter of credit
relating to our required initial investment in Shuweihat of $70 million. We plan
to contribute our initial investment when the project becomes commercially
operational in 2004.
FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE
REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND
MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and
Modernization Act of 2003 (the Act) was signed into law in December 2003. The
Act establishes a prescription drug benefit under Medicare (Medicare Part D) and
a federal subsidy, which is exempt from federal taxation, to sponsors of retiree
health care benefit plans that provide a benefit that is actuarially equivalent
to Medicare Part D. At December 31, 2003, we elected a one-time deferral of the
accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1.
The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff
Position, No. SFAS 106-1 and provides further accounting guidance. FASB Staff
Position, No. SFAS 106-2 states that for plans that are actuarially equivalent
to Medicare Part D, employers' measures of accumulated postretirement benefit
obligations and postretirement benefit costs should reflect the effects of the
Act.
We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $158 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months ended June 30, 2004,
$12 million for the six months ended June 30, 2004, and an expected total
reduction of $24 million for 2004. Consumers capitalizes a portion of OPEB cost
in accordance with regulatory accounting. As such, the remeasurement resulted in
a net reduction of OPEB expense of $4 million, or $0.03 per share, for the three
months ended June 30, 2004, $9 million, or $0.05 per share, for the six months
ended June 30, 2004, and an expected total net expense reduction of $17 million
for 2004.
EITF NO. 03-6, PARTICIPATING SECURITIES AND THE TWO-CLASS METHOD UNDER
SFAS NO. 128: EITF No. 03-6, effective June 30, 2004, addresses the treatment of
participating securities in earnings per share calculations. This EITF defines
participating securities and describes their treatment using a two-class method
of calculating earnings per share. Since we have not issued any participating
securities, as defined by EITF No. 03-6 and SFAS No. 128, there was no impact on
earnings per share upon adoption.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
PROPOSED EITF NO. 04-8, THE EFFECT OF CONTINGENTLY CONVERTIBLE DEBT ON
DILUTED EARNINGS PER SHARE: The Issue addresses when the dilutive effect of
contingently convertible debt instruments should be included in diluted earnings
per share calculations. At its July 1, 2004 meeting, the EITF reached a
consensus that contingently convertible debt instruments should be included in
the diluted earnings per share computation (if dilutive) regardless of whether
the market price trigger or other contingent features have been met.
We currently have a contingently convertible debt instrument and a
contingently convertible preferred stock instrument outstanding. Both securities
include similar contingent conversion provisions. Including the dilutive effect
of these instruments could reduce our diluted earnings per share. For further
information on these securities, refer to Note 4, Financings and Capitalization,
"Contingently Convertible Securities."
The proposed Issue is open for public comment and will be discussed by the
EITF at its September 2004 meeting. The tentative effective date for this EITF
Issue is for reporting periods ending after December 15, 2004. Prior period
earnings per share amounts would be required to be restated.
86
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS FOR THE FISCAL
YEAR ENDED DECEMBER 31, 2003
This Management's Discussion and Analysis of Financial Condition and Results of
Operations for the Fiscal Year Ended December 31, 2003, as filed on July 21,
2004 on Form 10-K/A (the "10-K MD&A") refers to, and in some sections
specifically incorporates by reference, CMS' Notes to Consolidated Financial
Statements and Notes for the fiscal year ended December 31, 2003 (the "DECEMBER
31, 2003 FINANCIAL STATEMENTS") beginning on page F-51. Both of the 10-K MD&A
and the December 31, 2003 Financial Statements have been modified from the
versions that were filed with the SEC on July 21, 2004 to reflect supplemental
disclosure by the Company in response to an SEC comment letter. The December 31,
2004 Financial Statements contain detailed information that should be referred
to in conjunction with the following 10-K MD&A. The 10-K MD&A also describes
material contingencies in CMS' Notes to the December 31, 2003 Financial
Statements, and CMS encourages readers to review these Notes. All note
references within the 10-K MD&A refer to CMS' Notes to the December 31, 2003
Financial Statements. Please refer to the Glossary beginning on page 146 of this
prospectus for definitions of certain capitalized terms used in the 10-K MD&A.
EXECUTIVE OVERVIEW
CMS Energy is an integrated energy company with a business strategy
focused primarily in Michigan. We are the parent holding company of Consumers
and Enterprises. Consumers is a combination electric and gas utility company
serving Michigan's Lower Peninsula. Enterprises, through subsidiaries, is
engaged in domestic and international diversified energy businesses including:
independent power production; natural gas transmission, storage and processing;
and energy services. We manage our businesses by the nature of services each
provides and operate principally in three business segments: electric utility,
gas utility, and enterprises.
We earn our revenue and generate cash from operations by providing
electric and natural gas utility services, electric power generation, gas
transmission, storage, and processing, and other energy-related services. Our
businesses are affected by weather, especially during the key heating and
cooling seasons, economic conditions, particularly in Michigan, regulation and
regulatory issues that primarily affect our gas and electric utility operations,
interest rates, our debt credit rating, and energy commodity prices.
Our strategy involves rebuilding our balance sheet and refocusing on our
core strength: superior utility operation. Over the next few years, we expect
this strategy to reduce our parent company debt substantially, improve our debt
ratings, grow earnings at a mid-single digit rate, restore a meaningful
dividend, and position the company to make new investments consistent with our
strengths. In the near term, our new investments will focus on the utility.
In 2003, we continued to implement our "utility plus" strategy centered
around growing a healthy utility in Michigan and optimizing the contribution
from key Enterprises assets. We sold over $900 million worth of non-strategic
assets, enabling us to reduce debt by $1.1 billion. We have taken advantage of
historically low interest rates to extend maturities and refinance our debt at
lower cost. We completed over $3 billion of financing and refinancing
transactions to resolve short-term liquidity concerns at the start of 2003. In
addition to improving our capital structure, we contributed $560 million to our
defined benefit pension plan. This should result in lower pension costs in the
future.
At the foundation of our financial progress was exceptional operating
performance. For the second consecutive year, our Michigan gas utility earned
the J.D. Power and Associates award for highest residential customer
satisfaction with natural gas services in the Midwest. Independent evaluators,
like J.D. Power and Associates recognize value and our regulators do too. The
MPSC authorized an annual increase in our gas utility rates of $56 million in
late 2002, and an additional interim annualized $19 million rate increase in
2003.
Despite strong financial and operational performance in 2003, we face
important challenges in the future. We continue to lose industrial and
commercial customers to other electric suppliers without receiving compensation
for stranded costs caused by the lost sales. As of March 2004, we lost 735 MW or
nine percent of our electric business to these alternative electric suppliers.
We expect the loss to grow to over 1,000 MW in 2004. Existing state
87
legislation encourages competition and provides for recovery of stranded costs,
but the MPSC has not yet authorized stranded cost recovery. We continue to work
cooperatively with the MPSC to resolve this issue.
Further, higher natural gas prices have harmed the economics of the MCV
and we are seeking approval from the MPSC to change the way in which the
facility is used. Our proposal would reduce gas consumption by an estimated 30
to 40 bcf per year while improving the MCV's financial performance with no
change to customer rates. A portion of the benefits from the proposal will
support additional renewable resource development in Michigan. Resolving the
issue is critical for our shareowners and customers, and we have asked the MPSC
to approve it quickly.
We also are focused on further reducing our business risk and leverage,
while growing the equity base of our company. Much of our asset sales program is
complete; we are focused on selling the remaining businesses that are not
strategic to us. This creates volatility in earnings as we recognize foreign
currency translation account losses at the time of sale, but it is the right
strategic direction for our company.
Finally, we are working to resolve outstanding litigation that stemmed
from energy trading activities in 2001 and earlier. Doing so will permit us to
devote more attention to improving business growth. Our business plan is
targeted at predictable earnings growth along with reduction in our debt. We are
a full year into our five-year plan to reduce by half the debt of the CMS Energy
holding company.
The result of these efforts will be a strong, reliable energy company that
will be poised to take advantage of opportunities for further growth.
RESTATEMENT
Financial statements of prior years and quarterly data for all three
periods presented have been restated for the following events:
- International Energy Distribution, which includes SENECA and CPEE,
is no longer considered "discontinued operations",
- certain derivative accounting corrections, and
- Loy Yang deferred tax accounting correction.
For additional details on the effect of the restatements, see Note 18,
Restatement and Reclassification, and Note 19, Quarterly Financial and Common
Stock Information (Unaudited).
RESULTS OF OPERATIONS
CMS ENERGY CONSOLIDATED NET LOSS
Our 2003 net loss was $44 million, an improvement of $606 million from
2002. We are continuing to restructure our business operations, and as our
financial plan moves forward, we will maintain our strategy of selling
under-performing or non-strategic assets in order to reduce our debt, to reduce
business risk, and to provide for more predictable future earnings.
In Millions (Except For Per
Share Amounts)
--------------------------------------------------------
Restated Restated
Years Ended December 31 2003 2002 2001
----------------------- -------- -------- --------
Net Loss $ (44) $ (650) $ (459)
Basic loss per share $ (0.30) $ (4.68) $ (3.51)
Diluted loss per share $ (0.30) $ (4.68) $ (3.51)
======== ======== ========
88
In Millions
---------------------------------------------------------------------------------------------
Restated Restated Restated
Years Ended December 31 2003 2002 Change 2002 2001 Change
------------------------------- -------- -------- ------ -------- -------- ------
Electric Utility $ 167 $ 264 $ (97) $ 264 $ 120 $ 144
Gas Utility 38 46 (8) 46 21 25
Enterprises 8 (419) 427 (419) (272) (147)
Corporate Interest and Other (256) (285) 29 (285) (196) (89)
-------- -------- ------ -------- -------- ------
Loss from Continuing Operations (43) (394) 351 (394) (327) (67)
-------- -------- ------ -------- -------- ------
Discontinued Operations 23 (274) 297 (274) (128) (146)
Accounting Changes (24) 18 (42) 18 (4) 22
-------- -------- ------ -------- -------- ------
Net Loss $ (44) $ (650) $ 606 $ (650) $ (459) $ (191)
======== ======== ====== ======== ======== ======
2003 COMPARED TO 2002: Our net loss was reduced significantly from:
- absence of $379 million, net of tax, of goodwill write downs recorded in
2002 associated with discontinued operations,
- an improvement of CMS Enterprises' earnings due to:
- decrease of $323 million, net of tax, in asset write downs from
planned and completed divestitures,
- lower expropriation and devaluation losses at the Argentine
facilities due to the stabilization of the Argentine Peso,
- absence of tax charges recorded in 2002 resulting from the loss of
indefinite tax deferral for several international investments, and
- higher revenues and lower interest costs within IPP.
- decrease in corporate interest and other.
However, our progress was slowed by:
- Electric Utility earnings:
- higher electric operating costs resulting from higher pension
expense, greater depreciation expense reflecting higher levels of
plant in service, and increased amortization expense associated with
securitized regulatory assets,
- lower electric deliveries from milder weather during the summer, and
- continuation of switching by commercial and industrial customers to
alternative electric suppliers.
- loss of $44 million, after-tax, on the sale of Panhandle,
- employee benefit plans net settlement and curtailment loss of $48 million,
after tax, related to a large number of employees retiring and exiting
these plans, and
- cumulative effect of a change of accounting resulting in a charge of $23
million, net of tax, due to energy trading contracts that did not meet the
definition of a derivative.
2002 COMPARED TO 2001: Our net loss increased $191 million from:
- after-tax charges in recognition of planned and completed divestitures and
reduced asset valuations,
89
- tax credit write-offs in 2002 at the parent level, and
- restructuring and other costs in 2002.
ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
-------------------------------------------------------------------------------------------------------------
Years Ended December 31 2003 2002 Change 2002 2001 Change
------------------------------------------ -------- -------- ------ -------- -------- ------
Net income $ 167 $ 264 $ (97) $ 264 $ 120 $ 144
======== ======== ====== ======== ======== ======
Reasons for the Change:
Electric deliveries $ (41) $ 41
Power supply costs and related revenue 26 149
Other operating expenses and non-commodity
revenue (80) (21)
Gain on asset sales (38) 38
General taxes 10 (3)
Fixed charges (22) 9
Income taxes 48 (69)
-------- -------- ------ -------- -------- ------
Total change $ (97) $ 144
======== ======== ====== ======== ======== ======
ELECTRIC DELIVERIES: In 2003, electric revenues decreased, reflecting
lower deliveries. Most significantly, sales volumes to commercial and industrial
customers were 5.6 percent lower than in 2002, a result of these sectors'
continued switching to alternative electric suppliers as allowed by the Customer
Choice Act. The decrease in revenue is also the result of reduced deliveries to
higher-margin residential customers, from a milder summer's impact on air
conditioning usage. Overall, electric deliveries, including transactions with
other wholesale marketers and other electric utilities, decreased 0.4 billion
kWh or 1.1 percent.
In 2002, electric revenue increased by $41 million from the previous year,
despite lower deliveries. This was due primarily to increased deliveries to
higher-margin residential customers as a result of a significantly warmer
summer's impact on air conditioning usage. Deliveries, including transactions
with other wholesale marketers and other electric utilities, decreased 0.3
billion kWh or 0.7 percent.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our recovery of power
supply costs was fixed, as required under the Customer Choice Act. Therefore,
power supply-related revenue in excess of actual power supply costs increased
operating income. By contrast, if power supply-related revenues had been less
than actual power supply costs, the impact would have decreased operating
income. In 2003, this difference between power supply-related revenues and
actual power supply costs benefited operating income by $26 million more than it
had in 2002. This increase is primarily the result of increased intersystem
revenues due to higher market prices and sales made from surplus capacity. The
efficient operation of our generating plants and lower priced purchased power
further decreased power supply costs.
In 2002, as compared to 2001, power supply costs and related revenues
increased operating income due primarily to reduced purchased power costs
because the Palisades plant returned to service in 2002, following an extended
2001 shutdown.
OTHER OPERATING EXPENSES AND NON-COMMODITY REVENUE: In 2003, net operating
expenses and non-commodity revenue decreased operating income by $80 million
versus 2002. This decrease relates to increased pension and other benefit costs
of $54 million, a scheduled refueling outage at Palisades, and higher
transmission costs. More plant in service increased depreciation costs by $8
million, and $11 million of higher amortization expense from securitized assets
further contributed to decreased operating income. Slightly offsetting the
increased operating expenses were higher non-commodity revenues associated with
other income.
In 2002, net operating expenses and non-commodity revenue decreased
operating income by $21 million compared with 2001. The decrease primarily
related to higher transmission expenses and increased depreciation costs from
more plant in service.
90
ASSET SALES: The reduction in operating income from asset sales for 2003
versus 2002, and the increase in operating income from asset sales for 2002
versus 2001 reflect the $31 million pretax gain associated with the 2002 sale of
our electric transmission system and the $7 million pretax gain associated with
the 2002 sale of nuclear equipment from the cancelled Midland project.
GENERAL TAXES: In 2003, general taxes decreased from 2002 due primarily to
reductions in MSBT expense, resulting primarily from a tax credit received from
the State of Michigan associated with construction of the new corporate
headquarters on a qualifying Brownfield site. In 2002, general taxes increased
over 2001 due to increases in MSBT and property tax accruals.
FIXED CHARGES: In 2003, fixed charges increased versus 2002 due primarily
to higher average debt levels, but also because of higher average interest
rates. In 2002, fixed charges decreased versus 2001 because of a reduction in
long-term debt.
INCOME TAXES: In 2003, income tax decreased versus 2002 due primarily to
lower earnings by the electric utility. In 2002, income tax expense increased
versus 2001 due primarily to increased earnings.
GAS UTILITY RESULTS OF OPERATIONS
In Millions
-------------------------------------------------------------------------------------------------------------
Years Ended December 31 2003 2002 Change 2002 2001 Change
------------------------------------------ -------- -------- ------ -------- -------- ------
Net income $ 38 $ 46 $ (8) $ 46 $ 21 $ 25
======== ======== ====== ======== ======== ======
Reasons for the change:
Gas deliveries $ (1) $ 21
Gas rate increase 39 25
Gas wholesale and retail services and
other gas revenues 1 1
Operation and maintenance (34) (14)
General taxes, depreciation, and other
income (6) (3)
Fixed charges (5) 3
Income taxes (2) (8)
-------- -------- ------ -------- -------- ------
Total change $ (8) $ 25
======== ======== ====== ======== ======== ======
GAS DELIVERIES: In 2003, gas deliveries, including miscellaneous
transportation, increased 4.1 bcf or 1.1 percent versus 2002. Despite increased
system deliveries, gas revenues actually declined by $1 million. Colder weather
during the first quarter of 2003 increased deliveries to the residential and
commercial sectors. Increased deliveries resulted in a $6 million increase in
gas revenues. However, the revenue increase was offset by a $7 million gas loss
adjustment recorded as a reduction to gas revenues.
In 2002, gas revenues increased by $21 million from the previous year.
System deliveries, including miscellaneous transportation, increased 9.4 bcf or
2.6 percent. The increase was due primarily to colder weather that increased
deliveries to the residential and commercial sectors.
GAS RATE INCREASE: In November 2002, the MPSC issued a final gas rate
order authorizing a $56 million annual increase to gas tariff rates. As a result
of this order, 2003 gas revenues increased $39 million. In 2002, gas rate
increases led to increased gas revenues of $25 million over 2001.
GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: In 2003, gas
wholesale and retail services and other gas revenues increased $1 million. The
$1 million increase includes primarily the following two items. In 2003, we
reversed a $4 million reserve, originally recorded in 2002, for non-physical gas
title tracking services. In addition, in 2003, we reserved $11 million for the
settlement agreement associated with the 2002-2003 GCR disallowance. For
additional details regarding both of these issues, see the Gas Utility Business
Uncertainties in the "Outlook" section of this MD&A.
OPERATION AND MAINTENANCE: In 2003, operation and maintenance expenses
increased versus 2002 due to increases in pension and other benefits costs of
$27 million and additional expenditures on safety, reliability, and
91
customer service. In 2002, operation and maintenance expenses increased versus
2001 due to the recognition of gas storage inventory losses and additional
expenditures on customer reliability and service.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: In 2003, the net of general
tax expense, depreciation expense, and other income decreased operating income
primarily because of increases in depreciation expense from increased plant in
service. In 2002, the net of general tax expense, depreciation expense, and
other income decreased operating income primarily because of increases in MSBT
and property tax expense accruals.
FIXED CHARGES: In 2003, fixed charges increased versus 2002 due primarily
to higher average debt levels, but also because of higher average interest
rates. In 2002 versus 2001, fixed charges decreased due to lower long-term debt
levels.
INCOME TAXES: In 2003 versus 2002, income tax expense increased due to
reduced income tax expense in 2002. The 2002 reduction was attributable to
flow-through accounting on plant, property and equipment as required by past
MPSC rulings. In 2002, income tax expense increased versus 2001 due primarily to
increased earnings of the gas utility.
ENTERPRISES RESULTS OF OPERATIONS
IN MILLIONS
-------------------------------------------------------------------------------------------------------------
Years Ended December 31 2003 2002 Change 2002 2001 Change
------------------------------------------ -------- -------- ------- -------- -------- ------
Net Income (Loss) $ 8 $ (419) $ 427 $ (419) $ (272) $ (147)
======== ======== ======= ======== ======== ======
Reasons for change:
Operating revenues $(3,382) $ 301
Cost of gas and purchased power 3,427 (400)
Earnings from equity method investees 68 (82)
Operation and maintenance (9) 167
General taxes, depreciation, and other
income, net 19 14
Asset impairment charges 507 (282)
Fixed charges (25) 31
Income taxes (178) 104
-------- -------- ------- -------- -------- ------
Total change $ 427 $ (147)
======== ======== ======= ======== ======== ======
OPERATING REVENUES AND COST OF GAS AND PURCHASED POWER: In 2003, operating
revenues and related cost of gas and purchased power decreased compared to 2002
due to the sale of CMS MST wholesale gas and power contracts. In 2002, operating
revenues and related cost of gas and purchased power increased compared to 2001
primarily due to higher sales at CMS MST.
EARNINGS FROM EQUITY METHOD INVESTEES: In 2003, earnings from equity method
investees increased compared to 2002 due to reduced investment write-downs and
higher earnings. In 2002, investment write-downs increased over 2001 and
earnings were lower.
OPERATION AND MAINTENANCE: In 2003, operation and maintenance expenses decreased
compared to 2002. Lower expenses in 2003 are primarily due to restructuring of
the marketing business and divestitures. In 2002, operation and maintenance
expenses decreased compared to 2001 primarily due to asset sales at CMS
Generation during 2002.
GENERAL TAXES, DEPRECIATION AND OTHER INCOME, NET: In 2003, the net of general
tax expense, depreciation expense, and other income increased net income
primarily as a result of higher interest income and lower depreciation partially
offset by higher general taxes. In 2002, the net of general tax expense,
depreciation expense, and other income increased net income primarily due to
lower foreign currency transaction losses.
92
ASSET IMPAIRMENT CHARGES: In 2003, asset impairment charges of $95 million
decreased compared to $602 million in 2002 due to reduced divestiture activity.
In 2002, asset impairments increased over impairments of $320 million in 2001
due to divestitures and reduced asset valuations.
FIXED CHARGES: In 2003, fixed charges increased compared to 2002 primarily due
to higher average debt levels and higher average interest rates. In 2002, fixed
charges decreased compared to 2001 due to lower long-term debt levels.
INCOME TAXES: In 2003, income taxes increased compared to 2002 primarily due to
higher earnings and the loss of indefinite tax deferral for several
international investments. In 2002, income taxes decreased compared to 2001 due
to lower net income.
In 2003, Enterprises had earnings compared to a significant loss in 2002.
This year over year improvement resulted from the:
- elimination of $323 million of asset impairments, net of tax, in
2002 for divestitures and reduced asset valuations,
- lower expropriation and devaluation losses at Argentine facilities,
and
- elimination of tax charges in 2002 from the loss of indefinite tax
deferral for several international investments.
2002 losses increased by $147 million from 2001 resulting from the:
- increased asset impairments for divestitures and reduced asset
valuations, and
- discontinuing and selling several businesses.
OTHER RESULTS OF OPERATIONS
CORPORATE INTEREST AND OTHER:
In Millions
-------------------------------------------------------------------------------------
Restated Restated Restated
Years Ended December 31 2003 2002 Change 2002 2001 Change
----------------------- -------- -------- ------ -------- -------- ------
Net Loss $ (256) $ (285) $ 29 $ (285) $ (196) $ (89)
======== ======== ====== ======== ======== ======
Our 2003 corporate interest and other net expenses decreased $29 million
from 2002 primarily due to reduced restructuring costs and reduced taxes,
partially offset by increased interest allocation to continuing operations.
Our 2002 corporate interest and other net expenses increased $89 million
from 2001 primarily due to restructuring charges, including the relocation of
corporate offices from Dearborn to Jackson, Michigan, and increased taxes
resulting from the loss of certain AMT credit carryforwards.
DISCONTINUED OPERATIONS: For the years ended December 31, 2003 and 2002,
discontinued operations included Parmelia, and through their respective dates of
sale, Panhandle, CMS Viron, CMS Field Services, and Marysville. For additional
information, see Note 2, Discontinued Operations, Other Asset Sales,
Impairments, and Restructuring.
CRITICAL ACCOUNTING POLICIES
The following accounting policies are important to an understanding of our
results and financial condition and should be considered an integral part of our
MD&A:
93
- use of estimates in accounting for long-lived assets, equity method
investments, and contingencies,
- accounting for financial and derivative instruments,
- accounting for international operations and foreign currency,
- accounting for the effects of industry regulation,
- accounting for pension and postretirement benefits,
- accounting for asset retirement obligations, and
- accounting for nuclear decommissioning costs.
For additional accounting policies, see Note 1, Corporate Structure and
Accounting Policies.
USE OF ESTIMATES
In preparing our financial statements, we use estimates and assumptions
that may affect reported amounts and disclosures. Accounting estimates are used
for asset valuations, depreciation, amortization, financial and derivative
instruments, employee benefits, and contingencies. For example, we estimate the
rate of return on plan assets and the cost of future health-care benefits to
determine our annual pension and other postretirement benefit costs. There are
risks and uncertainties that may cause actual results to differ from estimated
results, such as changes in the regulatory environment, competition, foreign
exchange, regulatory decisions, and lawsuits.
LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the
recoverability of long-lived assets and equity method investments involves
critical accounting estimates. Tests of impairment are performed periodically if
certain conditions that are other than temporary exist that may indicate the
carrying value may not be recoverable. Of our total assets, recorded at $13.838
billion at December 31, 2003, 60 percent represent long-lived assets and equity
method investments that are subject to this type of analysis. We base our
evaluations of impairment on such indicators as:
- the nature of the assets,
- projected future economic benefits,
- domestic and foreign regulatory and political environments,
- state and federal regulatory and political environments,
- historical and future cash flow and profitability measurements, and
- other external market conditions or factors.
If an event occurs or circumstances change in a manner that indicates the
recoverability of a long-lived asset should be assessed, we evaluate the asset
for impairment. An asset held-in-use is evaluated for impairment by calculating
the undiscounted future cash flows expected to result from the use of the asset
and its eventual disposition. If the undiscounted future cash flows are less
than the carrying amount, we recognize an impairment loss. The impairment loss
recognized is the amount by which the carrying amount exceeds the fair value. We
estimate the fair market value of the asset utilizing the best information
available. This information includes quoted market prices, market prices of
similar assets, and discounted future cash flow analyses. An asset considered
held-for-sale is recorded at the lower of its carrying amount or fair value,
less cost to sell.
We also assess our ability to recover the carrying amounts of our equity
method investments. This assessment requires us to determine the fair values of
our equity method investments. The determination of fair value is based on
valuation methodologies including discounted cash flows and the ability of the
investee to sustain an earnings
94
capacity that justifies the carrying amount of the investment. We also consider
the existence of CMS Energy guarantees on obligations of the investee or other
commitments to provide further financial support. If the fair value is less than
the carrying value and the decline in value is considered to be other than
temporary, an appropriate write-down is recorded.
Our assessments of fair value using these valuation methodologies
represent our best estimates at the time of the reviews and are consistent with
our internal planning. The estimates we use can change over time. If fair values
were estimated differently, they could have a material impact on the financial
statements.
In 2003, we analyzed impairment indicators related to our long-lived
assets and equity method investments. Following our analysis, we reduced the
carrying amount of our investment in Parmelia, our investment in SENECA, and an
equity investment at CMS Generation to reflect their fair values. We are still
pursuing the sale of our remaining non-strategic and under-performing assets,
including some assets that were not determined to be impaired. Upon the sale of
these assets, the proceeds realized may be materially different from the
remaining carrying values. Even though these assets have been identified for
sale, we cannot predict when, or make any assurances that, these asset sales
will occur. Further, we cannot predict the amount of cash or the value of
consideration that may be received. For additional details on asset sales, see
Note 2, Discontinued Operations, Other Asset Sales, Impairments, and
Restructuring.
CONTINGENCIES: We are involved in various regulatory and legal proceedings
that arise in the ordinary course of our business. We record accruals for such
contingencies based upon our assessment that the occurrence is probable and an
estimate of the liability amount. The recording of estimated liabilities for
contingencies is guided by the principles in SFAS No. 5. We consider many
factors in making these assessments, including history and the specifics of each
matter. The most significant of these contingencies are our electric and gas
environmental estimates, which are discussed in the "Outlook" section included
in this MD&A, and the potential underrecoveries from our power purchase contract
with the MCV Partnership.
MCV UNDERRECOVERIES: The MCV Partnership, which leases and operates the
MCV Facility, contracted to sell electricity to Consumers for a 35-year period
beginning in 1990 and to supply electricity and steam to Dow. We hold a 49
percent partnership interest in the MCV Partnership, and a 35 percent lessor
interest in the MCV Facility.
Under our power purchase agreement with the MCV Partnership, we pay a
capacity charge based on the availability of the MCV Facility whether or not
electricity is actually delivered to us; a variable energy charge for kWh
delivered to us; and a fixed energy charge based on availability up to 915 MW
and based on delivery for the remaining contracted capacity. The cost that we
incur under the MCV Partnership power purchase agreement exceeds the recovery
amount allowed by the MPSC. As a result, we estimate cash underrecoveries of
capacity availability payments will aggregate $206 million from 2004 through
2007. For capacity and fixed energy payments billed by the MCV Partnership after
September 15, 2007, and not recovered from customers, we expect to claim a
regulatory out provision under the MCV Partnership power purchase agreement.
This provision obligates us to pay the MCV Partnership only those capacity and
energy charges that the MPSC has authorized for recovery from electric
customers. The effect of any such action would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse
effect on our equity, and
- eliminate our underrecoveries for capacity and energy payments.
Further, under the PPA, variable energy payments to the MCV Partnership
are based on the cost of coal burned in our coal plants and operations and
maintenance expenses. However, the MCV Partnership's costs of producing
electricity are tied to the cost of natural gas. Because natural gas prices have
increased substantially in recent years, while the price the MCV Partnership can
charge us for energy has not, the MCV Partnership's financial performance has
been affected adversely.
As a result of returning to the PSCR process on January 1, 2004, we
returned to dispatching the MCV Facility on a fixed load basis, as permitted by
the MPSC, in order to maximize recovery from electric customers of our capacity
payments. This fixed load dispatch increases the MCV Facility's output and
electricity production costs, such as natural gas. As the spread between the MCV
Facility's variable electricity production costs and its energy payment
95
revenue widens, the MCV's Partnership's financial performance and our equity
interest in the MCV Partnership will be harmed.
In February 2004, we filed a RCP with the MPSC that is intended to help
conserve natural gas and thereby improve our equity investment in the MCV
Partnership, without raising the costs paid by our electric customers. The
plan's primary objective is to dispatch the MCV Facility on an economic basis
depending on natural gas market prices, which will reduce the MCV Facility's
annual natural gas consumption by an estimated 30 to 40 bcf. This decrease in
the quantity of high-priced natural gas consumed by the MCV Facility will
benefit Consumers' ownership interest in the MCV Partnership. We requested that
the MPSC provide interim approval while it conducts a full review of the plan.
The MPSC has scheduled a prehearing conference with respect to the MCV RCP for
April 2004. We cannot predict if or when the MPSC will approve our request.
The two most significant variables in the analysis of the MCV
Partnership's future financial performance are the forward price of natural gas
for the next 22 years and the MPSC's decision in 2007 or beyond related to our
recovery of capacity payments. Natural gas prices have been historically
volatile. Presently, there is no consensus in the marketplace on the price or
range of prices of natural gas in the short term or beyond the next five years.
Therefore, we cannot predict the impact of these issues on our future earnings,
cash flows, or on the value of our equity interest in the MCV Partnership.
For additional details, see Note 4, Uncertainties, "Other Consumers'
Electric Utility Uncertainties -- The Midland Cogeneration Venture."
ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES, AND
MARKET RISK INFORMATION
FINANCIAL INSTRUMENTS: We account for investments in debt and equity
securities using SFAS No. 115. Debt and equity securities can be classified into
one of three categories: held-to-maturity, trading, or available-for-sale
securities. Our investments in equity securities are classified as
available-for-sale securities. They are reported at fair value, with any
unrealized gains or losses resulting from changes in fair value reported in
equity as part of accumulated other comprehensive income and are excluded from
earnings unless such changes in fair value are determined to be other than
temporary. Unrealized gains or losses resulting from changes in the fair value
of our nuclear decommissioning investments are reported as regulatory
liabilities. The fair value of these investments is determined from quoted
market prices.
DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133, as amended
and interpreted, to determine if certain contracts must be accounted for as
derivative instruments. The rules for determining whether a contract meets the
criteria for derivative accounting are numerous and complex. Moreover,
significant judgment is required to determine whether a contract requires
derivative accounting, and similar contracts can sometimes be accounted for
differently.
If a contract is accounted for as a derivative instrument, it is recorded
in the financial statements as an asset or a liability, at the fair value of the
contract. The recorded fair value of the contract is then adjusted quarterly to
reflect any change in the market value of the contract, a practice known as
marking the contract to market. The accounting for changes in the fair value of
a derivative (that is, gains or losses) is reported either in earnings or
accumulated other comprehensive income depending on whether the derivative
qualifies for special hedge accounting treatment. For additional details on the
accounting policies for derivative instruments, see Note 7, Financial and
Derivative Instruments.
The types of contracts we typically classify as derivative instruments are
interest rate swaps, foreign currency exchange contracts, electric call options,
gas fuel options, fixed priced weather-based gas supply call options, fixed
price gas supply call and put options, gas futures, gas and power swaps, and
forward purchases and sales. We generally do not account for electric capacity
and energy contracts, gas supply contracts, coal and nuclear fuel supply
contracts, or purchase orders for numerous supply items as derivatives.
Certain of our electric capacity and energy contracts are not accounted
for as derivatives due to the lack of an active energy market in the state of
Michigan, as defined by SFAS No. 133, and the transportation costs that would
96
be incurred to deliver the power under the contracts to the closest active
energy market at the Cinergy hub in Ohio. If a market develops in the future, we
may be required to account for these contracts as derivatives. The
mark-to-market impact on earnings related to these contracts, particularly
related to the PPA, could be material to our financial statements.
To determine the fair value of contracts that are accounted for as
derivative instruments, we use a combination of quoted market prices and
mathematical valuation models. Valuation models require various inputs,
including forward prices, volatilities, interest rates, and exercise periods.
Changes in forward prices or volatilities could change significantly the
calculated fair value of certain contracts. At December 31, 2003, we assumed a
market-based interest rate of 1 percent (six-month U.S. Treasury rate) and
volatility rates ranging between 65 percent and 120 percent to calculate the
fair value of our electric and gas call options.
TRADING ACTIVITIES: Our wholesale power and gas trading activities are
also accounted for using the criteria in SFAS No. 133. Energy trading contracts
that meet the definition of a derivative are recorded as assets or liabilities
in the financial statements at the fair value of the contracts. Gains or losses
arising from changes in fair value of these contracts are recognized into
earnings in the period in which the changes occur. Energy trading contracts that
do not meet the definition of a derivative are accounted for as executory
contracts (i.e., on an accrual basis).
The market prices we use to value our energy trading contracts reflect our
consideration of, among other things, closing exchange and over-the-counter
quotations. In certain contracts, long-term commitments may extend beyond the
period in which market quotations for such contracts are available. Mathematical
models are developed to determine various inputs into the fair value calculation
including price and other variables that may be required to calculate fair
value. Realized cash returns on these commitments may vary, either positively or
negatively, from the results estimated through application of the mathematical
model. We believe that our mathematical models utilize state-of-the-art
technology, pertinent industry data, and prudent discounting in order to
forecast certain elongated pricing curves. Market prices are adjusted to reflect
the impact of liquidating our position in an orderly manner over a reasonable
period of time under present market conditions.
In connection with the market valuation of our energy trading contracts,
we maintain reserves for credit risks based on the financial condition of
counterparties. We also maintain credit policies that management believes will
minimize its overall credit risk with regard to our counterparties.
Determination of our counterparties' credit quality is based upon a number of
factors, including credit ratings, disclosed financial condition, and collateral
requirements. Where contractual terms permit, we employ standard agreements that
allow for netting of positive and negative exposures associated with a single
counterparty. Based on these policies, our current exposures, and our credit
reserves, we do not anticipate a material adverse effect on our financial
position or results of operations as a result of counterparty nonperformance.
The following tables provide a summary of the fair value of our energy
trading contracts as of December 31, 2003.
In Millions
-----------------------------------------------------------------------------------------------
Fair value of contracts outstanding as of December 31, 2002 $ 81
Fair value of new contracts when entered into during the period --
Implementation of EITF Issue No. 02-03(a) (36)
Fair value of derivative contracts sold and received from asset sales(b) (30)
Changes in fair value attributable to changes in valuation techniques
and assumptions --
Contracts realized or otherwise settled during the period (10)
Other changes in fair value(c) 10
-----------
Fair value of contracts outstanding as of December 31, 2003 $ 15
===========
(a) Reflects the removal of contracts that do not qualify as derivatives under
SFAS No. 133 as of January 1, 2003. See Note 17, Implementation of New
Accounting Standards.
(b) Reflects $60 million decrease for price risk management assets sold and
$30 million increase for price risk management assets received related to
the sales of the gas and power books.
97
(c) Reflects changes in price and net increase/(decrease) of forward positions
as well as changes to mark-to-market and credit reserves.
Fair Value Of Contracts At December 31, 2003 In Millions
--------------------------------------------------------------------------------------------------------
Maturity (In Years)
-----------------------------------------------------------
Total
Source Of Fair Value Fair Value Less Than 1 1 to 3 4 to 5 Greater Than 5
------------------------------------------ ---------- ----------- ------ ------ --------------
Prices actively quoted $ (23) $ 2 $ (7) $ (16) $ (2)
Prices based on models and other valuation
methods 38 11 13 13 1
---------- ----------- ------ ------ --------------
Total $ 15 $ 13 $ 6 $ (3) $ (1)
========== =========== ====== ====== ==============
MARKET RISK INFORMATION: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, currency exchange
rates, and equity security prices. We manage these risks using established
policies and procedures, under the direction of both an executive oversight
committee consisting of senior management representatives and a risk committee
consisting of business-unit managers. We may use various contracts to manage
these risks, including swaps, options, and forward contracts.
Contracts used to manage market risks may be considered derivative
instruments that are subject to derivative and hedge accounting pursuant to SFAS
No. 133. We intend that any gains or losses on these contracts will be offset by
an opposite movement in the value of the item at risk. We enter into all risk
management contracts for purposes other than trading. These contracts contain
credit risk if the counterparties, including financial institutions and energy
marketers, fail to perform under the agreements. We minimize such risk by
performing financial credit reviews using, among other things, publicly
available credit ratings of such counterparties.
We perform sensitivity analyses to assess the potential loss in fair
value, cash flows, or future earnings based upon a hypothetical 10 percent
adverse change in market rates or prices. We do not believe that sensitivity
analyses alone provide an accurate or reliable method for monitoring and
controlling risks. Therefore, we use our experience and judgment to revise
strategies and modify assessments. Changes in excess of the amounts determined
in sensitivity analyses could occur if market rates or prices exceed the 10
percent shift used for the analyses. These risk sensitivities are shown in
"Interest Rate Risk," "Commodity Price Risk," "Trading Activity Commodity Price
Risk," "Currency Exchange Risk," and "Equity Securities Price Risk" within this
section.
INTEREST RATE RISK: We are exposed to interest rate risk resulting from
issuing fixed-rate and variable-rate financing instruments and from interest
rate swap agreements. We use a combination of these instruments to manage this
risk as deemed appropriate, based upon market conditions. These strategies are
designed to provide and maintain a balance between risk and the lowest cost of
capital.
Interest Rate Risk Sensitivity Analysis (assuming a 10 percent adverse
change in market interest rates):
In Millions
----------------------------------------------------------------------------
As of December 31 2003 2002
------------------------------------------------------ -------- --------
Variable-rate financing-- before tax annual earnings
exposure $ 1 $ 2
Fixed-rate financing-- potential loss in fair value(a) 242 293
-----------------
(a) Fair value exposure could only be realized if we repurchased all of our
fixed-rate financing.
As discussed in "Electric Utility Business Uncertainties -- Competition
and Regulatory Restructuring -- Securitization" within this MD&A, we have filed
an application with the MPSC to securitize certain expenditures. Upon final
approval, we intend to use the proceeds from the securitization to retire
higher-cost debt, which could include a portion of our current fixed-rate debt.
We do not believe that any adverse change in debt price and interest rates would
have a material adverse effect on either our consolidated financial position,
results of operations or cash flows.
98
Certain equity method investees have issued interest rate swaps. These
instruments are not required to be included in the sensitivity analysis, but can
have an impact on financial results. See discussion of these instruments in Note
18, Restatement and Reclassification.
Commodity Price Risk: For purposes other than trading, we enter into
electric call options, fixed-priced weather-based gas supply call options, and
fixed-priced gas supply call and put options. The electric call options are used
to protect against the risk of fluctuations in the market price of electricity,
and to ensure a reliable source of capacity to meet our customers' electric
needs. The weather-based gas supply call options, along with the gas supply call
and put options, are used to purchase reasonably priced gas supply. Call options
give us the right, but not the obligation, to purchase gas supply at
predetermined fixed prices. Put options give third-party suppliers the right,
but not the obligation, to sell gas supply to us at predetermined fixed prices.
The commodity price risk sensitivity analysis was not material for the
years ending December 31, 2003 and December 31, 2002.
Trading Activity Commodity Price Risk: We are exposed to market
fluctuations in the price of energy commodities. We employ established policies
and procedures to manage these risks and may use various commodity derivatives,
including futures, options, and swap contracts. The prices of these energy
commodities can fluctuate because of, among other things, changes in the supply
of and demand for those commodities.
Trading Activity Commodity Price Risk Sensitivity Analysis (assuming a 10
percent adverse change in market prices):
In Millions
------------------------------------------------------
As of December 31 2003
------------------------------------------------------
Potential reduction in fair value:
Gas-related swaps and forward contracts $3
Electricity-related forward contracts 2
Electricity-related call option contracts 1
=================================================
A sensitivity analysis was not performed for the year ended December 31,
2002. There has been a significant change in trading activity in 2003 from the
prior year. As noted in "Trading Activities" within this section, the fair value
of contracts outstanding has decreased from $81 million at December 31, 2002 to
$15 million at December 31, 2003. For further information, see "Trading
Activities" within this section.
Currency Exchange Risk: We are exposed to currency exchange risk arising
from investments in foreign operations as well as various international projects
in which we have an equity interest and which have debt denominated in U.S.
dollars. We typically use forward exchange contracts and other risk mitigating
instruments to hedge currency exchange rates. The impact of hedges on our
investments in foreign operations is reflected in accumulated other
comprehensive income as a component of the foreign currency translation
adjustment. Gains or losses from the settlement of these hedges are maintained
in the foreign currency translation adjustment until we sell or liquidate the
investments on which the hedges were taken. At December 31, 2003, we had no
foreign exchange hedging contracts outstanding. As of December 31, 2003, the
total foreign currency translation adjustment was a net loss of $419 million,
which included a net hedging loss of $18 million related to settled contracts.
Equity Securities Price Risk: We are exposed to price risk associated with
investments in equity securities. As discussed in "Financial Instruments" within
this section, our investments in equity securities are classified as
available-for-sale securities. They are reported at fair value, with any
unrealized gains or losses resulting from changes in fair value reported in
equity as part of accumulated other comprehensive income and are excluded from
earnings unless such changes in fair value are determined to be other than
temporary. Unrealized gains or losses resulting from changes in the fair value
of our nuclear decommissioning investments are reported as regulatory
liabilities.
99
Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent
adverse change in market prices):
In Millions
--------------------------------------------------
As of December 31 2003 2002
--------------------------------------------------
Potential reduction in fair value:
Nuclear decommissioning investments $57 $49
Equity investments 7 6
=================================================
For additional details on market risk and derivative activities, see Note
7, Financial and Derivative Instruments.
INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY
We have investments in energy-related projects throughout the world. As a
result of a change in business strategy, over the last two years we have been
selling certain foreign investments. For additional details on the divestiture
of foreign investments see Note 2, Discontinued Operations, Other Asset Sales,
Impairments, and Restructuring.
BALANCE SHEET: Our subsidiaries and affiliates whose functional currency
is other than the U.S. dollar translate their assets and liabilities into U.S.
dollars at the exchange rates in effect at the end of the fiscal period. Gains
or losses that result from this translation and gains or losses on long-term
intercompany foreign currency transactions are reflected as a component of
stockholders' equity in the Consolidated Balance Sheets as "Foreign Currency
Translation." As of December 31, 2003, cumulative foreign currency translation
decreased stockholders' equity by $419 million. We translate the revenue and
expense accounts of these subsidiaries and affiliates into U.S. dollars at the
average exchange rate during the period.
AUSTRALIA: At December 31, 2003, the net foreign currency loss due to the
exchange rate of the Australian dollar recorded in the Foreign Currency
Translation component of stockholders' equity using an exchange rate of 1.335
Australian dollars per U.S. dollars was $95 million. This amount includes an
unrealized loss related to our investment in Loy Yang. This unrealized loss, and
the impact of certain deferred taxes associated with the Loy Yang investment,
will be realized upon sale, full liquidation, or other disposition of our
investment in Loy Yang for a total loss of approximately $110 million. In July
2003, we executed a conditional share sale agreement for our investment in Loy
Yang. For additional details, see "Outlook -- Enterprises Outlook" section
within this MD&A.
ARGENTINA: In January 2002, the Republic of Argentina enacted the Public
Emergency and Foreign Exchange System Reform Act. This law repealed the fixed
exchange rate of one U.S. dollar to one Argentina peso, converted all
dollar-denominated utility tariffs and energy contract obligations into pesos at
the same one-to-one exchange rate, and directed the President of Argentina to
renegotiate such tariffs.
Effective April 30, 2002, we adopted the Argentine peso as the functional
currency for our Argentine investments. We had used previously the U.S. dollar
as the functional currency. As a result, we translated the assets and
liabilities of our Argentine entities into U.S. dollars using an exchange rate
of 3.45 pesos per U.S. dollar, and recorded an initial charge to the Foreign
Currency Translation component of stockholders' equity of $400 million.
While we cannot predict future peso-to-U.S. dollar exchange rates, we do
expect that these non-cash charges reduce substantially the risk of further
material balance sheet impacts when combined with anticipated proceeds from
international arbitration currently in progress, political risk insurance, and
the eventual sale of these assets. At December 31, 2003, the net foreign
currency loss due to the unfavorable exchange rate of the Argentine peso
recorded in the Foreign Currency Translation component of stockholders' equity
using an exchange rate of 2.94 pesos per U.S. dollar was $264 million. This
amount also reflects the effect of recording, at December 31, 2002, U.S. income
taxes on temporary differences between the book and tax bases of foreign
investments, including the foreign currency translation associated with our
Argentine investments that were no longer considered permanent. For additional
details, see Note 8, Income Taxes.
INCOME STATEMENT: We use the U.S. dollar as the functional currency of
subsidiaries operating in highly inflationary economies and of subsidiaries that
meet the U.S. dollar functional currency criteria outlined in SFAS
100
No. 52. Gains and losses that arise from transactions denominated in a currency
other than the U.S. dollar, except those that are hedged, are included in
determining net income.
HEDGING STRATEGY: We may use forward exchange and option contracts to
hedge certain receivables, payables, long-term debt, and equity value relating
to foreign investments. The purpose of our foreign currency hedging activities
is to reduce risk associated with adverse changes in currency exchange rates
that could affect cash flow materially. These contracts would not subject us to
risk from exchange rate movements because gains and losses on such contracts are
inversely correlated with the losses and gains, respectively, on the assets and
liabilities being hedged.
ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION
Because we are involved in a regulated industry, regulatory decisions
affect the timing and recognition of revenues and expenses. We use SFAS No. 71
to account for the effects of these regulatory decisions. As a result, we may
defer or recognize revenues and expenses differently than a non-regulated
entity.
For example, items that a non-regulated entity normally would expense, we
may record as regulatory assets if the actions of the regulator indicate such
expenses will be recovered in future rates. Conversely, items that non-
regulated entities may normally recognize as revenues, we may record as
regulatory liabilities if the actions of the regulator indicate they will
require such revenues be refunded to customers. Judgment is required to
determine the recoverability of items recorded as regulatory assets and
liabilities. As of December 31, 2003, we had $1.105 billion recorded as
regulatory assets and $1.467 billion recorded as regulatory liabilities.
For additional details on industry regulation, see Note 1, Corporate
Structure and Accounting Policies, "Utility Regulation."
ACCOUNTING FOR PENSION AND OPEB
PENSION: We have established external trust funds to provide retirement
pension benefits to our employees under a non-contributory, defined benefit
Pension Plan. We have implemented a cash balance plan for employees hired after
June 30, 2003. We use SFAS No. 87 to account for pension costs.
OPEB: We provide postretirement health and life benefits under our OPEB
plan to substantially all our retired employees. We use SFAS No. 106 to account
for other postretirement benefit costs.
Liabilities for both pension and OPEB are recorded on the balance sheet at
the present value of their future obligations, net of any plan assets. The
calculation of the liabilities and associated expenses requires the expertise of
actuaries. Many assumptions are made including:
- life expectancies,
- present-value discount rates,
- expected long-term rate of return on plan assets,
- rate of compensation increases, and
- anticipated health care costs.
Any change in these assumptions can change significantly the liability and
associated expenses recognized in any given year.
The following table provides an estimate of our pension expense, OPEB
expense, and cash contributions for the next three years:
In Millions
-----------------------------------------------------
Pension Expense OPEB Expense Contributions
-----------------------------------------------------
2004 $ 21 $ 66 $ 98
2005 44 63 123
2006 67 61 131
=================================================
101
Actual future pension expense and contributions will depend on future
investment performance, changes in future discount rates, and various other
factors related to the populations participating in the Pension Plan.
Lowering the expected long-term rate of return on the Pension Plan assets
by 0.25 percent (from 8.75 percent to 8.50 percent) would increase estimated
pension expense for 2004 by $2 million. Lowering the discount rate by 0.25
percent (from 6.25 percent to 6.00 percent) would increase estimated pension
expense for 2004 by $4 million.
In August 2003, we made a planned contribution of $210 million to the
Pension Plan. In December 2003, we made an additional contribution of $350
million. As a result of these contributions, we reversed the additional minimum
liability and the resulting decrease in equity that we charged in 2002. As of
December 31, 2003, we have a prepaid pension asset of $408 million recorded on
our consolidated balance sheets.
Market-Related Valuation: We determine pension expense based on a
market-related valuation of assets, which reduces year-to-year volatility. The
market-related valuation recognizes investment gains or losses over a five-year
period from the year in which the gains or losses occur. Investment gains or
losses for this purpose are the difference between the expected return
calculated using the market-related value of assets and the actual return based
on the market value of assets. Since the market-related value of assets
recognizes gains or losses over a five-year period, the future value of assets
will be impacted as previously deferred gains or losses are recorded.
Due to the unfavorable performance of the equity markets in the past few
years, as of December 31, 2003, we had cumulative losses of approximately $239
million that remain to be recognized in the calculation of the market-related
value of assets. These unrecognized net actuarial losses may result in increases
in future pension expense in accordance with SFAS No. 87.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003
was signed into law in December 2003. This Act establishes a prescription drug
benefit under Medicare (Medicare Part D), and a federal subsidy to sponsors of
retiree health care benefit plans that provide a benefit that is actuarially
equivalent to Medicare Part D. We are deferring recognizing the effects of the
Act in our 2003 financial statements, as permitted by FASB Staff Position No.
106-1. When accounting guidance is issued, our retiree health benefit obligation
may be adjusted.
For additional details on postretirement benefits, see Note 10, Retirement
Benefits.
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, Accounting for Asset Retirement Obligations, became
effective January 2003. It requires companies to record the fair value of the
cost to remove assets at the end of their useful lives, if there is a legal
obligation to remove them. We have legal obligations to remove some of our
assets, including our nuclear plants, at the end of their useful lives. As
required by SFAS No. 71, we accounted for the implementation of this standard by
recording a regulatory asset and liability for regulated entities instead of a
cumulative effect of a change in accounting principle. Accretion of $1 million
related to the Big Rock and Palisades' profit component included in the
estimated cost of removal was expensed for 2003.
The fair value of ARO liabilities has been calculated using an expected
present value technique. This technique reflects assumptions, such as costs,
inflation, and profit margin that third parties would consider to assume the
settlement of the obligation. Fair value, to the extent possible, should include
a market risk premium for unforeseeable circumstances. No market risk premium
was included in our ARO fair value estimate since a reasonable estimate could
not be made.
If a reasonable estimate of fair value cannot be made in the period the
asset retirement obligation is incurred, such as assets with indeterminate
lives, the liability is to be recognized when a reasonable estimate of fair
value can be made. Generally, transmission and distribution assets have
indeterminate lives. Retirement cash flows cannot be determined. There is a low
probability of a retirement date, so no liability has been recorded for these
assets. No liability has been recorded for assets that have insignificant
cumulative disposal costs, such as substation batteries. The measurement of the
ARO liabilities for Palisades and Big Rock are based on decommissioning studies
that are based largely on third-party cost estimates.
102
Reclassification of Non-Legal Cost of Removal: Beginning in December 2003,
the SEC requires the quantification and reclassification of the estimated cost
of removal obligations arising from other than legal obligations. These
obligations have been accrued through depreciation charges. We estimate that we
had $983 million in 2003 and $907 million in 2002 of previously accrued asset
removal costs related to our regulated operations, for other than legal
obligations. These obligations, which were previously classified as a component
of accumulated depreciation, were reclassified as regulatory liabilities in the
accompanying consolidated balance sheets.
For additional details on ARO, see Note 16, Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and FERC regulate the recovery of costs to decommission our Big
Rock and Palisades nuclear plants. They require, and we have established,
external trust funds to finance the decommissioning of both plants. Our electric
customers pay a surcharge to fund these trusts. We record the trust fund
balances as a non-current asset on our balance sheet.
Our decommissioning cost estimates for the Big Rock and Palisades plants
assume:
- each plant site will be restored to conform to the adjacent
landscape,
- all contaminated equipment and material will be removed and disposed
of in a licensed burial facility, and
- the site will be released for unrestricted use.
Independent contractors with expertise in decommissioning have helped us
develop decommissioning cost estimates. Various inflation rates for labor,
non-labor, and contaminated equipment disposal costs are used to escalate these
cost estimates to the future decommissioning cost. A portion of future
decommissioning cost will result from the failure of the DOE to remove fuel from
the sites, as required by the Nuclear Waste Policy Act of 1982. Spent fuel
storage costs would not be incurred if the DOE took possession of the spent
fuel. There is litigation underway to recover these costs.
The decommissioning trust funds include equities and fixed income
investments. Equities will be converted to fixed income investments during
decommissioning, and fixed income investments are converted to cash as needed.
In December 2000, funding of the Big Rock trust fund was stopped since it was
considered fully funded, subject to further MPSC review. The funds provided by
the trusts, additional customer surcharges, and potential funds from DOE
litigation are all required to cover fully the decommissioning costs, and we
currently expect that to happen. The costs of decommissioning these sites and
the adequacy of the trust funds could be affected by:
- variances from expected trust earnings,
- a lower recovery of costs from the DOE and lower rate recovery from
customers, and
- changes in decommissioning technology, regulations, estimates or
assumptions.
For additional details on nuclear decommissioning, see Note 1, Corporate
Structure and Accounting Policies, "Nuclear Plant Decommissioning."
CAPITAL RESOURCES AND LIQUIDITY
Our liquidity and capital requirements are a function of our results of
operations, capital expenditures, contractual obligations, debt maturities,
working capital needs, and collateral requirements. During the summer months, we
purchase natural gas and store it for resale primarily during the winter heating
season. Recently, the market price for natural gas has increased. Although our
natural gas purchases are recoverable from our customers, the amount paid for
natural gas stored as inventory could require additional liquidity due to the
timing of the cost
103
recoveries. In addition, a few of our commodity suppliers have requested advance
payment or other forms of assurances, including margin calls, in connection with
maintenance of ongoing deliveries of gas and electricity.
At the beginning of 2003, we had debt maturities and capital expenditures
that required substantial amounts of cash. We were also subject to liquidity
demands of various commercial commitments, such as guarantees, indemnities, and
letters of credit. As a result, in 2003, we executed a financial improvement
plan to address these critical liquidity issues.
In January 2003, we suspended payment of the common stock dividend and
increased our efforts to reduce operating expenses and capital expenditures. We
continued to sell non-strategic assets and we used the proceeds to reduce debt.
Gross proceeds from asset sales were $939 million in 2003. Finally, we explored
financing opportunities, such as refinancing debt, issuing new debt and
preferred equity, and negotiating private placement debt. Together, all of these
steps enabled us to meet our liquidity demands.
In 2004, we will continue to monitor our operating expenses and capital
expenditures, evaluate market conditions for financing opportunities, and sell
assets that are not consistent with our strategy. We do not anticipate paying
dividends in the foreseeable future. The Board of Directors may reconsider or
revise this policy from time to time based upon certain conditions, including
our results of operations, financial condition, and capital requirements, as
well as other relevant factors. We believe our current level of cash and
borrowing capacity, along with anticipated cash flows from operating and
investing activities, will be sufficient to meet our liquidity needs through
2005.
CASH POSITION, INVESTING, AND FINANCING
Consolidated cash needs are met by our operating, investing and financing
activities. At December 31, 2003, $733 million consolidated cash was on hand
which includes $201 million of restricted cash. For additional details on
restricted cash, see Note 1, Corporate Structure and Accounting Policies.
Our primary ongoing source of cash is dividends and other distributions
from our subsidiaries, including proceeds from asset sales. In 2003, Consumers
paid $218 million in common stock dividends and Enterprises paid $536 million in
common stock dividends and other distributions to us. Enterprises' other
distributions include a transfer of 1,967,640 shares of CMS Energy Common Stock,
valued at $16 million, in the form of a stock dividend. There was no impact on
shares outstanding or the consolidated income statement from this distribution.
SELECTED MEASURES OF LIQUIDITY AND CAPITAL RESOURCES:
2003
---------------------------------------------------
Working capital (in millions) $ 844
Current ratio 1.51:1
===================================================
Workingcapital in 2003 was primarily driven by the following:
- cash proceeds from long-term debt issuance -- $2.080 billion,
- cash proceeds from asset sales -- $939 million, and
- cash proceeds from preferred stock issuance/sale -- $272 million.
partially offset by:
- cash used for long-term debt retirements, excluding current portion
-- $1.531 billion,
- cash used for pension contributions -- $560 million, and
- cash used for purchase of property, plant and equipment -- $535
million.
104
SUMMARY OF CASH FLOWS:
In Millions
-----------------------------------------------------------------------------------
Restated Restated
2003 2002 2001
-----------------------------------------------------------------------------------
Net cash provided by (used in):
Operating activities $ (251) $ 614 $ 372
Investing activities 203 829 (1,349)
Financing activities 230 (1,223) 967
Effect of exchange rates on cash (1) 8 (10)
----------------------------------------------------------------------------------
Net increase (decrease) in cash and temporary cash
investments $ 181 $ 228 $ (20)
==================================================================================
OPERATING ACTIVITIES:
2003: Net cash used in operating activities was $251 million in 2003
compared to net cash provided by operating activities of $614 million in 2002.
The change of $865 million was primarily due to an increase in pension plan
contributions of $496 million, an increase in inventories of $428 million due to
higher gas purchases at higher prices by our gas utility operations, and a
decrease in accounts payable and accrued expenses of $232 million due primarily
to the sale of CMS MST's wholesale gas and power contracts. This change was
partially offset by a decrease in accounts receivable and accrued revenue of
$101 million due primarily to the sale of CMS MST's wholesale gas and power
contracts.
2002: Net cash provided by operating activities increased $242 million in
2002 primarily due to a decrease in inventories of $479 million due to a lower
volume of gas purchased at lower prices, combined with increased sales volumes
at higher prices at our gas utility. This increase was partially offset by a
smaller decrease in accounts receivable and accrued revenues of $238 million.
INVESTING ACTIVITIES:
2003: Net cash provided by investing activities decreased $626 million in
2003 due primarily to a decrease in asset sale proceeds of $720 million,
primarily from the sale of Equatorial Guinea, Powder River, and CMS Oil and Gas
in 2002, offset by a decrease in 2003 versus 2002 capital expenditures of $212
million as a result of our strategic plan to reduce capital expenditures.
2002: Net cash provided by investing activities increased $2.178 billion
in 2002 due primarily to a decrease in capital expenditures of $492 million as a
result of our strategic plan to reduce capital expenditures, and an increase in
asset sale proceeds of $1.525 billion, resulting primarily from the sales of
Equatorial Guinea, Powder River, and CMS Oil and Gas.
FINANCING ACTIVITIES:
2003: Net cash provided by financing activities increased $1.453 billion
in 2003 due primarily to an increase in net proceeds from borrowings of $988
million and net proceeds from preferred securities issuances/ sale of $272
million. For additional details on long-term debt activity, see Note 5,
Financings and Capitalization.
2002: Net cash used in financing activities increased $2.190 billion in
2002 due primarily to a decrease in net proceeds from borrowings of $1.733
billion and a decrease in net proceeds from common stock and preferred
securities of $454 million.
OBLIGATIONS AND COMMITMENTS
The following information on our contractual obligations, off-balance
sheet arrangements, and commercial commitments is provided to collect
information in a single location so that a picture of liquidity and capital
resources is readily available. For additional information on our obligations
and commitments see Note 5, Financings and Capitalization.
105
Contractual Obligations In Millions
---------------------------------------------------------------------------------------------------------
Payments Due
---------------------------------------------------------
December 31 Total 2004 2005 2006 2007 2008 Beyond
---------------------------------------------------------------------------------------------------------
On-balance sheet:
Long-term debt $ 6,529 $ 509 $ 696 $ 490 $ 516 $ 987 $ 3,331
Long-term debt -- related parties 684 -- -- -- -- -- 684
Capital lease obligations 68 10 11 10 10 8 19
---------------------------------------------------------------------------------------------------------
Total on-balance sheet $ 7,281 $ 519 $ 707 $ 500 $ 526 $ 995 $ 4,034
---------------------------------------------------------------------------------------------------------
Off-balance sheet:
Non-recourse debt $ 2,909 $ 233 $ 123 $ 170 $ 85 $ 101 $ 2,197
Interest payments on long-term
debt(a) 4,135 460 424 404 377 311 2,159
Capital lease obligation -- MCV 144 16 9 8 8 8 95
Operating leases 78 12 10 10 9 7 30
Sale of accounts receivable 297 297 -- -- -- -- --
Unconditional purchase
obligations(b) 16,370 1,895 1,258 892 711 670 10,944
---------------------------------------------------------------------------------------------------------
Total off-balance sheet $23,933 $ 2,913 $ 1,824 $ 1,484 $ 1,190 $ 1,097 $15,425
=========================================================================================================
(a) This represents currently scheduled interest payments on both variable and
fixed rate long-term debt, long-term debt - related parties, and the
current portion of long-term debt. Variable rate interest payments are
based on the contractual rates in effect at December 31, 2003.
(b) This excludes purchase obligations that Consumers has with Genesee,
Grayling, and Filer City generating plants because these entities are
consolidated under FASB Interpretation No. 46. Purchase obligations
related to the MCV Facility PPA assume that the regulatory out provision
is exercised in 2007. For additional details, see Note 4, Uncertainties,
"Other Consumers' Electric Utility Uncertainties -- The Midland
Cogeneration Venture."
REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers must obtain FERC
authority to issue short and long-term securities. For additional details of
Consumers' existing authority, see Note 5, Financings and Capitalization.
LONG-TERM DEBT: Details on long-term debt and preferred securities
issuances, retirements, and outstanding balances are presented in Note 5,
Financings and Capitalization.
SHORT-TERM FINANCINGS: CMS Energy has $190 million available and Consumers
has $390 million available under revolving credit facilities. At December 31,
2003, the lines are available for general corporate purposes, working capital,
and letters of credit. Additional details are in Note 5, Financings and
Capitalization.
CAPITAL LEASE OBLIGATIONS: Our capital leases are comprised mainly of
leased service vehicles and office furniture. The full obligation of our leases
could become due in the event of lease payment default.
OFF-BALANCE SHEET ARRANGEMENTS: We use off-balance sheet arrangements in
the normal course of business. Our off-balance sheet arrangements include:
- operating leases,
- non-recourse debt,
- sale of accounts receivable, and
- unconditional purchase obligations.
Operating Leases: Our leases of railroad cars, certain vehicles, and
miscellaneous office equipment are accounted for as operating leases.
Non-recourse Debt: Our share of unconsolidated debt associated with
partnerships and joint ventures in which we have a minority interest is
non-recourse.
106
Sale of Accounts Receivable: Under a revolving accounts receivable sales
program, we currently sell up to $325 million of certain accounts receivable.
For additional details, see Note 5, Financings and Capitalization.
Unconditional Purchase Obligations: Long-term contracts for purchase of
commodities and services are unconditional purchase obligations. These
obligations represent operating contracts used to assure adequate supply with
generating facilities that meet PURPA requirements. The commodities and services
include:
- natural gas,
- electricity,
- coal purchase contracts and their associated cost of transportation,
and
- electric transmission.
Included in unconditional purchase obligations are long-term power
purchase agreements with various generating plants including the MCV Facility.
These contracts require us to make monthly capacity payments based on the
plants' availability or deliverability. These payments will approximate $43
million per month during 2004, including $34 million related to the MCV
Facility. If a plant is not available to deliver electricity, we are not
obligated to make the capacity payments to the plant for that period of time.
For additional details on power supply costs, see "Electric Utility Results of
Operations" within this MD&A and Note 4, Uncertainties, "Consumers' Electric
Utility Rate Matters -- Power Supply Costs," and "Other Consumers' Electric
Utility Uncertainties -- The Midland Cogeneration Venture."
Commercial Commitments: Our commercial commitments include indemnities and
letters of credit. Indemnities are agreements to reimburse other companies, such
as an insurance company, if those companies have to complete our contractual
performance in a third party contract. Banks, on our behalf, issue letters of
credit guaranteeing payment to a third party. Letters of credit substitute the
bank's credit for ours and reduce credit risk for the third party beneficiary.
We monitor and approve these obligations and believe it is unlikely that we
would be required to perform or otherwise incur any material losses associated
with these guarantees.
Commercial Commitments In Millions
--------------------------------------------------------------------------
Commitment Expiration
--------------------------------------------------------------------------
December 31 Total 2004 2005 2006 2007 2008 Beyond
--------------------------------------------------------------------------
Off-balance sheet:
Guarantees $239 $ 20 $ 36 $ 4 $ -- $ -- $179
Indemnities 28 8 -- -- -- -- 20
Letters of Credit(a) 254 215 10 5 5 5 14
-------------------------------------------------------------------------
Total $521 $243 $ 46 $ 9 $ 5 $ 5 $213
=========================================================================
(a) At December 31, 2003, we had $175 million of cash collateralized letters
of credit and the cash used to collateralize the letters of credit is
included in Restricted Cash on the Consolidated Balance Sheets.
DIVIDEND RESTRICTIONS: Under the provisions of its articles of
incorporation, at December 31, 2003, Consumers had $373 million of unrestricted
retained earnings available to pay common dividends. However, covenants in
Consumers debt facilities cap common stock dividend payments at $300 million in
a calendar year. Through December 31, 2003, we received the following common
stock dividend payments from Consumers:
In Millions
----------------------------------------------------------------
January $ 78
May 31
June 53
November 56
------------------------------------------------------------
Total common stock dividends paid to CMS Energy $218
============================================================
As of December 18, 2003, Consumers is also under an annual dividend cap of
$190 million imposed by the MPSC during the current interim gas rate relief
period. Because all of the $218 million of common stock dividends
107
to CMS energy were paid prior to December 18, 2003, Consumers was not out of
compliance with this new restriction for 2003. In February 2004, Consumers paid
a $78 million common stock dividend.
For additional details on the potential cap on common dividends payable
included in the MPSC Securitization order see Note 4, Uncertainties, "Consumers'
Electric Utility Rate Matters -- Securitization." Also, for additional details
on the cap on common dividends payable during the current interim gas rate
relief period, see Note 4, Uncertainties, "Consumers' Gas Utility Rate Matters
-- 2003 Gas Rate Case."
CAPITAL EXPENDITURES
We estimate the following capital expenditures, including new lease
commitments, by expenditure type and by business segments during 2004 through
2006. We prepare these estimates for planning purposes and may revise them.
In Millions
------------------------------------------------------------
Years Ending December 31 2004 2005 2006
------------------------------------------------------------
Electric utility operations(a)(b) $395 $370 $570
Gas utility operations(a) 155 185 170
Enterprises 85 5 5
------------------------------------------------------------
$635 $560 $745
============================================================
(a) These amounts include an attributed portion of Consumers' anticipated
capital expenditures for plant and equipment common to both the electric
and gas utility businesses.
(b) These amounts include estimates for capital expenditures that may be
required by recent revisions to the Clean Air Act's national air quality
standards.
OUTLOOK
CORPORATE OUTLOOK
During 2003, we continued to implement a back-to-basics strategy that
focuses on growing a healthy utility and divesting under-performing or other
non-strategic assets. The strategy is designed to generate cash to pay down
debt, reduce business risk, and provide for more predictable future operating
revenues and earnings.
Consistent with our back-to-basics strategy, we are pursuing actively the
sale of non-strategic and under-performing assets and have received $3.6 billion
of cash from asset sales, securitization proceeds and proceeds from LNG
monetization since 2001. For additional details, see Note 2, Discontinued
Operations, Other Asset Sales, Impairments, and Restructuring. Some of these
assets are recorded at estimates of their current fair value. Upon the sale of
these assets, the proceeds realized may be different from the recorded values if
market conditions have changed. Even though these assets have been identified
for sale, we cannot predict when, nor make any assurance that, these sales will
occur. We anticipate that the sales, if any, will result in additional cash
proceeds that will be used to retire existing debt.
As we continue to implement our back-to-basics strategy and further reduce
our ownership of non-utility assets, the percentage of our future earnings
relating to Jorf Lasfar and the MCV Partnership may increase and our total
future earnings may depend more significantly upon the performance of Jorf
Lasfar and the MCV Partnership. For the year ended December 31, 2003, earnings
from our equity method investment in Jorf Lasfar were $61 million and earnings
from our equity method investment in the MCV Partnership were $29 million.
ELECTRIC UTILITY BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect electric deliveries to grow at
an average rate of approximately two percent per year based primarily on a
steadily growing customer base and economy. This growth rate includes both full
service sales and delivery service to customers who choose to buy generation
service from an alternative electric supplier, but excludes transactions with
other wholesale market participants and other electric utilities. This growth
108
rate reflects a long-range expected trend of growth. Growth from year to year
may vary from this trend due to customer response to abnormal weather conditions
and changes in economic conditions, including utilization and expansion of
manufacturing facilities.
For 2003, our electric deliveries, including delivery to customers who
chose to buy generation service from an alternative electric supplier, declined
1.4 percent from 2002. This was due to a combination of warmer than normal
summer weather in 2002, cooler than normal summer weather in 2003, and a decline
in manufacturing activity during 2003. In 2004, we project electric deliveries
to grow more than three percent. This short-term outlook for 2004 assumes higher
levels of manufacturing activity than in 2003 and normal weather conditions
throughout the year.
ELECTRIC UTILITY BUSINESS UNCERTAINTIES
Several electric business trends or uncertainties may affect our financial
results and condition. These trends or uncertainties have, or we reasonably
expect could have, a material impact on revenues or income from continuing
electric operations. Such trends and uncertainties include:
Environmental
- increasing capital expenditures and operating expenses for Clean Air
Act compliance, and
- potential environmental liabilities arising from various
environmental laws and regulations, including potential liability or
expenses relating to the Michigan Natural Resources and
Environmental Protection Acts and Superfund.
Restructuring
- response of the MPSC and Michigan legislature to electric industry
restructuring issues,
- ability to meet peak electric demand requirements at a reasonable
cost, without market disruption,
- ability to recover any of our net Stranded Costs under the
regulatory policies being followed by the MPSC,
- recovery of electric restructuring implementation costs,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer instead of an electric
transmission owner-operator.
Regulatory
- effects of conclusions about the causes of the August 14, 2003
blackout, including exposure to liability, increased regulatory
requirements, and new legislation,
- successful implementation of initiatives to reduce exposure to
purchased power price increases,
- effects of potential performance standards payments, and
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel.
Other
- effects of commodity fuel prices such as natural gas and coal,
- pending litigation filed by PURPA qualifying facilities,
109
- potential rising pension costs due to market losses and lump sum
payments. For additional details, see "Accounting for Pension and
OPEB" section within this MD&A.
- pending litigation and government investigations.
For additional details about these trends or uncertainties, see Note 4,
Uncertainties.
ELECTRIC ENVIRONMENTAL ESTIMATES: Our operations are subject to
environmental laws and regulations. Costs to operate our facilities in
compliance with these laws and regulations generally have been recovered in
customer rates.
Compliance with the federal Clean Air Act and resulting regulations has
been, and will continue to be, a significant focus for us. The Title I
provisions of the Clean Air Act require significant reductions in nitrogen oxide
emissions. To comply with the regulations, we expect to incur capital
expenditures totaling $771 million. The key assumptions included in the capital
expenditure estimate include:
- construction commodity prices, especially construction material and
labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- allowance for funds used during construction (AFUDC) rate.
Our current capital cost estimates include an escalation rate of 2.6
percent and an AFUDC capitalization rate of 8.1 percent. As of December 31,
2003, we have incurred $446 million in capital expenditures to comply with these
regulations and anticipate that the remaining $325 million of capital
expenditures will be made between 2004 and 2009. These expenditures include
installing catalytic reduction technology on coal-fired electric plants. In
addition to modifying the coal-fired electric plants, we expect to purchase
nitrogen oxide emissions credits for years 2004 through 2008. The cost of these
credits is estimated to average $8 million per year and is accounted for as
inventory.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants.
Future clean air regulations requiring emission controls for sulfur
dioxide, nitrogen oxides, mercury, and nickel may require additional capital
expenditures. Total expenditures will depend upon the final makeup of the new
regulations.
The EPA continues to make new rules. The EPA has proposed changes to the
rules that govern generating plant cooling water intake systems. The proposed
rules are scheduled to be final in the first quarter of 2004. We are studying
the proposed rules to determine the most cost-effective solutions for
compliance.
For additional details on electric environmental matters, see Note 4,
Uncertainties, "Consumers' Electric Utility Contingencies -- Electric
Environmental Matters."
COMPETITION AND REGULATORY RESTRUCTURING: Michigan's Customer Choice Act
and other developments will continue to result in increased competition in the
electric business. Generally, increased competition reduces profitability and
threatens market share for generation services. As of January 1, 2002, the
Customer Choice Act allowed all of our electric customers to buy electric
generation service from us or from an alternative electric supplier. As a
result, alternative electric suppliers for generation services have entered our
market. As of March 2004, alternative electric suppliers are providing 735 MW of
generation supply to ROA customers. This amount represents nine percent of our
distribution load and an increase of 42 percent compared to March 2003. We
anticipate this upward trend to continue and expect over 1,000 MW of generation
supply to ROA customers in 2004. We cannot predict the total amount of electric
supply load that may be lost to competitor suppliers.
110
In February 2004, the MPSC issued an order on Detroit Edison's request for
rate relief for costs associated with customers leaving under electric customer
choice. The MPSC order allows Detroit Edison to charge a transition surcharge of
approximately 0.4 cent per kWh to ROA customers and eliminates securitization
offsets of 0.7 cents per kWh for primary service customers and 0.9 cents per kWh
for secondary service customers. We are seeking similar recovery of Stranded
Costs due to ROA customers leaving our system and are encouraged by this ruling.
This ruling may change significantly the anticipated number of customers who
choose ROA.
Securitization: In March 2003, we filed an application with the MPSC
seeking approval to issue Securitization bonds. In June 2003, the MPSC issued a
financing order authorizing the issuance of Securitization bonds in the amount
of approximately $554 million. In July 2003, we filed for rehearing and
clarification on a number of features in the financing order.
In December 2003, the MPSC issued its order on rehearing, which rejected
our requests for clarification and modification to the dividend payment
restriction, failed to rule directly on the accounting clarifications requested,
and remanded the proceeding to the ALJ for additional proceedings to address
rate design. We filed testimony regarding the remanded proceeding in February
2004. The financing order will become effective after acceptance by us and
resolution of any appeals.
Stranded Costs: To the extent we experience net Stranded Costs as
determined by the MPSC, the Customer Choice Act allows us to recover such costs
by collecting a transition surcharge from customers who switch to an alternative
electric supplier. We cannot predict whether the Stranded Cost recovery method
adopted by the MPSC will be applied in a manner that will fully offset any
associated margin loss.
In 2002 and 2001, the MPSC issued orders finding that we experienced zero
net Stranded Costs from 1999 to 2001. The MPSC also declined to resolve numerous
issues regarding the net Stranded Cost methodology in a way that would allow a
reliable prediction of the level of Stranded Costs for future years. We
currently are in the process of appealing these orders with the Michigan Court
of Appeals and the Michigan Supreme Court.
In March 2003, we filed an application with the MPSC seeking approval of
net Stranded Costs incurred in 2002, and for approval of a net Stranded Cost
recovery charge. Our net Stranded Costs incurred in 2002 are estimated to be $38
million with the issuance of Securitization bonds that include Clean Air Act
investments, or $85 million without the issuance of Securitization bonds that
include Clean Air Act investments.
Once the MPSC issues a final financing order on Securitization, we will
know the amount of our request for net Stranded Cost recovery for 2002. We
cannot predict how the MPSC will rule on our request for the recoverability of
Stranded Costs. Therefore, we have not recorded regulatory assets to recognize
the future recovery of such costs.
Implementation Costs: Since 1997, we have incurred significant costs to
implement the Customer Choice Act. The Customer Choice Act allows electric
utilities to recover the Act's implementation costs. The MPSC has reviewed and
allowed certain of the implementation costs incurred through 2001, but has not
authorized recovery. Depending upon the outcome of the remanded Securitization
proceeding, a significant portion of the implementation costs could be recovered
through the Securitization process.
Our application for $2 million of implementation costs in 2002 is
currently pending approval by the MPSC. We deferred these costs as a regulatory
asset. In addition to the implementation costs filed with the MPSC, as of
December 31, 2003, we recorded an additional $2 million for total implementation
costs of $91 million. Included in total implementation costs is $19 million
associated with the cost of money. We believe the implementation costs and the
associated cost of money are fully recoverable in accordance with the Customer
Choice Act. Cash recovery from customers is expected to begin after the rate cap
period has expired. For additional information on rate caps, see "Rate Caps"
within this section. Once a final financing order by the MPSC on Securitization
is issued, the recoverability of the implementation costs requested will be
known. We cannot predict the amounts the MPSC will approve as allowable costs.
Also, we are pursuing authorization at the FERC for MISO to reimburse us
for approximately $8 million in certain electric utility restructuring
implementation costs related to our former participation in the development of
111
the Alliance RTO, a portion of which has been expensed. In May 2003, the FERC
issued an order denying MISO's request for authorization to reimburse us. We
appealed the FERC ruling at the United States Court of Appeals for the District
of Columbia. In addition, we continue to pursue other potential means of
recovery with FERC. We cannot predict the outcome of the appeal process or the
ultimate amount, if any, the FERC will allow us to collect for implementation
costs.
Rate Caps: The Customer Choice Act imposes certain limitations on electric
rates that could result in us being unable to collect our full cost of
conducting business from electric customers. Such limitations include:
- a rate freeze effective through December 31, 2003, and
- rate caps effective through December 31, 2004 for small commercial
and industrial customers, and through December 31, 2005 for
residential customers.
As a result, we may be unable to maintain our profit margins in our
electric utility business during the rate cap periods. In particular, if we
needed to purchase power supply from wholesale suppliers while retail rates are
capped, the rate restrictions may make it impossible for us to fully recover
purchased power and associated transmission costs.
PSCR: Prior to 1998, the PSCR process provided for the reconciliation of
actual power supply costs with power supply revenues. This process assured
recovery of all reasonable and prudent power supply costs actually incurred by
us, including the actual cost for fuel, and purchased and interchange power. In
1998, as part of the electric restructuring efforts, the MPSC suspended the PSCR
process, effective through 2001. As a result of the rate freeze imposed by the
Customer Choice Act, frozen rates remained in effect until December 31, 2003,
and the PSCR process remained suspended. Therefore, changes in power supply
costs due to fluctuating electricity prices were not reflected in rates charged
to our customers during the rate freeze period.
As a result of meeting the transmission capability expansion requirements
and the market power test, we have met the requirements under the Customer
Choice Act to return to the PSCR process. For additional details see Note 4,
Uncertainties, "Consumers' Electric Utility Restructuring Matters -- Electric
Restructuring Legislation."
Accordingly, in September 2003, we submitted a PSCR filing to the MPSC
that reinstates the PSCR process for customers whose rates are no longer frozen
or capped as of January 1, 2004. The proposed PSCR charge allows us to recover a
portion of our increased power supply costs from large commercial and industrial
customers, and subject to the overall rate cap, from other customers. We
estimate the recovery of increased power supply costs from large commercial and
industrial customers to be approximately $30 million in 2004. As allowed under
current regulation, we self-implemented the proposed PSCR charge on January 1,
2004. The revenues received from the PSCR charge are also subject to subsequent
reconciliation at the end of the year after actual costs have been reviewed for
reasonableness and prudence. We cannot predict the outcome of this filing.
Decommissioning Surcharge: When our electric retail rates were frozen in
June 2000, a nuclear decommissioning surcharge related to the decommissioning of
Big Rock was included. We continued to collect the equivalent to the Big Rock
nuclear decommissioning surcharge consistent with the Customer Choice Act rate
freeze in effect through December 31, 2003. Collection of the surcharge stopped,
effective January 1, 2004, when the electric rate freeze expired. As a result,
our electric revenues will be reduced by $35 million in 2004. However, we expect
a portion of this reduction to be offset with increased electric revenues from
returning to the PSCR process.
Industrial Contracts: We entered into multi-year electric supply contracts
with certain large industrial customers. The contracts provide electricity at
specially negotiated prices, usually at a discount from tariff prices. The MPSC
approved these special contracts totaling approximately 685 MW of load. Unless
terminated or restructured, the majority of these contracts are in effect
through 2005. As of December 31, 2003, contracts for 301 MW of load have
terminated. Of the contracts that have terminated, contracts for 64 MW have gone
to an alternative electric supplier and contracts for 237 MW have returned to
bundled tariff rates. In January 2004, new special contracts for 91 MW, with the
State of Michigan and three universities, were approved by the MPSC. Other new
special contracts for 101 MW received interim approval from the MPSC and are
awaiting final approval. All new special contracts end
112
by January 1, 2006. We cannot predict the ultimate financial impact of changes
related to these power supply contracts, or whether additional special contracts
will be necessary or advisable.
Transmission Sale: In May 2002, we sold our electric transmission system
for $290 million to MTH. We are currently in arbitration with MTH regarding
property tax items used in establishing the selling price of our electric
transmission system. We cannot predict whether the remaining open items will
impact materially the sale proceeds previously recognized.
There are multiple proceedings and a proposed rulemaking pending before
the FERC regarding transmission pricing mechanisms and standard market design
for electric bulk power markets and transmission. The results of these
proceedings and proposed rulemakings could significantly affect:
- transmission cost trends,
- delivered power costs to us, and
- delivered power costs to our retail electric customers.
The financial impact of such proceedings, rulemaking and trends are not
currently quantifiable. In addition, we are evaluating whether or not there may
be impacts on electric reliability associated with the outcomes of these various
transmission related proceedings.
August 14, 2003 Blackout: On August 14, 2003, the electric transmission
grid serving parts of the Midwest and the Northeast experienced a significant
disturbance that impacted electric service to millions of homes and businesses.
Approximately 100,000 of our 1.7 million electric customers were without power
for approximately 24 hours as a result of the disturbance. We incurred $1
million of immediate expense as a result of the blackout. We continue to
cooperate with investigations of the blackout by several federal and state
agencies. We cannot predict the outcome of these investigations.
In November 2003, the MPSC released its report on the blackout. The MPSC
report found no evidence to suggest that the events in Michigan, or actions
taken by the Michigan utilities or transmission operators, were factors
contributing to the cause of the blackout. Also in November 2003, the United
States and Canadian power system outage taskforce preliminarily reported that
the primary cause of the blackout was due to transmission line contact with
trees in areas outside of Consumers' operating territory. In December 2003, the
MPSC issued an order requiring Consumers to report by April 1, 2004, the status
of lines used to serve our customers, including details of vegetation trimming
practices in calendar year 2003. Consumers intends to comply with the MPSC's
request.
In February 2004, the Board of Trustees of NERC approved recommendations
to improve electric transmission reliability. The key recommendations are as
follows:
- strengthen the NERC compliance enforcement program,
- evaluate vegetation management procedures, and
- improve technology to prevent or mitigate future blackouts.
These recommendations require transmission operators, which Consumers is
not, to submit annual reports on vegetation management beginning March 2005 and
improve technology over various milestones throughout 2004. These
recommendations could result in increased transmission costs payable by
transmission customers in the future. The financial impacts of these
recommendations are not currently quantifiable.
For additional details and material changes relating to the rate matters
and restructuring of the electric utility industry, see Note 4, Uncertainties,
"Consumers' Electric Utility Restructuring Matters," and "Consumers' Electric
Utility Rate Matters."
113
PERFORMANCE STANDARDS: Electric distribution performance standards
developed by the MPSC became effective in February 2004. The performance
standards establish standards related to restoration after an outage, safety,
and customer relations. Financial incentives and penalties are contained within
the performance standards. An incentive is possible if all of the established
performance standards have been exceeded for a calendar year. However, the value
of such incentive cannot be determined at this point as the performance
standards do not contain an approved incentive mechanism. Financial penalties in
the form of customer credits are also possible. These customer credits are based
on duration and repetition of outages. We cannot predict the likely effects of
the financial incentive or penalties, if any, on us.
GAS UTILITY BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect gas deliveries to grow at an
average rate of less than one percent per year. Actual gas deliveries in future
periods may be affected by:
- abnormal weather,
- use by independent power producers,
- competition in sales and delivery,
- Michigan economic conditions,
- gas consumption per customer, and
- increases in gas commodity prices.
GAS UTILITY BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our financial
results and conditions. These trends or uncertainties could have a material
impact on net sales, revenues, or income from gas operations. The trends and
uncertainties include:
Environmental
- potential environmental cost at a number of sites, including sites
formerly housing manufactured gas plant facilities.
Regulatory
- inadequate regulatory response to applications for requested rate
increases,
- potential adverse appliance service plan ruling or related
legislation, and
- response to increases in gas costs, including adverse regulatory
response and reduced gas use by customers,
Other
- potential rising pension costs due to market losses and lump sum
payments as discussed in the "Accounting for Pension and OPEB"
section within this MD&A, and
- pending litigation and government investigations.
Consumers sells gas to retail customers under tariffs approved by the
MPSC. These tariffs measure the gas delivered to customers based on the volume
(i.e. mcf) of gas delivered. However, Consumers purchases gas for resale on a
Btu basis. The Btu content of the gas available for purchase has increased and
may result in customers
114
using less gas for the same heating requirement. Consumers fully recovers what
it spends to purchase the gas through the approved GCR. However, since the
customer is using less gas on a volumetric basis, the revenue from the
distribution charge (the non-gas cost portion of the customer bill) would be
reduced. This could affect adversely Consumers' earnings from it gas utility.
The amount of the earnings loss in future periods cannot be estimated at this
time.
In September 2002, the FERC issued an order rejecting our filing to assess
certain rates for non-physical gas title tracking services we offered. In
December 2003, the FERC ruled that no refunds were at issue and we reversed a $4
million reserve related to this matter. In January 2004, three companies filed
with FERC for clarification or rehearing of FERC's December 2003 order. We
cannot predict the outcome of this filing.
GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. We expect our remaining remedial action costs to be between $37 million
and $90 million. Any significant change in assumptions, such as remediation
techniques, nature and extent of contamination, and legal and regulatory
requirements, could change the remedial action costs for the sites. For
additional details, see Note 4, Uncertainties, "Consumers' Gas Utility
Contingencies -- Gas Environmental Matters."
GAS COST RECOVERY: The MPSC is required by law to allow us to charge
customers for our actual cost of purchased natural gas. The GCR process is
designed to allow us to recover all of our gas costs; however, the MPSC reviews
these costs for prudency in an annual reconciliation proceeding. In January
2004, the MPSC staff and intervenors filed direct testimony in our 2002-2003 GCR
case proposing GCR recovery disallowances. In February 2004, the parties in the
case reached a tentative settlement agreement that would result in a GCR
disallowance of $11 million for the GCR period plus $1 million accrued interest
through February 2004. A reserve was recorded in December 2003. For additional
details, see Note 4, Uncertainties, "Consumers' Gas Utility Rate Matters -- Gas
Cost Recovery."
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC
for a $156 million annual increase in our gas delivery and transportation rates
that included a 13.5 percent return on equity. In September 2003, we filed an
update to our gas rate case that lowered the requested revenue increase from
$156 million to $139 million and reduced the return on common equity from 13.5
percent to 12.75 percent. The MPSC authorized an interim gas rate increase of
$19 million annually. The interim increase is under bond and subject to refund
if the final rate relief is a lesser amount. The interim increase order includes
a $34 million reduction in book depreciation expense and related income taxes
effective only during the period that we receive the interim relief. The MPSC
order allowed us to increase our rates beginning December 19, 2003. As part of
the interim rate order, Consumers agreed to restrict its dividend payments to
CMS Energy, to a maximum of $190 million annually during the period that
Consumers receives the interim relief. On March 5, 2004, the ALJ issued a
Proposal for Decision recommending that the MPSC not rely upon the projected
test year data included in our filing and supported by the MPSC Staff and
further recommended that the application be dismissed. The MPSC is not bound by
these recommendations and will consider the issues anew after receipt of
exceptions and replies to the exception filed by the parties in response to the
Proposal for Decision.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our
gas utility plant depreciation case originally filed in June 2001. This case is
independent of the 2003 gas rate case. The original filing was based on December
2000 plant balances and historical data. The December 2003 filing updates the
gas depreciation case to include December 2002 plant balances. The proposed
depreciation rates, if approved, will result in an annual increase of $12
million in depreciation expense.
OTHER CONSUMERS' OUTLOOK
CODE OF CONDUCT: In December 2000, the MPSC issued a new code of conduct
that applies to utilities and alternative electric suppliers. The code of
conduct seeks to prevent financial support, information sharing, and
preferential treatment between a utility's regulated and non-regulated services.
The new code of conduct is broadly written and could affect our:
- retail gas business energy related services,
115
- retail electric business energy related services,
- marketing of non-regulated services and equipment to Michigan
customers, and
- transfer pricing between our departments and affiliates.
We appealed the MPSC orders related to the code of conduct and sought a
deferral of the orders until the appeal was complete. We also sought waivers
available under the code of conduct to continue utility activities that provide
approximately $50 million in annual electric and gas revenues. In October 2002,
the MPSC denied waivers for three programs including the appliance service plan
offered by us, which generated $34 million in gas revenue in 2003. In March
2004, the Michigan Court of Appeals upheld the MPSC's implementation of the code
of conduct without modification. We are in the process of filing an application
for leave to appeal with the Michigan Supreme Court, but we cannot predict
whether the Michigan Supreme Court will accept the case or the outcome of any
appeal.
The Michigan House of Representatives is scheduled to review the proposed
legislation in 2004 that would allow us to remain in the appliance service
business. In the interim, the legislature passed a bill to extend to July 1,
2004, the deadline for exiting this business. The full impact of the new code of
conduct on our business will remain uncertain until the final judicial
resolution of our appeal or the Michigan legislature enacts clarifying
legislation.
OTHER CONSUMERS' MATTERS
2001 GAS RATE CASE: In June 2001, we filed an application with the MPSC
for a distribution service rate increase. In November 2002, the MPSC approved a
$56 million annual distribution service rate increase, with an 11.4 percent
authorized return on equity.
ENTERPRISES OUTLOOK
INDEPENDENT POWER PRODUCTION: We plan to complete the restructuring of our
IPP business by narrowing the focus of our existing operations and commitments
to North America and the Middle East/North Africa. Accordingly, we will continue
to sell designated assets and investments that are under-performing or are not
synergistic with our other business units. We will continue to operate and
manage our remaining portfolio of assets in a manner that maximizes their
contribution to our earnings and that maintains our reputation for solid
performance in the construction and operation of power plants.
CMS ERM: CMS ERM has continued to streamline its portfolio in order to
reduce its business risk and outstanding credit guarantees. Our future
activities will be centered around meeting contractual obligations, as well as
purchasing fuel for and marketing the merchant power from DIG, Michigan Power,
LLC, and other IPPs as their current power purchase agreements expire.
CMS GAS TRANSMISSION: CMS Gas Transmission continues to narrow its scope
of existing operations. We plan to continue to sell international assets and
businesses. Future operations will be mainly in Michigan.
UNCERTAINTIES: The results of operations and the financial position of our
diversified energy businesses may be affected by a number of trends or
uncertainties. Those that could have a material impact on our income, cash
flows, or balance sheet and credit improvement include:
- our ability to sell or to improve the performance of assets and
businesses in accordance with our financial plan,
- changes in exchange rates or local economic conditions, particularly
in Argentina, Venezuela, Brazil, and Australia,
- changes in foreign laws or in governmental or regulatory policies
that could reduce significantly the tariffs charged and revenues
recognized by certain foreign subsidiaries, or increase expenses,
116
- imposition of stamp taxes on South American contracts that could
increase substantially project expenses,
- impact of any future rate cases, or FERC actions, or orders on
regulated businesses, and
- impact of ratings downgrades on our liquidity, operating costs, and
cost of capital.
PENDING ASSET SALE: Affiliates of CMS Generation and CMS Gas Transmission
own a 49.6 percent interest in the Loy Yang Power Partnership ("LYPP"), which
owns the 2,000 MW Loy Yang coal-fired power project in Victoria, Australia. Due
to unfavorable power prices in the Australian market, the LYPP is not generating
cash flow sufficient to meet its debt-service obligations. LYPP has A$500
million of term bank debt that, pursuant to extensions from the lenders, is
scheduled to mature on March 31, 2004. The partners in LYPP (including
affiliates of CMS Generation, CMS Gas Transmission, NRG Energy Inc. and Horizon
Energy Australia Investments) have been exploring the possible sale of the
project (or control of the project) and a restructuring of the finances of LYPP.
In July 2003, a conditional share sale agreement was executed by the LYPP
partners and partners of the Great Energy Alliance Corporation ("GEAC") to sell
the project to GEAC for A$3.5 billion ($2.8 billion in U.S. dollars), including
A$165 million for the project equity. The partners in GEAC are the Australian
Gas Light Company, the Tokyo Electric Power Company, and a group of financial
investors led by the Commonwealth Bank of Australia. A recent resolution of an
Australian Competition and Consumer Commission objection to the sale has led to
an extension of the exclusive arrangement with GEAC to allow enough time to
complete the sale. The conditions to completion of the sale to GEAC include
consents from LYPP's lenders to a restructuring of the debt and rulings on tax
and stamp duty obligations. The project equity portion of the sale price has
been reduced to A$155 million ($122 million in U.S. dollars) as a result of
working capital and other adjustments, and closing is targeted for March 2004.
The share sale agreement and subsequent extensions provide GEAC a period of
exclusivity while the conditions of the purchase are satisfied. The ultimate net
proceeds to CMS Energy for its equity share in LYPP may be subject to a
reduction based on the ultimate resolution of many of the factors described
above as conditions to completion of the sale, as well as closing adjustments
and transaction costs, and could likely range between $20 million and a nominal
amount.
We cannot predict whether this sale to GEAC will be consummated or, if
not, whether any of the other initiatives will be successful, and it is possible
that CMS Generation may lose all or a substantial part of its remaining equity
investment in the LYPP. We previously have written off our equity investment in
the LYPP, and further write-offs would be limited to cumulative net foreign
currency translation losses. The amount of such cumulative net foreign currency
translation losses is approximately $110 million at December 31, 2003. Any such
write-off would flow through our income statement but would not result in a
reduction in shareholders' equity or cause us to be in noncompliance with our
financing agreements.
OTHER OUTLOOK
LITIGATION AND REGULATORY INVESTIGATIONS: We are the subject of various
investigations as a result of round-trip trading transactions by CMS MST,
including investigations by the United States Department of Justice and the SEC.
Additionally, we are a party to various litigation including a shareholder
derivative lawsuit, a securities class action lawsuit, a class action lawsuit
alleging ERISA violations, several lawsuits regarding alleged false natural gas
price reporting, and a lawsuit surrounding the possible sale of CMS Pipeline
Assets. For additional details regarding these investigations and litigation,
see Note 4, Uncertainties.
OTHER MATTERS
CONTROL WEAKNESSES AT CMS MST
In late 2001 and during 2002, we identified a number of deficiencies in
CMS MST's systems of internal accounting controls. The internal control
deficiencies related to, among other things, a lack of account reconciliations,
unidentified differences between subsidiary ledgers and the general ledger, and
procedures and processes surrounding our accounting for energy trading
contracts, including mark-to-market accounting.
117
Senior management, the Audit Committee of the Board of Directors, the
Board of Directors, and the independent auditors were notified of these
deficiencies as they were discovered, and we commenced a plan of remediation
that included replacing certain key personnel and deploying additional internal
and external accounting personnel to CMS MST. While a number of these control
improvements and changes were implemented in late 2002, the most important ones
occurred in the first quarter of 2003.
We believe that the improvements to our system of internal accounting
controls were appropriate and responsive to the internal control deficiencies
that were identified. We monitored the operation of the improved internal
controls throughout 2003 and have concluded that they were effective.
NEW ACCOUNTING STANDARDS
See Note 17, Implementation of New Accounting Standards, for discussion of
new standards.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES:
FASB issued this interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest to consolidate the entity.
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46.
For entities that have not previously adopted FASB Interpretation No. 46,
Revised FASB Interpretation No. 46 provides an implementation deferral until the
first quarter of 2004. Revised FASB Interpretation No. 46 is effective for the
first quarter of 2004 for all entities other than special purpose entities.
Special purpose entities must apply either FASB Interpretation No. 46 or Revised
FASB Interpretation No. 46 for the first reporting period that ends after
December 15, 2003.
As of December 31, 2003, we have completed our analysis for and have
adopted Revised FASB Interpretation No. 46 for all entities other than the MCV
Partnership and FMLP. We continue to evaluate and gather information regarding
those entities. We will adopt the provisions of Revised FASB Interpretation No.
46 for the MCV Partnership and FMLP in the first quarter of 2004.
If our completed analysis shows we have the controlling financial interest
in the MCV Partnership and FMLP, we would consolidate their assets, liabilities,
and activities, including $700 million of non-recourse debt, into our financial
statements. Financial covenants under our financing agreements could be impacted
negatively after such a consolidation. As a result, it may become necessary to
seek amendments to the relevant financing agreements to modify the terms of
certain of these covenants to remove the effect of this consolidation, or to
refinance the relevant debt. As of December 31, 2003, our investment in the MCV
Partnership was $419 million and our investment in the FMLP was $224 million.
We determined that we have the controlling financial interest in three
entities that are determined to be variable interest entities. We have 50
percent partnership interest in T.E.S Filer City Station Limited Partnership,
Grayling Generating Station Limited Partnership, and Genesee Power Station
Limited Partnership. Additionally, we have operating and management contracts
and are the primary purchaser of power from each partnership through long-term
power purchase agreements. Collectively, these interests provide us with the
controlling financial interest as defined by the Interpretation. Therefore, we
have consolidated these partnerships into our consolidated financial statements
for the first time as of December 31, 2003. At December 31, 2003, total assets
consolidated for these entities are $227 million and total liabilities are $164
million, including $128 million of non-recourse debt. At December 31, 2003, CMS
Energy has outstanding letters of credit and guarantees of $5 million relating
to these entities. At December 31, 2003, minority interest recorded for these
entities totaled $36 million.
We also determined that we do not hold the controlling financial interest
in our trust preferred security structures. Accordingly, those entities have
been deconsolidated as of December 31, 2003. Company obligated Trust Preferred
Securities totaling $663 million that were previously included in mezzanine
equity have been eliminated
118
due to deconsolidation. As a result of the deconsolidation, we have reflected
$684 million of long-term debt -- related parties and have reflected an
investment in related parties of $21 million.
We are not required to, and have not, restated prior periods for the
impact of this accounting change.
Additionally, we have non-controlling interests in four other variable
interest entities. FASB Interpretation No. 46 requires us to disclose certain
information about these entities. The chart below details our involvement in
these entities at December 31, 2003:
Investment Operating Total
Nature Of Involvement Balance Agreement With Generating
Name (Ownership Interest) The Entity Country Date (In Millions) CMS Energy Capacity
---------------------------------------------------------------------------------------------------------------------
Loy Yang Power (49%) Power
Generator Australia 1997 $ -- Yes 2,000 MW
Taweelah (40%) Power
Generator United Arab
Emirates 1999 $ 83 Yes 777 MW
Jubail (25%) Generator --
Under
Construction Saudi Arabia 2001 $ -- Yes 250 MW
Shuweihat (20%) Generator --
Under
Construction United Arab
Emirates 2001 $ (24)(a) Yes 1,500 MW
--------------------------------------------------------------------------------------------------------------------
Total $ 59 4,527 MW
====================================================================================================================
(a) At December 31, 2003, we recorded a negative investment in Shuweihat. The
balance is comprised of our investment of $3 million reduced by our
proportionate share of the negative fair value of derivative instruments
of $27 million. We are required to record the negative investment due to
our future commitment to make an equity investment in Shuweihat.
Our maximum exposure to loss through our interests in these variable
interest entities is limited to our investment balance of $59 million, Loy Yang
currency translation losses of $110 million, net of tax, and letters of credit,
guarantees, and indemnities relating to Taweelah and Shuweihat totaling $146
million. Included in the $146 million is a letter of credit relating to our
required initial investment in Shuweihat of $70 million. We plan to contribute
our initial investment when the project becomes commercially operational in
2004.
STATEMENT OF POSITION, ACCOUNTING FOR CERTAIN COSTS AND ACTIVITIES RELATED
TO PROPERTY, PLANT, AND EQUIPMENT: At its September 9, 2003 meeting, the
Accounting Standards Executive Committee, of the American Institute of Certified
Public Accountants voted to approve the Statement of Position, Accounting for
Certain Costs and Activities Related to Property, Plant, and Equipment. The
Statement of Position is expected to be presented for FASB clearance in 2004 and
would be applicable for fiscal years beginning after December 15, 2004. An asset
classified as property, plant, and equipment often comprises multiple parts and
costs. A component accounting policy determines the level at which those parts
are recorded. Capitalization of certain costs related to property, plant, and
equipment are included in the total cost. The Statement of Position could impact
our component and capitalization accounting for property, plant, and equipment.
We continue to evaluate the impact, if any, this Statement of Position will have
upon adoption.
119
OUR BUSINESS
GENERAL
CMS ENERGY
CMS Energy was formed in Michigan in 1987 and is an energy holding company
operating through subsidiaries in the United States and in selected markets
around the world. Its two principal subsidiaries are Consumers and Enterprises.
Consumers is a public utility that provides natural gas and/or electricity to
almost 6.5 million of Michigan's 10 million residents and serves customers in 61
of 68 counties in Michigan's Lower Peninsula. Through various subsidiaries,
Enterprises is engaged in energy businesses in the United States and in selected
international markets.
In 2003, CMS Energy's consolidated operating revenue was approximately
$5.5 billion.
CONSUMERS
Consumers was formed in Michigan in 1968 and is the successor to a
corporation organized in Maine in 1910 that conducted business in Michigan from
1915 to 1968. In 1997, Consumers changed its name from Consumers Power Company
to Consumers Energy Company to better reflect its integrated electricity and gas
businesses.
Consumers' service areas include automotive, metal, chemical and food
products as well as a diversified group of other industries. Consumers'
consolidated operations account for a majority of CMS Energy's total assets and
income, as well as a substantial portion of its operating revenue. At year-end
2003, Consumers' customer base and operating revenues were as follows:
Customers Operating 2003 Vs. 2002
Served Revenue Operating Revenue
(Millions) (Millions) % Increase/(Decrease)
-----------------------------------------------------------------------------
Electric Utility Business 1.77 $2,590 (2.2)
Gas Utility Business 1.67 1,845 21.5
--------------------------------------------------------------------
Total 2.87(a) $4,435 6.4
====================================================================
(a) Reflects total number of customers, taking into account the approximately
0.6 million combination electric and gas customers that are included in
each of the Electric Utility Business and Gas Utility Business numbers
above.
Consumers' rates and certain other aspects of its business are subject to
the jurisdiction of the MPSC and FERC, as described in CMS ENERGY AND CONSUMERS
REGULATION below.
CONSUMERS' PROPERTIES -- GENERAL: Consumers and its subsidiaries own their
principal properties in fee, except that most electric lines and gas mains are
located in public roads or on land owned by others pursuant to easements and
other rights. Almost all of Consumers' properties are subject to the lien of its
First Mortgage Bond Indenture. For additional information on Consumers'
properties see BUSINESS SEGMENTS -- Consumers' Electric Utility Operations --
Electric Utility Properties, and -- Consumers' Gas Utility Operations -- Gas
Utility Properties, below.
BUSINESS SEGMENTS
CMS ENERGY FINANCIAL INFORMATION
For information with respect to operating revenue, net operating income,
identifiable assets and liabilities attributable to all of CMS Energy's business
segments and international and domestic operations, see the December 31, 2003
Financial Statements and the Notes thereto.
CONSUMERS ELECTRIC UTILITY
ELECTRIC UTILITY OPERATIONS
Consumers' electric utility revenue was $2.590 billion in 2003, $2.648
billion in 2002, and $2.633 billion in 2001. Based on the average number of
customers, Consumers' electric utility operations, if independent, would be the
thirteenth largest electric utility company in the United States. Consumers'
electric utility operations include the
120
generation, purchase, distribution and sale of electricity. At year-end 2003, it
served customers in 61 of the 68 counties of Michigan's Lower Peninsula.
Principal cities served include Battle Creek, Flint, Grand Rapids, Jackson,
Kalamazoo, Midland, Muskegon and Saginaw. Consumers' electric utility customer
base includes a mix of residential, commercial and diversified industrial
customers, the largest segment of which is the automotive industry. Consumers'
electric utility operations are not dependent upon a single customer, or even a
few customers, and the loss of any one or even a few of such customers is not
reasonably likely to have a material adverse effect on its financial condition.
Consumers' electric utility operations are seasonal. The summer months
usually increase demand for electric energy, principally due to the use of air
conditioners and other cooling equipment, thereby affecting revenues. In 2003,
Consumers' electric sales were 36 billion kWh and retail open access deliveries
were 3 billion kWh, for total electric deliveries of 39 billion kWh. In 2002,
Consumers' electric sales were 37 billion kWh and retail open access deliveries
were 2 billion kWh, for total electric deliveries of 39 billion kWh.
Consumers' 2003 summer peak demand was 7,721 MW (excluding retail open
access loads) and 8,170 MW (including retail open access loads). For the 2002-03
winter period, Consumers' winter peak demand was 5,862 MW (excluding retail open
access loads) and 6,140 MW (including retail open access loads). In December
2003, Consumers experienced peak demand of 5,657 MW (excluding retail open
access loads) and 6,093 MW (including retail open access loads). Based on its
summer 2003 forecast, Consumers carried an 11 percent reserve margin target.
However, as a result of lower than forecasted peak loads, Consumers' ultimate
reserve margin was 14.7 percent compared to 20.6 percent in 2002. Currently,
Consumers has a reserve margin of 5.0 percent, or supply resources equal to 105
percent of projected summer peak load for summer 2004 and is in the process of
securing the additional capacity needed to meet its summer 2004 reserve margin
target of 11 percent (111 percent of projected summer peak load). The ultimate
use of the reserve margin will depend primarily on summer weather conditions,
the level of retail open access requirements being served by others during the
summer, and any unscheduled plant outages.
ELECTRIC UTILITY PROPERTIES
GENERATION: At December 31, 2003, Consumers' electric generating system
consists of the following:
2003 Net
2003 Summer Net Generation
Size And Year Demonstrated (Millions
Name And Location (Michigan) Entering Service Capability (MWs) Of kWhs)
------------------------------------------------------------------------------------------
COAL GENERATION 2 Units, 1962-1967 615 4,253
J H Campbell 1 & 2 -- West Olive
J H Campbell 3 -- West Olive 1 Unit, 1980 765(a) 5,657
D E Karn -- Essexville 2 Units, 1959-1961 511 3,429
B C Cobb -- Muskegon 2 Units, 1956-1957 312 2,166
J R Whiting -- Erie 3 Units, 1952-1953 326 2,256
J C Weadock -- Essexville 2 Units, 1955-1958 302 2,330
---------------------------
Total coal generation 2,831 20,091
---------------------------
OIL/GAS GENERATION 3 Units, 1999-2000(b) 183 6
B C Cobb -- Muskegon
D E Karn -- Essexville 2 Units, 1975-1977 1,276 352
---------------------------
Total oil/gas generation 1,459 358
---------------------------
HYDROELECTRIC 13 Plants, 1906-1949 74 335
Conventional Hydro Generation
Ludington Pumped Storage 6 Units, 1973 955(c) (517)(d)
---------------------------
Total Hydroelectric 1,029 (182)
---------------------------
NUCLEAR GENERATION
Palisades -- South Haven 1 Unit, 1971 767 6,151
---------------------------
GAS/OIL COMBUSTION TURBINE
Generation 7 Plants, 1966-1971 345 13
---------------------------
Total owned generation 6,431 26,431
===========================
PURCHASED AND INTERCHANGE POWER 1,991(e)
Capacity
---------------------------
Total 8,422
===========================
121
(a) Represents Consumers' share of the capacity of the J H Campbell 3 unit,
net of 6.69 percent (ownership interests of the Michigan Public Power
Agency and Wolverine Power Supply Cooperative, Inc.).
(b) Cobb 1-3 are retired coal fired units that were converted to gas fired.
Units were placed back into service in the years indicated.
(c) Represents Consumers' share of the capacity of Ludington. Consumers and
Detroit Edison have 51 percent and 49 percent undivided ownership,
respectively, in the plant.
(d) Represents Consumers' share of net pumped storage generation. This
facility electrically pumps water during off-peak hours for storage to
later generate electricity during peak-demand hours.
(e) Includes 1,240 MW of purchased contract capacity from the MCV Facility.
In 2003, through long-term purchase contracts, options, spot market and
other seasonal purchases, Consumers purchased up to 2,353 MW of net capacity
from other power producers (the largest of which was the MCV Partnership), which
amounted to 30.5 percent of Consumers' total system requirements.
DISTRIBUTION:
Consumers' distribution system includes:
- 347 miles of high-voltage distribution radial lines operating at 120
kilovolts and above;
- 4,164 miles of high-voltage distribution overhead lines operating at
23 kilovolts and 46 kilovolts;
- 16 subsurface miles of high-voltage distribution underground lines
operating at 23 kilovolts and 46 kilovolts;
- 54,922 miles of electric distribution overhead lines;
- 8,526 subsurface miles of underground distribution lines; and o
substations having an aggregate transformer capacity of 20,605,680
kilovoltamperes.
Consumers formerly owned a high-voltage transmission system that
interconnects Consumers' electric generating plants at many locations with
transmission facilities of unaffiliated systems, including those of other
utilities in Michigan and Indiana. The interconnections permit a sharing of the
reserve capacity of the connected systems. This allows mutual assistance during
emergencies and substantially reduces investment in utility plant facilities. On
May 1, 2002, Consumers transferred its investment in the high-voltage
transmission system to a third party, Michigan Electric Transmission Company,
LLC. Consequently, Consumers no longer owns or controls transmission facilities
either directly or indirectly. For additional information on the sale of the
transmission assets, see Note 4 of the Notes to the December 31, 2003 Financial
Statements. UNCERTAINTIES -- CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS
-- TRANSMISSION SALE
FUEL SUPPLY: Consumers has four generating plant sites that burn coal.
These plants constitute 76 percent of Consumers' baseload supply, the capacity
used to serve a constant level of customer demand. In 2003, these plants
produced a combined total of 20,091 million kWhs of electricity and burned 10.1
million tons of coal. On December 31, 2003, Consumers had on hand a 28-day
supply of coal.
Consumers owns Palisades, an operating nuclear power plant located near
South Haven, Michigan. In May 2001, with the approval of the NRC, Consumers
transferred its authority to operate Palisades to the NMC. During 2003,
Palisades' net generation was 6,151 million kWhs, constituting 23.3 percent of
Consumers' baseload supply. Palisades' nuclear fuel supply responsibilities are
under NMC's control as agent for Consumers. New fuel contracts are being written
as NMC agreements. Consumers/NMC currently have sufficient contracts for uranium
concentrates to provide up to 42 percent of its fuel supply requirements for the
fall 2004 reload. A mix of spot and medium-term uranium concentrates contracts
are currently being negotiated to provide for the remaining open requirements
for the 2004 and 2006 reloads. Consumers/NMC also have contracts for conversion
services with quantity flexibility to provide up to 100 percent of the
requirements for the 2004 reload and approximately 10 percent of the
requirements for the 2006 reload. Contracts to provide for the future Consumers/
NMC requirements
122
are currently being pursued with all suppliers of conversion services.
Enrichment services contracts with quantity flexibility ranging up to 100
percent of the requirements for the 2004 and 2006 reloads are in place. NMC is
currently negotiating a contract for supply of enrichment services beyond 2006.
NMC also has contracts for nuclear fuel services and for fabrication of
nuclear fuel assemblies. The fuel contracts are with major private industrial
suppliers of nuclear fuel and related services and with uranium producers,
converters and enrichers who participate in the world nuclear fuel marketplace.
The fabrication contract is effective for the 2004 reload with options to extend
the contract for an additional two reloads in 2006 and 2007.
As shown below, Consumers generates electricity principally from coal and
nuclear fuel.
Millions Of kWhs
------------------------------------------------------------------------------
Power Generated 2003 2002 2001 2000 1999
------------------------------------------------------------------------------
Coal 20,091 19,361 19,203 17,926 19,085
Nuclear 6,151 6,358 2,326(a) 5,724 5,105
Oil 242 347 331 645 809
Gas 129 354 670 400 441
Hydro 335 387 423 351 365
Net pumped storage (517) (486) (553) (541) (476)
-----------------------------------------------------------------------------
Total net generation 26,431 26,321 22,400 24,505 25,329
=============================================================================
(a) On June 20, 2001, the Palisades reactor was shut down so technicians could
inspect a small steam leak on a control rod drive assembly. The defective
components were replaced and the plant returned to service on January 21, 2002.
The cost of all fuels consumed, shown below, fluctuates with the mix of fuel
burned.
Cost Per Million Btu
--------------------------------------------------------------------------------
Fuel Consumed 2003 2002 2001 2000 1999
--------------------------------------------------------------------------------
Coal $ 1.33 $ 1.34 $ 1.38 $ 1.34 $ 1.38
Oil 3.92 3.49 4.02 3.30 2.69
Gas 7.62 3.98 4.05 4.80 2.74
Nuclear 0.34 0.35 0.39 0.45 0.52
All Fuels(a) 1.16 1.19 1.44 1.27 1.28
================================================================================
(a) Weighted average fuel costs.
The Nuclear Waste Policy Act of 1982 made the federal government
responsible for the permanent disposal of spent nuclear fuel and high-level
radioactive waste by 1998. The DOE has not arranged for storage facilities and
it does not expect to receive spent nuclear fuel for storage in 2004. Palisades
currently has spent nuclear fuel that exceeds its temporary on-site storage pool
capacity. Therefore, Consumers is storing spent nuclear fuel in NRC-approved
steel and concrete vaults known as "dry casks." For additional information on
disposal of nuclear fuel and Consumers' use of dry casks, see Note 4 of the
Notes to the December 31, 2003 Financial Statements -- UNCERTAINTIES -- OTHER
CONSUMERS' ELECTRIC UTILITY UNCERTAINTIES -- NUCLEAR MATTERS.
CONSUMERS GAS UTILITY
GAS UTILITY OPERATIONS
Consumers' gas utility operating revenue was $1.845 billion in 2003,
$1.519 billion in 2002 and $1.338 billion in 2001. Based on the average number
of customers, Consumers' gas utility operations, if independent, would be the
10th largest gas utility company in the United States. Consumers' gas utility
operations purchase, transport, store, distribute and sell natural gas. As of
December 31, 2003, it was authorized to provide service in 44 of the 68 counties
in Michigan's Lower Peninsula. Principal cities served include Bay City, Flint,
Jackson, Kalamazoo, Lansing, Pontiac and Saginaw, as well as the suburban
Detroit area, where nearly 900,000 of the gas customers are located. Consumers'
gas
123
utility operations are not dependent upon a single customer, or even a few
customers, and the loss of any one or even a few of such customers is not
reasonably likely to have a material adverse effect on its financial condition.
Consumers' gas utility operations are seasonal. Consumers injects natural
gas into storage during the summer months for use during the winter months when
the demand for natural gas is higher. Peak demand usually occurs in the winter
due to colder temperatures and the resulting increased demand for heating fuels.
In 2003, total deliveries of natural gas sold by Consumers and by other sellers
who deliver natural gas to customers (including the MCV Partnership) through
Consumers' pipeline and distribution network totaled 388 bcf.
During the winter months of 2002-03, cold weather caused heavy withdrawals
from Consumers' gas storage fields. As a result, water and other liquids entered
certain of Consumers' pipelines. The existence of water and other liquids in the
pipelines could cause pipe corrosion, which in turn may increase future
maintenance problems and costs.
GAS UTILITY PROPERTIES: Consumers' gas distribution and transmission
system consists of:
- 25,055 miles of distribution mains throughout Michigan's Lower
Peninsula;
- 2,408 miles of transmission lines throughout Michigan's Lower
Peninsula;
- 7 compressor stations with a total of 162,000 installed horsepower;
and
- 14 gas storage fields located across Michigan with an aggregate
storage capacity of 331 bcf and a working storage capacity of 130
bcf.
GAS SUPPLY: In 2003, Consumers purchased 3 percent of its gas from
Michigan producers, 66 percent from United States producers outside Michigan and
22 percent from Canadian producers. Authorized suppliers in the gas customer
choice program supplied the remaining 9 percent of gas that Consumers delivered.
Consumers' firm transportation agreements are with ANR Pipeline Company,
Great Lakes Gas Transmission, L.P., Trunkline Gas Co. and Panhandle Eastern Pipe
Line Company. Consumers uses these agreements to deliver gas to Michigan for
ultimate deliveries to market. Consumers' firm transportation and city gate
arrangements are capable of delivering over 95 percent of Consumers' total gas
supply requirements. As of December 31, 2003, Consumers' portfolio of firm
transportation from pipelines to Michigan is as follows:
Volume
(Dekatherms/Day) Expiration
----------------------------------------------------------------------------------------------
ANR Pipeline Company ..................................... 84,054 March 2004
ANR Pipeline Company (starting 04/01/04) ................. 50,000 March 2006
ANR Pipeline Company (starting 04/01/04) ................. 40,000 October 2004
Great Lakes Gas Transmission, L.P. ....................... 85,092 April 2004
Great Lakes Gas Transmission, L.P. (starting 04/01/04) ... 50,000 March 2007
Great Lakes Gas Transmission, L.P. ....................... 90,000 March 2004
Great Lakes Gas Transmission, L.P. (starting 04/01/04) ... 100,000 March 2007
Trunkline Gas Co. ........................................ 336,375 October 2005
Trunkline Gas Co. ........................................ 40,106 March 2004
Panhandle Eastern Pipe Line Company (starting 04/01/04) .. 50,000 October 2004
Vector Pipeline .......................................... 50,000 March 2007
==============================================================================================
Consumers purchases the balance of its required gas supply under firm city
gate contracts and as needed, interruptible contracts. The amount of
interruptible transportation service and its use varies primarily with the price
for such service and the availability and price of the spot supplies being
purchased and transported. Consumers' use of interruptible transportation is
generally in off-peak summer months and after Consumers has fully utilized the
services under the firm transportation agreements.
ENTERPRISES
Enterprises, through subsidiaries, is engaged in domestic and
international diversified energy businesses including natural gas transmission,
storage and processing, independent power production, and energy services.
Enterprises' operating revenue was $1.085 billion in 2003, $4.508 billion in
2002 and $4.034 billion in 2001.
124
NATURAL GAS TRANSMISSION
CMS Gas Transmission was formed in 1988 and owns, develops and manages
domestic and international natural gas facilities. In 2003, CMS Gas
Transmission's operating revenue was $22 million.
In 1999, CMS Gas Transmission acquired Panhandle, which was primarily
engaged in the interstate transmission and storage of natural gas and also
provided LNG terminalling and regasification services. Panhandle operated a
large natural gas pipeline network, which provided customers in the Midwest and
Southwest with a comprehensive array of transportation services. Panhandle's
major customers included 25 utilities located primarily in the United States
Midwest market area, which encompassed large portions of Illinois, Indiana,
Michigan, Missouri, Ohio and Tennessee.
In February 2003, Panhandle sold its one-third equity interest in
Centennial for $40 million to Centennial's two other partners, MAPL and TE
Products Pipeline Company, Limited Partnership, through its general partner,
TEPPCO.
In March 2003, Panhandle transferred $63 million previously committed to
collateralize a letter of credit and its one-third ownership interest in
Guardian to CMS Gas Transmission. CMS Gas Transmission sold its interest in
Guardian to a subsidiary of WPS Resources Corporation in May 2003. Proceeds from
the sale were $26 million and the $63 million of cash collateral was released.
In June 2003, CMS Gas Transmission sold Panhandle to Southern Union
Panhandle Corp., a newly formed entity owned by Southern Union. Southern Union
Panhandle Corp. purchased all of Panhandle's outstanding capital stock for
approximately $582 million in cash and 3 million shares of Southern Union common
stock. Southern Union Panhandle Corp. also assumed approximately $1.166 billion
in debt. In July 2003, Southern Union declared a five percent common stock
dividend resulting in an additional 150,000 shares of common stock for CMS Gas
Transmission. In October 2003, CMS Gas Transmission sold its 3.15 million shares
to a private investor for $17.77 per share.
In July 2003, CMS Gas Transmission completed the sale of CMS Field
Services to Cantera Natural Gas, Inc. for gross cash proceeds of approximately
$113 million, subject to post closing adjustments, and a $50 million face value
note of Cantera Natural Gas, Inc. The note is payable to CMS Energy for up to
$50 million subject to the financial performance of the Fort Union and Bighorn
natural gas gathering systems from 2004 through 2008.
In August 2004, we sold our interests in Parmelia and Goldfields to APT
for approximately $206 million Australian (approximately $147 million in U.S.
dollars).
NATURAL GAS TRANSMISSION PROPERTIES: CMS Gas Transmission has a total of
288 miles of gathering and transmission pipelines located in the state of
Michigan, with a daily capacity of 0.95 bcf. At December 31, 2003, CMS Gas
Transmission had nominal processing capabilities of approximately 0.33 bcf per
day of natural gas in Michigan.
At December 31, 2003, CMS Gas Transmission has ownership interests in the
following international pipelines:
Location Ownership Interest (%) Miles Of Pipelines
--------------------------------------------------------------------------------
Argentina 29.42 3,362
Argentina to Brazil 20.00 262
Argentina to Chile 50.00 707
Australia (Western Australia) 40.00(a) 927
Australia (Western Australia) 100.00 259
=========================================================================
(a) CMS Gas Transmission has a 45 percent interest in a consortium that acquired
an 88 percent interest in the pipeline.
Properties of certain CMS Gas Transmission subsidiaries are subject to
liens of creditors of the respective subsidiaries.
125
INDEPENDENT POWER PRODUCTION
CMS Generation was formed in 1986. It invests in, acquires, develops,
constructs and operates non-utility power generation plants in the United States
and abroad. In 2003, the independent power production business segment's
operating revenue, which includes revenues from CMS Generation, CMS Operating,
S.A., the MCV Facility and the MCV Partnership, was $204 million.
INDEPENDENT POWER PRODUCTION PROPERTIES: As of December 31, 2003, CMS
Generation had ownership interests in operating power plants totaling 8,766
gross MW (4,149 net MW). At December 31, 2003, additional plants totaling
approximately 1,784 gross MW (420 net MW) were under construction or in advanced
stages of development. These plants include the Shuweihat power plant, which is
under construction in the United Arab Emirates, and the Saudi Petrochemical
Company power plant, which is under advanced development and will be located in
the Kingdom of Saudi Arabia. In 2004, CMS Generation plans to complete the
restructuring of its operations by narrowing the scope of its existing
operations and commitments from four to two regions: the U.S. and the Middle
East/North Africa. In addition, it plans to sell designated assets and
investments that are under-performing, non-region focused and non-synergistic
with other CMS Energy business units.
The following table details CMS Generation's interest in independent power
plants as of year-end 2003 (excluding the plants owned by CMS Operating, S.R.L.
and CMS Electric and Gas and the MCV facility, discussed further below):
Percentage Of
Gross Capacity
Under Long-Term
Ownership Interest Gross Capacity Contract
Location Fuel Type (%) (MW) (%)
--------------------------------------------------------------------------------------------------------
California Wood 37.8 36 100
Connecticut Scrap tire 100 31 100
Michigan Coal 50 70 100
Michigan Natural gas 100 710 85
Michigan Natural gas 100 224 0
Michigan Wood 50 40 100
Michigan Wood 50 38 100
New York Hydro 0.3 14 100
North Carolina Wood 50 50 100
Oklahoma Natural gas 8.8 124 100
-----
Domestic Total 1,337
Argentina Hydro 17.2 1,320 20(a)
Australia Coal 49.6 2,000 55
Chile Natural gas 50 720 100(b)
Ghana Crude oil 90 224 100
India Coal 50 250 100
India Natural gas 33.2 235 100
Jamaica Diesel 42.3 63 100
Latin America Various Various 484 51
Morocco Coal 50 1,356 100
United Arab Emirates Natural gas 40 777 100
-----
International Total 7,429
Total Domestic And International 8,766
=====
Projects Under Construction/
Advanced Development 1,784
=====
(a) El Chocon is primarily on a spot market basis, however, it has a high
dispatch rate due to low cost.
126
(b) Atacama is not allowed to sell more than 440 MW to the grid. 100 percent
of the 440 MW is under contract.
Through a CMS International Ventures subsidiary called CMS Operating,
S.R.L., CMS Enterprises, CMS Gas Transmission and CMS Generation have a 100
percent ownership interest in a 128 MW natural gas power plant and a 92.6
percent ownership interest in a 540 MW natural gas power plant, each in
Argentina.
Through CMS Electric and Gas, CMS Enterprises has an 86 percent ownership
interest in 287 MW of gas turbine and diesel generating capacity in Venezuela.
CMS Midland owns a 49 percent general partnership interest in the MCV
Partnership, which was formed to construct and operate the MCV Facility. The MCV
Facility was sold to five owner trusts and leased back to the MCV Partnership.
CMS Holdings is a limited partner in the FMLP, which is a beneficiary of one of
these trusts. Through FMLP, CMS Holdings has a 35 percent Lessor interest in the
MCV Facility. The MCV Facility has a net electrical generating capacity of
approximately 1,500 MW.
In April 2004, CMS and its partners sold the 2,000-megawatt Loy Yang power
plant and adjacent coal mine located in Victoria, Australia for approximately
$3.5 billion Australian (approximately $2.6 billion in U.S. dollars), including
$145 million Australian for the project equity. We owned 49.6 percent of Loy
Yang. NRG Energy Inc. and Horizon Energy Australia Investments each owned about
25 percent of Loy Yang. CMS Energy's share of the proceeds was approximately $71
million Australian (approximately $44 million in U.S. dollars), subject to
closing adjustments and transaction costs.
CMS Generation has ownership interests in certain facilities such as Jorf
Lasfar and El Chocon.. The Jorf Lasfar facility is held pursuant to a right of
possession agreement with the Moroccan state-owned Office National de
l'Electricite. The El Chocon facility is held pursuant to a 30-year possession
agreement.
For information on capital expenditures, see The 10-Q MD&A -- CAPITAL
RESOURCES AND LIQUIDITY The 10-K MD&A -- CAPITAL RESOURCES AND LIQUIDITY, Note 5
of the Notes to the December 31, 2003 Financial Statements -- FINANCINGS AND
CAPITALIZATION and Note 4 of the Notes to the June 30, 2004 Financial Statements
-- FINANCINGS AND CAPITALIZATION.
OIL AND GAS EXPLORATION AND PRODUCTION
CMS Energy used to own an oil and gas exploration and production company.
In October 2002, CMS Energy completed its exit from the oil and gas exploration
and production business.
ENERGY RESOURCE MANAGEMENT
In 2003, CMS ERM moved its headquarters from Houston, Texas to Jackson,
Michigan. In February 2004, CMS ERM changed its name from CMS Marketing,
Services and Trading Company to CMS Energy Resource Management Company. CMS ERM
has reduced its business focus and in the future will concentrate on the
purchase and sale of energy commodities in support of CMS Energy's generating
facilities. CMS ERM previously provided gas, oil, and electric marketing, risk
management and energy management services to industrial, commercial, utility and
municipal energy users throughout the United States. In January 2003, CMS ERM
closed the sale of a major portion of its wholesale natural gas trading book to
Sempra Energy Trading. The cash proceeds were approximately $17 million. In
April 2003, CMS ERM sold its wholesale electric power business to Constellation
Power Source, Inc. Also in April 2003, CMS ERM sold the federal business of CMS
Viron, its energy management service provider, to Pepco Energy Services, Inc. In
July 2003, CMS ERM sold CMS Viron's non-federal business to Chevron Energy
Solutions Company, a division of Chevron U.S.A. In 2003, CMS ERM marketed
approximately 85 bcf of natural gas and 5,314 GWh of electricity. Its operating
revenue was $711 million in 2003, $4.137 billion in 2002, and $3.616 billion in
2001.
INTERNATIONAL ENERGY DISTRIBUTION
In October 2001, CMS Energy discontinued the operations of its
international energy distribution business. In 2002, CMS Energy discontinued all
new development outside North America, which included closing all non-U.S.
127
development offices. In 2003, CMS Energy reclassified to continuing operations
SENECA, which is its energy distribution business in Venezuela, and CPEE, which
is its energy distribution business in Brazil, due to its inability to sell
these assets.
CMS ENERGY REGULATION
CMS Energy is a public utility holding company that is exempt from
registration under PUHCA. CMS Energy and its subsidiaries are subject to
regulation by various federal, state, local and foreign governmental agencies,
including those described below.
MICHIGAN PUBLIC SERVICE COMMISSION
Consumers is subject to the MPSC's jurisdiction, which regulates public
utilities in Michigan with respect to retail utility rates, accounting, utility
services, certain facilities and various other matters. The MPSC also has rate
jurisdiction over several limited liability companies in which CMS Gas
Transmission has ownership interests. These companies own, or will own, and
operate intrastate gas transmission pipelines.
The Attorney General, ABATE, and the MPSC staff typically intervene in
MPSC electric- and gas-related proceedings concerning Consumers. For many years,
almost every significant MPSC order affecting Consumers has been appealed.
Certain appeals from the MPSC orders are pending in the Court of Appeals.
RATE PROCEEDINGS: In 1996, the MPSC issued an order that established the
electric authorized rate of return on common equity at 12.25 percent. In 2002,
the MPSC issued an order that established the gas authorized rate of return on
common equity at 11.4 percent.
MPSC REGULATORY AND MICHIGAN LEGISLATIVE CHANGES: State regulation of the
retail electric and gas utility businesses has undergone significant changes. In
2000, the Michigan Legislature enacted the Customer Choice Act. The Customer
Choice Act provides that as of January 2002, all electric customers have the
choice to buy generation service from an alternative electric supplier. The
Customer Choice Act also imposes rate reductions, rate freezes and rate caps.
For additional information regarding the Customer Choice Act, see Note 4 of the
Notes to the December 31, 2003 Financial Statements -- UNCERTAINTIES --
CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS.
As a result of regulatory changes in the natural gas industry, Consumers
transports the natural gas commodity that is sold to some customers by
competitors like gas producers, marketers and others. Pursuant to a gas customer
choice program that Consumers implemented, as of April 2003 all of Consumers'
gas customers are eligible to select an alternative gas commodity supplier.
Consumers' current GCR mechanism allows it to recover from its customers all
prudently incurred costs to purchase natural gas commodity and transport it to
Consumers' facilities. For additional information, see Note 4 of the Notes to
the December 31, 2003 Financial Statements UNCERTAINTIES -- CONSUMERS' GAS
UTILITY RATE MATTERS.
FEDERAL ENERGY REGULATORY COMMISSION
FERC has exercised limited jurisdiction over several independent power
plants in which CMS Generation has ownership interests, as well as over CMS ERM.
Among other things, FERC jurisdiction relates to the acquisition, operation and
disposal of assets and facilities and to the service provided and rates charged.
Some of Consumers' gas business is also subject to regulation by FERC, including
a blanket transportation tariff pursuant to which Consumers can transport gas in
interstate commerce.
FERC also regulates certain aspects of Consumers' electric operations
including compliance with FERC accounting rules, wholesale rates, operation of
licensed hydro-electric generating plants, transfers of certain facilities, and
corporate mergers and issuance of securities. FERC is currently soliciting
comments on whether it should exercise jurisdiction over power marketers like
CMS ERM, requiring them to follow FERC's uniform system of accounts and seek
authorization for issuance of securities and assumption of liabilities. These
issues are pending before the agency.
128
NUCLEAR REGULATORY COMMISSION
Under the Atomic Energy Act of 1954, as amended, and the Energy
Reorganization Act of 1974, Consumers is subject to the jurisdiction of the NRC
with respect to the design, construction, operation and decommissioning of its
nuclear power plants. Consumers is also subject to NRC jurisdiction with respect
to certain other uses of nuclear material. These and other matters concerning
Consumers' nuclear plants are more fully discussed in Note 1 of the Notes to the
December 31, 2003 Financial Statements -- CORPORATE STRUCTURE AND ACCOUNTING
POLICIES and Note 4 of the December 31, 2003 Financial Statements --
UNCERTAINTIES.
OTHER REGULATION
The Secretary of Energy regulates the importation and exportation of
natural gas and has delegated various aspects of this jurisdiction to FERC and
the DOE's Office of Fossil Fuels.
Pipelines owned by system companies are subject to the Natural Gas
Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002,
which regulates the safety of gas pipelines. Consumers is also subject to the
Hazardous Liquid Pipeline Safety Act of 1979, which regulates oil and petroleum
pipelines.
CMS ENERGY ENVIRONMENTAL COMPLIANCE
CMS Energy and its subsidiaries are subject to various federal, state and
local regulations for environmental quality, including air and water quality,
waste management, zoning and other matters.
Consumers has installed and is currently installing modern emission
controls at its electric generating plants and has converted and is converting
electric generating units to burn cleaner fuels. Consumers expects that the cost
of future environmental compliance, especially compliance with clean air laws,
will be significant because of EPA regulations regarding nitrogen oxide and
particulate-related emissions. These regulations will require Consumers to make
significant capital expenditures.
Consumers is in the process of closing older ash disposal areas at two
plants. Construction, operation, and closure of a modern solid waste disposal
area for ash can be expensive, because of strict federal and state requirements.
In order to significantly reduce ash field closure costs, Consumers has worked
with others to use bottom ash and fly ash as part of temporary and final cover
for ash disposal areas instead of native materials, in cases where such use of
bottom ash and fly ash is compatible with environmental standards. To reduce
disposal volumes, Consumers sells coal ash for use as a filler for asphalt, for
incorporation into concrete products and for other environmentally compatible
uses. The EPA has announced its intention to develop new nationwide standards
for ash disposal areas. Consumers intends to work through industry groups to
help ensure that any such regulations require only the minimum cost necessary to
adhere to standards that are consistent with protection of the environment.
Like most electric utilities, Consumers has PCB in some of its electrical
equipment. During routine maintenance activities, Consumers identified PCB as a
component in certain paint, grout and sealant materials at the Ludington Pumped
Storage facility. Consumers removed and replaced part of the PCB material.
Consumers has proposed a plan to the EPA to deal with the remaining materials
and is waiting for a response from the EPA.
Certain environmental regulations affecting CMS Energy and Consumers
include, but are not limited to, the Clean Air Act Amendments of 1990 and
Superfund. Superfund can require any individual or entity that may have owned or
operated a disposal site, as well as transporters or generators of hazardous
substances that were sent to such site, to share in remediation costs for the
site.
CMS Energy's and Consumers' current insurance coverage does not extend to
certain environmental clean-up costs, such as claims for air pollution, some
past PCB contamination and for some long-term storage or disposal of pollutants.
129
For additional information concerning environmental matters, including
estimated capital expenditures to reduce nitrogen oxide related emissions, see
Note 4 of the Notes of the December 31, 2003 Financial Statements --
UNCERTAINTIES.
CMS ENERGY COMPETITION
ELECTRIC COMPETITION
Consumers' electric utility business experiences actual and potential
competition from many sources, both in the wholesale and retail markets, as well
as in electric generation, electric delivery and retail services.
In the wholesale electricity markets, Consumers competes with other
wholesale suppliers, marketers and brokers. Electric competition in the
wholesale markets increased significantly since 1996 due to FERC Order 888.
While Consumers is still active in wholesale electricity markets, wholesale for
resale transactions by Consumers generated an immaterial amount of Consumers'
2003 revenues from electric utility operations. Consumers believes future loss
of wholesale for resale transactions will be insignificant.
A significant increase in retail electric competition has occurred because
of the Customer Choice Act and the availability of retail open access. Price is
the principal method of competition for generation services. The Customer Choice
Act gives all electric customers the right to buy generation service from an
alternative electric supplier. As of March 2004, alternative electric suppliers
are providing 735 MW of generation supply to retail open access customers. This
represents nine percent of Consumers' total generating load and an increase of
approximately 42 percent in generation supply being purchased from alternative
electric suppliers by retail open access customers. Consumers has applied for,
but has not yet been granted, reimbursement for implementation costs incurred
for the Electric Customer Choice program. The MPSC is supposed to adopt a
mechanism pursuant to the Customer Choice Act to provide for recovery of
stranded costs. In 2000 and 2001, the MPSC determined the stranded cost recovery
was zero, contrary to Consumers' position. Consumers continues to work toward
the adoption of a stranded cost recovery mechanism that will offset margin loss.
Consumers cannot predict the total amount of electric supply load that may be
lost to competitor suppliers, whether the stranded cost recovery method adopted
by the MPSC will be applied in a manner that will fully offset any associated
margin loss, or whether implementation costs will be fully recovered.
In addition to retail electric customer choice, Consumers also has
competition or potential competition from:
- the threat of customers relocating outside Consumers' service
territory;
- the possibility of municipalities owning or operating competing
electric delivery systems;
- customer self-generation; and
- adjacent municipal utilities that extend lines to customers near
service territory boundaries.
Consumers addresses this competition by offering special contracts,
providing additional non-energy services, and monitoring and enforcing
compliance with MPSC and FERC rules.
Consumers offers non-energy revenue services to electric customers,
municipalities and other utilities in an effort to offset costs. These services
include engineering and consulting, construction of customer-owned distribution
facilities, equipment sales (such as transformers), power quality analysis,
fiber optic line construction, meter reading and joint construction for phone
and cable. Consumers faces competition from many sources, including energy
management services companies, other utilities, contractors, and retail
merchandisers.
CMS ERM, which is a non-utility electric subsidiary, has modified its
focus toward optimization of CMS Energy's independent power production
portfolio. CMS Energy's independent power production business segment, another
non-utility electric subsidiary, faces competition from generators, marketers
and brokers, as well as lower power prices on the wholesale market.
130
For additional information concerning electric competition, see the 10-Q
MD&A and 10-K MD&A -- OUTLOOK -- ELECTRIC UTILITY BUSINESS UNCERTAINTIES.
GAS COMPETITION
Competition has existed for the past decade in various aspects of
Consumers' gas utility business, and is likely to increase. Competition
traditionally comes from alternate fuels and energy sources, such as propane,
oil and electricity.
INSURANCE
CMS Energy and its subsidiaries, including Consumers, maintain insurance
coverage similar to comparable companies in the same lines of business. The
insurance policies are subject to terms, conditions, limitations and exclusions
that might not fully compensate CMS Energy for all losses. As CMS Energy renews
its policies it is possible that full insurance coverage may not be obtainable
on commercially reasonable terms due to restrictive insurance markets.
EMPLOYEES
As of December 31, 2003, CMS Energy and its subsidiaries, including
Consumers, had 8,411 full-time equivalent employees, of whom 8,353 are full-time
employees and 58 are full-time equivalent employees associated with the
part-time work force. Included in the total are 3,800 employees who are covered
by union contracts.
LEGAL PROCEEDINGS
CMS Energy and some of its subsidiaries and affiliates are parties to
certain routine lawsuits and administrative proceedings incidental to their
businesses involving, for example, claims for personal injury and property
damage, contractual matters, various taxes, and rates and licensing. For
additional information regarding various pending administrative and judicial
proceedings involving regulatory, operating and environmental matters, see OUR
BUSINESS -- CMS ENERGY AND CONSUMERS REGULATION, as well as the 10-K MD&A and
Notes to the December 31, 2003 Financial Statements and the 10-Q MD&A and Notes
to the June 30, 2004 Financial Statements.
DEMAND FOR ACTIONS AGAINST OFFICERS AND DIRECTORS
In May 2002, the Board of Directors of CMS Energy received a demand, on
behalf of a shareholder of CMS Energy Common Stock, that it commence civil
actions (i) to remedy alleged breaches of fiduciary duties by certain CMS Energy
officers and directors in connection with round-trip trading by CMS MST, and
(ii) to recover damages sustained by CMS Energy as a result of alleged insider
trades alleged to have been made by certain current and former officers of CMS
Energy and its subsidiaries. In December 2002, two new directors were appointed
to the Board. The Board formed a special litigation committee in January 2003 to
determine whether it is in CMS Energy's best interest to bring the action
demanded by the shareholder. The disinterested members of the Board appointed
the two new directors to serve on the special litigation committee.
In December 2003, during the continuing review by the special litigation
committee, CMS Energy was served with a derivative complaint filed on behalf of
the shareholder in the Circuit Court of Jackson County, Michigan in furtherance
of his demands. The date for CMS Energy and other defendants to answer or
otherwise respond to the complaint has been extended to December 1, 2004,
subject to such further extensions as may be mutually agreed upon by the parties
and authorized by the Court. CMS Energy cannot predict the outcome of this
matter.
INTEGRUM LAWSUIT
Integrum filed a complaint in Wayne County, Michigan Circuit Court in July
2003 against CMS Energy, Enterprises and APT. Integrum alleges several causes of
action against APT, CMS Energy, and Enterprises in connection with an offer by
Integrum to purchase the CMS Pipeline Assets. In addition to seeking unspecified
money damages, Integrum is seeking an order enjoining CMS Energy and Enterprises
from selling, and APT from purchasing, the CMS Pipeline Assets and an order of
specific performance mandating that CMS Energy, Enterprises, and APT complete
the sale of the CMS Pipeline Assets to APT and Integrum. A certain officer and
131
director of Integrum is a former officer and director of CMS Energy, Consumers,
and their subsidiaries. The individual was not employed by CMS Energy,
Consumers, or their subsidiaries when Integrum made the offer to purchase the
CMS Pipeline Assets. CMS Energy and Enterprises filed a motion to change venue
from Wayne County to Jackson County, which was granted. The parties are now
awaiting transfer of the file from Wayne County to Jackson County. CMS Energy
and Enterprises believe that Integrum's claims are without merit. CMS Energy and
Enterprises intend to defend vigorously against this action but they cannot
predict the outcome of this litigation.
GAS INDEX PRICE REPORTING LITIGATION
In August 2003, Cornerstone Propane Partners, L.P. (Cornerstone) filed a
putative class action complaint in the United States District Court for the
Southern District of New York against CMS Energy and dozens of other energy
companies. The court ordered the Cornerstone complaint to be consolidated with
similar complaints filed by Dominick Viola and Roberto Calle Gracey. The
plaintiffs filed a consolidated complaint on January 20, 2004. The consolidated
complaint alleges that false natural gas price reporting by the defendants
manipulated the prices of NYMEX natural gas futures and options. The complaint
contains two counts under the Commodity Exchange Act, one for manipulation and
one for aiding and abetting violations. CMS Energy is no longer a defendant,
however, CMS MST and CMS Field Services are named as defendants. (CMS Energy
sold CMS Field Services to Cantera Natural Gas, Inc. but is required to
indemnify Cantera Natural Gas, Inc. with respect to this action).
In a similar but unrelated matter, Texas-Ohio Energy, Inc. filed a
putative class action lawsuit in the United States District Court for the
Eastern District of California against a number of energy companies engaged in
the sale of natural gas in the United States. CMS Energy is named as a
defendant. The complaint alleges defendants entered into a price-fixing
conspiracy by engaging in activities to manipulate the price of natural gas in
California. The complaint contains counts alleging violations of the Sherman
Act, Cartwright Act (a California statute), and the California Business and
Profession Code relating to unlawful, unfair and deceptive business practices.
There is currently pending in the Nevada federal district court a multi-district
court litigation (MDL) matter involving seven complaints originally filed in
various state courts in California. These complaints make allegations similar to
those in the Texas-Ohio case regarding price reporting, although none contain a
Sherman Act claim and some of the defendants in the MDL matter are also
defendants in the Texas-Ohio case. Those defendants successfully argued to have
the Texas-Ohio case transferred to the MDL proceeding. The plaintiff in the
Texas-Ohio case agreed to extend the time for all defendants to answer or
otherwise respond until May 28, 2004 and on that date a number of defendants
filed motions to dismiss. In order to negotiate possible dismissal and/or
substitution of defendants, CMS Energy and two other parent holding company
defendants were given further extensions to answer or otherwise respond to the
complaint until August 16, 2004.
Benscheidt v. AEP Energy Services, Inc., et al., a new class action
complaint containing allegations similar to those made in the Texas-Ohio case,
albeit limited to California state law claims, was filed in California state
court in February 2004. CMS Energy and CMS MST are named as defendants.
Defendants filed a notice to remove this action to California federal district
court, which was granted, and had it transferred to the MDL proceeding in
Nevada. However, the plaintiff is seeking to have the case remanded back to
California and until the issue is resolved, no further action will be taken.
Three new, virtually identical actions were filed in San Diego Superior
Court in July 2004, one by the County of Santa Clara (Santa Clara), one by the
County of San Diego (San Diego), and one by the City of and County of San
Francisco and the San Francisco City Attorney (collectively San Francisco).
Defendants, consisting of a number of energy companies including CMS Energy, CMS
MS&T, Cantera Natural Gas and Cantera Gas Company, are alleged to have engaged
in false reporting of natural gas price and volume information and sham sales to
artificially inflate natural gas retail prices in California. All three
complaints allege claims for unjust enrichment and violations of the Cartwright
Act, and the San Francisco action also alleges a claim for violation of the
California Business and Profession Code relating to unlawful, unfair and
deceptive business practices.
CMS Energy and its subsidiaries will vigorously defend themselves but
cannot predict the outcome of these matters.
132
EMPLOYMENT RETIREMENT INCOME SECURITY ACT CLASS ACTION LAWSUITS
CMS Energy is a named defendant, along with Consumers, CMS MST, and
certain named and unnamed officers and directors, in two lawsuits brought as
purported class actions on behalf of participants and beneficiaries of the CMS
Employees' Savings and Incentive Plan (the Plan). The two cases, filed in July
2002 in United States District Court for the Eastern District of Michigan, were
consolidated by the trial judge and an amended consolidated complaint was filed.
Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution
on behalf of the Plan with respect to a decline in value of the shares of CMS
Energy Common Stock held in the Plan. Plaintiffs also seek other equitable
relief and legal fees. The judge issued an opinion and order dated March 31,
2004 in connection with the motions to dismiss filed by CMS Energy, Consumers
and the individuals. The judge dismissed certain of the amended counts in the
plaintiffs' complaint and denied CMS Energy's motion to dismiss the other claims
in the complaint. CMS Energy, Consumers and the individual defendants filed
answers to the amended complaint on May 14, 2004. A trial date has not been set,
but is expected to be no earlier than late in 2005. CMS Energy and Consumers
will defend themselves vigorously but cannot predict the outcome of this
litigation.
SECURITIES CLASS ACTION LAWSUITS
Beginning on May 17, 2002, a number of securities class action complaints
were filed against CMS Energy, Consumers, and certain officers and directors of
CMS Energy and its affiliates. The complaints were filed as purported class
actions in the United States District Court for the Eastern District of
Michigan, by shareholders who allege that they purchased CMS Energy's securities
during a purported class period. The cases were consolidated into a single
lawsuit and an amended and consolidated class action complaint was filed on May
1, 2003. The consolidated complaint contains a purported class period beginning
on May 1, 2000 and running through March 31, 2003. It generally seeks
unspecified damages based on allegations that the defendants violated United
States securities laws and regulations by making allegedly false and misleading
statements about CMS Energy's business and financial condition, particularly
with respect to revenues and expenses recorded in connection with round-trip
trading by CMS MST. The judge issued an opinion and order dated March 31, 2004
in connection with various pending motions, including plaintiffs' motion to
amend the complaint and the motions to dismiss the complaint filed by CMS
Energy, Consumers and other defendants. The judge directed plaintiffs to file an
amended complaint under seal and ordered an expedited hearing on the motion to
amend, which was held on May 12, 2004. At the hearing, the judge ordered
plaintiffs to file a Second Amended Consolidated Class Action complaint deleting
Counts III and IV relating to purchasers of CMS PEPS, which the judge ordered
dismissed with prejudice. Plaintiffs filed this complaint on May 26, 2004. CMS
Energy, Consumers, and the individual defendants filed new motions to dismiss on
June 21, 2004. A hearing on those motions occurred on August 2, 2004 and the
judge has taken the matter under advisement. CMS Energy, Consumers and the
individual defendants will defend themselves vigorously but cannot predict the
outcome of this litigation.
ENVIRONMENTAL MATTERS
CMS Energy and its subsidiaries and affiliates are subject to various
federal, state and local laws and regulations relating to the environment.
Several of these companies have been named parties to various actions involving
environmental issues. Based on their present knowledge and subject to future
legal and factual developments, they believe it is unlikely that these actions,
individually or in total, will have a material adverse effect on their financial
condition or future results of operations. For additional information, see the
10-K MD&A the and the Notes to the December 31, 2003 Financial Statements, and
the 10-Q MD&A and the Notes to the June 30, 2004 Financial Statements.
133
OUR MANAGEMENT
The following table sets forth the names, ages, positions and five-year
employment history of our executive officers as of June 1, 2004.
EXECUTIVE OFFICERS
Name Age Position Period
-------------------------------------------------------------------------------------------------------------------
Kenneth Whipple 69 Chairman of the Board, Chief Executive Officer of CMS Energy 2002-Present
Chairman of the Board, Chief Executive Officer of Consumers 2002-Present
Chairman of the Board of CMS Enterprises 2002-2003
Director of CMS Energy 1993-Present
Director of Consumers 1993-Present
Chairman, Chief Executive Officer of Ford Credit Company 1997-1999
Executive Vice President, President of Ford Financial Services Group 1989-1999
S. Kinnie Smith, Jr. 73 Vice Chairman of the Board of CMS Enterprises 2003-Present
Vice Chairman of the Board, General Counsel of CMS Energy 2002-Present
Vice Chairman of the Board of Consumers 2002-Present
Executive Vice President of CMS Enterprises 2002-2003
Director of CMS Energy 2002-Present
Director of Consumers 2002-Present
Director of Enterprises 2003-Present
Vice Chairman of Trans-Elect, Inc. 2002
Senior Counsel at Skadden, Arps, Slate, Meagher, & Flom LLP 1995-2002
David W. Joos 50 Chairman of the Board, Chief Executive Officer of CMS Enterprises 2003-Present
President, Chief Operating Officer of CMS Energy 2001-Present
President, Chief Operating Officer of Consumers 2001-Present
President, Chief Operating Officer of CMS Enterprises 2001-2003
Director of CMS Energy 2001-Present
Director of Consumers 2001-Present
Director of Enterprises 2000-Present
Executive Vice President, Chief Operating Officer - Electric
of CMS Energy 2000-2001
Executive Vice President, Chief Operating Officer - Electric
of CMS Enterprises 2000-2001
Executive Vice President, President and Chief Executive Officer -
Electric of Consumers 1997-2001
Thomas J. Webb 51 Executive Vice President, Chief Financial Officer of CMS Energy 2002-Present
Executive Vice President, Chief Financial Officer of Consumers 2002-Present
Executive Vice President, Chief Financial Officer of CMS Enterprises 2002-Present
Director of Enterprises 2002-Present
Executive Vice President, Chief Financial Officer of Panhandle
Eastern Pipe Line Company 2002-2003
Executive Vice President, Chief Financial Officer of Kellogg Company 1999-2002
Vice President, Chief Financial Officer of Visteon, a division of
Ford Motor Company 1996-1999
Thomas W. Elward 55 President, Chief Operating Officer of CMS Enterprises 2003-Present
President, Chief Executive Officer of CMS Generation Co. 2002-Present
Director of Enterprises 2003-Present
Senior Vice President of CMS Enterprises 2002-2003
Senior Vice President of CMS Generation Co. 1998-2001
Carl L. English 57 Executive Vice President, President and Chief Executive Officer -
Gas of Consumers 1999-Present
Vice President of Consumers 1990-1999
David G. Mengebier* 46 Senior Vice President of CMS Enterprises 2003-Present
Senior Vice President of CMS Energy 2001-Present
Senior Vice President of Consumers 2001-Present
Vice President of CMS Energy 1999-2001
134
Vice President of Consumers 1999-2001
John G. Russell** 46 Executive Vice President, President and Chief Executive Officer -
Electric of Consumers 2001-Present
Senior Vice President of Consumers 2000-2001
Vice President of Consumers 1999-2000
John F. Drake 55 Senior Vice President of CMS Enterprises 2003-Present
Senior Vice President of CMS Energy 2002-Present
Senior Vice President of Consumers 2002-Present
Vice President of CMS Energy 1997-2002
Vice President of Consumers 1998-2002
Glenn P. Barba 38 Vice President, Chief Accounting Officer of CMS Enterprises 2003-Present
Vice President, Controller and Chief Accounting Officer of CMS Energy 2003-Present
Vice President, Controller and Chief Accounting Officer of Consumers 2003-Present
Vice President and Controller of Consumers 2001-2003
Controller of CMS Generation 1997-2001
----------
* From 1997 to 1999, Mr. Mengebier served as Executive Director of Federal
Governmental Affairs for CMS Enterprises.
** From July 1997 until October 1999, Mr. Russell served as Manager --
Electric Customer Operations of Consumers.
There are no family relationships among executive officers and directors
of CMS Energy.
DIRECTORS
MERRIBEL S. AYRES, 52, has served since 1996 as President of Lighthouse Energy
Group, LLC, a firm she founded. Lighthouse provides governmental affairs and
communications expertise, as well as management consulting and business
development services, to a broad spectrum of international clients focused on
energy and environmental matters. Ms. Ayers served from 1988 to 1996 as Chief
Executive Officer of the National Independent Energy Producers of Washington, D.
C., a trade association representing the independent power supply industry. She
is a member of the Aspen Institute Energy Policy Forum, the National Advisory
Council of the National Renewable Energy Laboratory, and the Dean's Alumni
Leadership council of Harvard University's Kennedy School of Government. She was
elected as a director of CMS and Consumers on May 28, 2004.
EARL D. HOLTON, 70, has served since 1999 as Vice Chairman of Meijer, Inc., a
Grand Rapids, Michigan based operator of food and general merchandise centers.
He served from 1980 to 1999 as President of Meijer, Inc. He is a director of
Meijer, Inc. and Steelcase, Inc. He has been a director of CMS and of Consumers
since 1989.
DAVID W. JOOS, 51, has served since 2001 as President and Chief Operating
Officer of CMS and Consumers. He served from 2000 to 2001 as Executive Vice
President and Chief Operating Officer -- Electric of CMS and from 1997 to 2000
as President and Chief Executive Officer -- Electric of Consumers. He is a
director of Steelcase, Inc., the Michigan Colleges Foundation, Michigan Economic
Development Corporation, is a director and Chairman of Nuclear Management Co.,
and is a director and Chairman of the Michigan Manufacturers Association. He has
been a director of CMS and of Consumers since 2001.
MICHAEL T. MONAHAN, 65, has served since 1999 as President of Monahan
Enterprises, LLC, a Bloomfield Hills, Michigan based consulting firm. He was
Chairman of Munder Capital Management, an investment management company, from
October 1999 to December 2000 and Chairman and Chief Executive Officer of Munder
from October 1999 until January 2000. Prior to that, he was President and a
director of Comerica Bank from 1992 to 1999 and President and a director of
Comerica Inc., from 1993 to 1999. He is a director of The Munder Funds, Inc.,
Chairman of the Board of Guilford Mills, Inc., a member of the board of trustees
of Henry Ford Health Systems, Inc., and a member of the board of trustees of the
Community Foundation for Southeastern Michigan. He has been a director of CMS
and Consumers since December 2002.
135
JOSEPH F. PAQUETTE, JR., 69, served from 1988 to 1995 as Chairman of the Board
and Chief Executive Officer and from 1995 until his retirement in 1997 as
Chairman of the Board of PECO Energy, formerly the Philadelphia Electric
Company, a major supplier of electric and gas energy. He is a director of USEC,
Inc. and Mercy Health Systems. He has been a director of CMS and Consumers since
December 2002. He had previously served as a director of CMS and Consumers and
as President of CMS from 1987 to 1988.
WILLIAM U. PARFET, 57, has served since 1999 as Chairman and Chief Executive
Officer of MPI Research, Inc., Mattawan, Michigan, a contract research
laboratory conducting risk assessment toxicology studies. He served from 1995 to
1999 as Co-Chairman of MPI Research. He is a director of Stryker Corporation,
PAREXEL International Corporation, and Monsanto Company. He is also a
commissioner of the Michigan Department of Natural Resources. He has been a
director of CMS and of Consumers since 1991.
PERCY A. PIERRE, 65, has served since 1990 as Professor of Electrical
Engineering, Michigan State University, East Lansing, Michigan. He also served
as Vice President for Research and Graduate Studies at Michigan State University
from 1990 to 1995. Dr. Pierre is a former Assistant Secretary of the Army for
Research, Development and Acquisition. He is also a former President of Prairie
View A&M University. He is a director of Fifth Third Bank (Western Michigan). He
also serves as a member of the Boards of Trustees for the University of Notre
Dame and Hampshire College. He has been a director of CMS and of Consumers since
1990.
S. KINNIE SMITH, JR., 73, has served as Vice Chairman and General Counsel of CMS
since June 2002. He served as Senior Counsel for the law firm Skadden, Arps,
Slate, Meagher & Flom from 1996 to 2002. He has been a director of CMS and
Consumers since August 2002. He had held the positions of Vice Chairman and
President of CMS and Vice Chairman of Consumers and served as a director of CMS
and Consumers from 1987 to 1996. In May and June of 2002, he served as Vice
Chairman and as a director of Trans-Elect, Inc.
KENNETH L. WAY, 64, served from 1988 through 2002 as Chairman of the Board of
Lear Corporation, a Southfield, Michigan based supplier of automotive interior
systems to the automotive industry. He remains a director of Lear Corporation.
In addition, he served from 1988 to 2000 as Chief Executive Officer of Lear
Corporation. He is a director of Comerica, Inc. and WESCO International, Inc. He
also serves as a member of the Boards of Trustees for Kettering University and
the Henry Ford Health Systems. He has been a director of CMS and of Consumers
since 1998.
KEN WHIPPLE, 69, has served since May of 2002 as Chairman of the Board and Chief
Executive Officer of CMS and Consumers. He served from 1988 until his retirement
in 1999 as Executive Vice President of Ford Motor Company, Dearborn, Michigan, a
world-wide automotive manufacturer, and President of the Ford Financial Services
Group. In addition, he served from 1997 to 1999 as Chairman and Chief Executive
Officer of Ford Motor Credit Company. He had previously served as Chairman and
Chief Executive Officer of Ford of Europe, Inc. from 1986 to 1988. He is a
director of AB Volvo and a trustee of 13 J.P.Morgan Chase mutual funds. He has
been a director of CMS and of Consumers since 1993.
JOHN B. YASINSKY, 64, served from 1999 until his retirement in 2000 as Chairman
of the Board and Chief Executive Officer and continued as Chairman until
February 2001 of OMNOVA Solutions Inc., Fairlawn, Ohio, a developer,
manufacturer, and marketer of emulsion polymers, specialty chemicals, and
building products. He served from 1995 to 1999 as Chairman, Chief Executive
Officer and President of GenCorp. He is a director of A. Schulman, Inc. He has
been a director of CMS and of Consumers since 1994.
136
MANAGEMENT SECURITY OWNERSHIP
The following chart shows the ownership of CMS Common Stock by the
directors and executive officers:
Shares
Name Beneficially Owned*
---------------------------------------------------------------------
James J. Duderstadt ........................ 7,791
Kathleen R. Flaherty ....................... 8,504
Earl D. Holton ............................. 26,916
David W. Joos .............................. 211,171
Michael T. Monahan ......................... 3,943
Joseph F. Paquette, Jr ..................... 21,345
William U. Parfet .......................... 15,800
Percy A. Pierre ............................ 8,215
S. Kinnie Smith, Jr ........................ 155,046
Kenneth L. Way ............................. 49,613
Kenneth Whipple ............................ 356,011
John B. Yasinsky ........................... 16,485
Thomas J. Webb ............................. 100,278
Thomas W. Elward ........................... 44,620
David A. Mikelonis ......................... 42,045
William J. Haener .......................... 73,224
All Directors and Executive Officers** ..... 1,480,328
* All shares shown above are as of December 31, 2003. In addition to the shares
shown above, Mr. Joos, Mr. Smith, Mr. Webb, Mr. Elward, Mr. Mikelonis, Mr.
Haener and all other executive officers of CMS and Consumers own options to
acquire 473,000; 165,000; 150,000; 146,000; 137,000; 224,500; and 1,213,520
shares, respectively. Mr. Whipple does not own any options to acquire CMS Common
Stock. All options identified in this footnote are as of December 31, 2003.
** All Directors and Executive Officers include executive officers of both CMS
and Consumers.
Shares shown as beneficially owned include (1) shares to which a person
has or shares voting power and/or investment power, and (2) the number of shares
and share equivalents represented by interests in the Employee Savings Plan, the
Deferred Salary Savings Plan, the Performance Incentive Stock Plan, the
Directors' Deferred Compensation Plan, Salaried Employees' Merit Plan and
employment agreements. Dr. Duderstadt, Ms. Flaherty, Mr. Holton, Mr. Parfet, Mr.
Smith, Mr. Way, Mr. Whipple, and Mr. Yasinsky each own 10 shares of Preferred
Stock of Consumers. The directors and executive officers of CMS and Consumers
together own less than 1% of the outstanding shares of CMS.
SECTION 16(A) BENEFICIAL OWNERSHIP REGARDING COMPLIANCE
Federal securities laws require CMS directors and executive officers, and
persons who own more than 10% of CMS Common Stock, to file with the SEC reports
of ownership and changes in ownership of any securities or derivative securities
of CMS. To CMS' knowledge, during the year ended December 31, 2003, CMS'
officers and directors made all required Section 16(a) filings on a timely
basis.
COMPENSATION OF DIRECTORS
Directors who are not officers of CMS or Consumers received in 2003 an
annual retainer fee of $30,000, $1,500 for attendance at each Board meeting and
$750 for attendance at each committee meeting. Committee chairs received $1,000
for attendance at each committee meeting. These figures have remained unchanged
for several years, and are relatively low by industry standards. In 2003, all
directors who were not officers of CMS or Consumers were granted 850 restricted
shares of CMS Common Stock with a fair market value at time of grant of $6,468.
These restricted shares must be held for at least three years from the date of
grant. These restricted shares must be held for at least three years from the
date of grant Directors are reimbursed for expenses incurred in attending Board
or committee meetings. Directors who are officers of CMS or Consumers do not
receive retainers or meeting fees for service on the Board or as a member of any
Board committee. Pursuant to the Directors'
137
Deferred Compensation Plan, a director of CMS or Consumers who is not an officer
may, at any time prior to a calendar year in which a retainer and fees are to be
earned, or at any time during the year prior to the month in which a retainer
and fees are earned, irrevocably elect to defer payment for that year, or a
portion thereof, through written notice to CMS or Consumers, of all or half of
any of the retainer and fees which would otherwise be paid to the director, to a
time following the director's retirement from the Board of Directors. Any amount
deferred will either (a) accrue interest at either the prime rate or the rate
for 10-year Treasury Notes (whichever is greater), (b) be treated as if it were
invested as an optional cash payment in CMS' Stock Purchase Plan, or (c) be
treated as if it were invested in a Standard & Poor's 500 stock index fund.
Accrued amounts will be distributed in a lump sum or in five or ten annual
installments in cash. Outside directors who retire with five years of service on
the Board will receive retirement payments equal to the retainer. These payments
will continue for a period of time equal to their years of service on the Board.
All benefits will cease at the death of the retired director. Outside directors
are offered optional life insurance coverage, business-related travel accident
insurance, and optional health care insurance, and CMS and Consumers pay the
premiums associated with participation by directors. The imputed income for the
life insurance coverage in 2003 was: Messrs. Duderstadt, $753: Holton, $2,715;
Monahan, $726; Paquette, $2,553; Parfet, $663; Pierre, $726; Whipple, $2,553;
Yasinsky, $744; and Ms. Flaherty, $399. The imputed income for health insurance
coverage in 2003 was: Ms. Flaherty, $9,289.
EXECUTIVE COMPENSATION
The following charts contain information concerning annual and long-term
compensation and awards of stock options and restricted stock under CMS'
Performance Incentive Stock Plan. The charts include the Chairman of the Board
and Chief Executive Officer and the next four most highly compensated executive
officers in 2003.
SUMMARY COMPENSATION TABLE
LONG-TERM
COMPENSATION(1)
-------------------------------------------------------
AWARDS PAYOUTS
ANNUAL --------------------------- -------------------------
COMPENSATION RESTRICTED SECURITIES LONG-TERM
------------------------------- STOCK UNDERLYING INCENTIVE ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS AWARDS(2) OPTIONS PAYOUTS(3) COMPENSATION
-------------------------------- ------ -------------- -------------- -------------- ---------- ---------- ------------
Current Officers
KENNETH WHIPPLE................. 2003 $1,156,431(4a) $1,620,000(4b) $1,015,000(4c) 0 $ 0 $ 0
Chairman and CEO, CMS 2002 639,060(4d) 0 0 0 0 0
and Consumers 2001 0 0 0 0 0 0
DAVID W. JOOS................... 2003 750,000 734,103(5) 635,000(7) 100,000 0 0
President and COO, 2002 750,000 0 406,000(7) 165,000 0 15,000(6)
CMS and Consumers 2001 637,500 0 0 100,000 35,907 19,125(6)
S KINNIE SMITH, JR.............. 2003 600,000 581,742(5) 381,000(7) 100,000 0 0
Vice Chairman and General 2002 300,000 0 263,900(7) 65,000 0 3,000(6)
Counsel of CMS 2001 0 0 0 0 0 0
THOMAS J. WEBB.................. 2003 500,000 459,351(5) 381,000(7) 100,000 0 0
Chief Financial Officer, CMS 2002 208,333 0 203,000(7) 50,000 0 0
and Consumers 2001 0 0 0 0 0 0
THOMAS W. ELWARD................ 2003 320,040 266,749(5) 127,000(7) 76,000 0 0
President and COO 2002 320,040 0 81,200(7) 36,000 0 6,401(6)
CMS Enterprises 2001 270,000 0 0 14,000 13,453 8,100(6)
DAVID A. MIKELONIS.............. 2003 355,000 266,085(5) 76,200(7) 59,000 0 0
Senior Vice President and 2002 355,000 0 56,840(7) 28,000 0 7,100(6)
General Counsel, Consumers 2001 355,000 0 0 14,000 17,978 10,650(6)
Former Officer
WILLIAM J. HAENER............... 2003 530,000 455,058(5) 0 0 0 0
Executive Vice President, 2002 530,000 0 178,640(7) 82,500 0 10,600(6)
And COO - Natural Gas, CMS 2001 509,167 0 0 40,000 26,930 15,275(6)
(1) Aggregate non-performance based restricted stock held as of December 31,
2003 by named officers was: Mr. Whipple, 900 shares, with a year-end
market value of $7,668; Mr. Joos, 150,000 shares, with a year-end market
value of $1,278,000; Mr. Smith, 92,500 shares, with a year-end market
value of $788,100; Mr. Webb, 85,000 shares, with a year-end market value
of $724,200; Mr. Elward, 30,000 shares, with a year-end market value of
$255,600; Mr. Mikelonis, 19,000 shares, with a year-end market value of
$161,880; and Mr. Haener, 22,318 shares, with year-end market value of
$190,149. No dividends were paid on such restricted stock.
138
(2) 2003 restricted stock awards granted August 22, 2003. These shares
vest at a rate of 25% per year beginning August 22, 2005. The 2003
dollar values shown above are based on the August 22, 2003 grant
date closing price of $6.35 per share.
(3) Market value of CMS Common Stock paid under CMS' Performance
Incentive Stock Plan for three-year performance periods.
(4) (a) Mr. Whipple's 2003 salary consisted of $134,933 in cash
compensation and $1,021,498 in deferred compensation in the form of
phantom stock units payable in cash. The payout value of the
deferred salary will be based on the future price of CMS Common
Stock.
(b) Mr. Whipple's bonus consisted of an amount earned with respect
to 2003 but for which payment is deferred into future years in the
form of phantom stock units payable in cash. The payout value of the
deferred bonus will be based on the future price of CMS Common Stock
when 50% of the phantom stock units are cashed out on each of the
first and second anniversaries of the bonus award.
(c) Mr. Whipple's 2003 restricted stock value consisted of 125,000
restricted phantom stock units awarded on October 31, 2003 and
payable in cash upon vesting at a rate of 25% per year beginning
September 1, 2005. The dollar value of this award upon vesting will
be based upon the future price of CMS Common Stock. The 2003 dollar
value shown is based on the grant date closing price of CMS Common
Stock of $8.12 per share. These phantom stock units were awarded
pursuant to the terms of Mr. Whipple's employment agreement in lieu
of the restricted stock and options awarded to other officers under
CMS' Performance Incentive Stock Plan. At December 31, 2003, these
125,000 phantom stock units had a market value of $1,065,000 at
$8.52 per share.
(d) Mr. Whipple's 2002 salary consisted of $2,125 in cash
compensation and $636,935 in deferred compensation in the form of
phantom stock units payable in cash. The payout value of the
deferred salary will be based on the future price of CMS Common
Stock.
(5) Bonuses for 2003 for Messrs. Joos, Smith, Webb and Elward were
deferred and will be paid out in the first quarter of 2005
consistent with the payouts from the Corporation's Salaried
Employees' Merit Plan. The 2003 bonuses for Messrs. Mikelonis and
Haener were paid out in the first quarter of 2004.
(6) Employer matching contribution to defined contribution plans. No
employer matching contributions were made in 2003.
(7) Mr. Joos, Mr. Smith, Mr. Webb, Mr. Elward, Mr. Mikelonis and Mr.
Haener were awarded 50,000, 32,500, 25,000, 10,000, 7,000 and 22,000
restricted shares, respectively, in 2002 and 100,000, 60,000,
60,000, 20,000, 12,000 and zero restricted shares, respectively in
2003.
EMPLOYMENT ARRANGEMENTS
Agreements with the executive officers named above provide for payments
equal to three times annual cash compensation if there is a change of control
and adverse change of responsibilities, as well as payments equal to two times
annual cash compensation if employment is terminated by the company, other than
for cause, in the absence of a change of control. CMS and Consumers also provide
long-term disability insurance policies for all executive officers, which would
provide payment of up to 60% of compensation in the event of disability. CMS
does not have a "poison pill" plan and is not considering the adoption of such a
plan.
139
OPTION GRANTS IN 2003
Number Of Securities Percentage Of Total Exercise Grant Date
Underlying Options Options Granted To Price Per Expiration Present
Name Granted Employees In 2003 Share Date Value(1)
------------------ -------------------- ------------------- --------- ---------- ------------
Kenneth Whipple 0 0 0 $ 0
David W. Joos 100,000 6.3 6.35 9-21-13 296,000
S Kinnie Smith, Jr 100,000 6.3 6.35 9-21-13 296,000
Thomas J. Webb 100,000 6.3 6.35 9-21-13 296,000
Thomas W. Elward 76,000 4.8 6.35 9-21-13 224,960
David A. Mikelonis 59,000 3.7 6.35 9-21-13 174,640
William J. Haener 0 0 0 0
------- --- ---- ------- ------------
(1) The present value is based on the Black-Scholes Model, a mathematical
formula used to value options traded on securities exchanges. The model
utilizes a number of assumptions, including the exercise price, the
underlying CMS Common Stock's volatility using weekly closing prices for a
four and one half year period prior to grant date, the dividend rate, the
term of the option, and the level of interest rates equivalent to the
yield of four-year Treasury Notes. However, the Model does not take into
account a significant feature of options granted to employees under CMS'
Plan, the non-transferability of options awarded. For those options above
with an expiration date of September 21, 2013 (granted August 22, 2003),
the volatility was 55.46%, the dividend rate at the time was $0.00 per
quarter, and the interest rate was 3.02%.
AGGREGATED OPTION EXERCISES IN 2003 AND YEAR-END OPTIONS VALUES
Number Of Securities Value Of Unexercised
Shares Acquired Value Underlying Unexercised In-The-Money Options
Name On Exercise Realized Options At Year End At Year End(1)(2)
------------------ --------------- -------- ---------------------- --------------------
Kenneth Whipple 0 $ 0 0 $ 0
David W. Joos 0 0 473,000 257,000
S Kinnie Smith, Jr 0 0 165,000 243,000
Thomas J. Webb 0 0 150,000 237,000
Thomas W. Elward 0 0 146,000 172,920
David A. Mikelonis 0 0 137,000 133,630
William J. Haener 0 0 224,500 17,000
--- -------- ------- ------------
(1) All options listed in this table are exercisable. The named officers have
no unexercisable options.
(2) Based on the December 31, 2003 closing price of CMS Common Stock as shown
in the report of the NYSE Composite Transactions ( $8.52 ).
PENSION PLAN TABLE
The following table shows the aggregate annual pension benefits at normal
retirement date presented on a straight life annuity basis under CMS' qualified
Pension Plan and non-qualified Supplemental Executive Retirement Plan (offset by
a portion of Social Security benefits).
Years Of Service
------------ --------------------------------------------------------------------------
Compensation 15 20 25 30 35
------------ -------- ----------- ----------- ------------- -------------
$ 500,000 $157,500 $ 210,000 $ 247,500 $ 285,000 $ 322,500
800,000 252,000 336,000 396,000 456,000 516,000
1,100,000 346,500 462,000 544,500 627,000 709,500
1,400,000 441,000 588,000 693,000 798,000 903,000
1,700,000 535,500 714,000 891,500 969,000 1,096,500
2,000,000 630,000 840,000 990,000 1,140,000 1,290,000
-------- ----------- ----------- ------------- -------------
"Compensation" in this table is the average of Salary plus Bonus, as shown
in the Summary Compensation Table, for the five years of highest earnings. The
estimated years of service for each named executive is: Mr.
140
Whipple, 3.56 years; Mr. Joos, 32.33 years; Mr. Smith, 20.82 years; Mr. Webb,
2.99 years; Mr. Elward 35.00 years; Mr. Mikelonis, 35.00 years; and Mr. Haener,
20.00 years.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
Number Of Securities
Number of Remaining Available
Securities to For Future Issuance
be Issued Upon Under Equity Compensation
Upon Exercise of Weighted-Average Plans
Outstanding Options, Exercise Price of Outstanding (Excluding Securities
Plan Category Warrants and Rights Options, Warrants and Rights Reflected In Column (A))
---------------------- -------------------- ----------------------------- --------------------------
(a) (b) (c)
Equity compensation 5,821,576 $ 21.27 2,240,247
plans approved by
security holders
Equity compensation 0 0 0
plans not approved by
security holders
--------- --------- ---------
Total 5,821,576 $ 21.27 2,240,247
========= ========= =========
The Performance Incentive Stock Plan reserves for award not more than five
percent of Common Stock outstanding on January 1 of each year, less (i) the
number of shares of restricted Common Stock awarded and (ii) Common Stock
subject to options granted under the plan during the immediately preceding four
calendar years. The number of shares of restricted Common Stock awarded under
this plan cannot exceed 20 percent of the aggregate number of shares reserved
for award. Any forfeitures of shares previously awarded will increase the number
of shares available to be awarded under the plan. At December 31, 2003, awards
of up to 2,240,247 shares of CMS Common Stock may be issued..
AFFILIATE RELATIONSHIPS AND TRANSACTIONS
On May 1, 2002, Consumers sold its electric transmission system to
Michigan Transmission Holdings, LLP, a non-affiliated limited partnership whose
general partner is a subsidiary of Trans-Elect, Inc. A Trans-Elect, Inc.
subsidiary provides interstate electric transmission service to Consumers
pursuant to agreements entered into at the time of the sale. The rates and other
terms of the service were approved by the Federal Energy Regulatory Commission
prior to the sale and remain subject to the Commissions' jurisdiction. From May
15, 2002 until June 30, 2002, S. Kinnie Smith, Jr. served as Vice Chairman of
Trans-Elect, Inc. Mr. Smith served as a director of Trans-Elect, Inc. since its
organization in 1998. Mr. Smith resigned as Vice Chairman and director of
Trans-Elect, Inc. upon becoming Vice Chairman, General Counsel, and a director
of CMS. Mr. Smith owns 20,000 shares of Convertible Preferred A Stock of
Trans-Elect, Inc., or approximately 10% of the outstanding voting securities of
Trans-Elect, Inc. Mr. Smith also has an option to acquire an additional 250
shares of this security.
The Consumers electric transmission system was sold in a competitive
bidding process to Trans-Elect, Inc's subsidiary for approximately $290 million
in cash. Consumers did not provide any financial or credit support for the sale
to Trans-Elect, Inc. As a result of the sale, Consumers experienced an after-tax
earnings increase of approximately $17 million in 2002 due to the recognition of
a $26 million gain on the sale. During the calendar year 2003, Consumers paid a
total of $74 million to Trans-Elect, Inc's subsidiary for electric transmission
services.
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSEQUENSES
DESCRIPTION OF CERTAIN FEDERAL INCOME TAX CONSEQUENCES OF THE EXCHANGE OF OLD
NOTES FOR NEW NOTES
The following summary describes the principal United States federal income
tax consequences to holders who exchange old notes for new notes pursuant to the
Exchange Offer. This summary is intended to address the beneficial owners of old
notes that are citizens or residents of the United States, corporations,
partnerships or other entities created or organized in or under the laws of the
United States or any State or the District of Columbia, or
141
estates or trusts that are not foreign estates or trusts for United States
federal income tax purposes, in each case, that hold the old notes as capital
assets.
The exchange of old notes for new notes pursuant to the Exchange Offer
will not constitute a taxable exchange for United States federal income tax
purposes. As a result, a holder of an old note whose old note is accepted in the
Exchange Offer will not recognize gain or loss on the exchange. A tendering
holder's tax basis in the new notes received pursuant to the Exchange Offer will
be the same as such holder's tax basis in the old notes surrendered therefore. A
tendering holder's holding period for the new notes received pursuant to the
Exchange Offer-will include its holding period for the old notes surrendered
therefore.
ALL HOLDERS OF OLD NOTES ARE ADVISED TO CONSULT THEIR OWN TAX ADVISORS
REGARDING THE UNITED STATES FEDERAL, STATE AND LOCAL TAX CONSEQUENCES OF THE
EXCHANGE OF OLD NOTES FOR NEW NOTES, AND OF THE OWNERSHIP AND DISPOSITION OF NEW
NOTES RECEIVED IN THE EXCHANGE OFFER IN LIGHT OF THEIR OWN PARTICULAR
CIRCUMSTANCES.
DESCRIPTION OF CERTAIN FEDERAL INCOME TAX CONSEQUENCES OF AN INVESTMENT IN THE
NEW NOTES
The following is a summary of the material United States federal income
tax consequences of the acquisition, ownership and disposition of the old notes
or the new notes by a United States Holder (as defined below). This summary
deals only with the United States Holders that will hold the old notes or the
new notes as capital assets. The discussion does not cover-all aspects of
federal taxation that may be relevant to, or the actual tax effect that any of
the matters described herein will have on, the acquisition, ownership or
disposition of the old notes or the new notes by particular investors, and does
not address state, local, foreign or other tax laws. In particular, this summary
does not discuss all of the tax considerations that may be relevant to certain
types of investors subject to special treatment under the federal income tax
laws (such as banks, insurance companies, investors liable for the alternative
minimum tax, individual retirement accounts and other tax-deferred accounts,
tax-exempt organizations, dealers in securities or currencies, investors that
will hold the old notes or the new notes as part of straddles, hedging
transactions or conversion transactions for federal tax purposes or investors
whose functional currency is not United States Dollars). Furthermore, the
discussion below is based on provisions of the Internal Revenue Code of 1986, as
amended (the "CODE"), and regulations, rulings, and judicial decisions
thereunder as of the date hereof, and such authorities may be repealed, revoked
or modified so as to result in U.S. federal income tax consequences different
from those discussed below.
PERSONS CONSIDERING THE PURCHASE, OWNERSHIP, OR DISPOSITION OF NEW NOTES
SHOULD CONSULT THEIR OWN TAX ADVISORS CONCERNING THE U.S. FEDERAL INCOME TAX
CONSEQUENCES IN LIGHT OF THEIR PARTICULAR SITUATIONS AS WELL AS ANY CONSEQUENCES
ARISING UNDER THE LAWS OF ANY STATE, LOCAL OR INTERNATIONAL TAXING JURISDICTION.
As used herein, the term "UNITED STATES HOLDER" means a beneficial owner
of the old notes or the new notes that is (i) a citizen or resident of the
United States for United States federal income tax purposes, (ii) a corporation
created or organized under the laws of the United States or any State thereof,
(iii) a person or entity that is otherwise subject to United States federal
income tax on a net income basis in respect of income derived from the old notes
or the new notes, or (iv) a partnership to the extent the interest therein is
owned by a person who is described in clause (i), (ii) or (iii) of this
paragraph.
INTEREST
Interest paid on an old note or a new note will be taxable to a United
States Holder as ordinary income at the time it is received or accrued,
depending on the holder's method of accounting for tax purposes.
PURCHASE, SALE, EXCHANGE, RETIREMENT AND REDEMPTION OF THE NEW NOTES
In general (with certain exceptions described below) a United States
Holder's tax basis in a new note will equal the price paid for the old notes for
which such new note was exchanged pursuant to the Exchange Offer. A United
States Holder generally will recognize gain or loss on the sale, exchange,
retirement, redemption or other disposition
142
of an old note or a new note (or portion thereof) equal to the difference
between the amount realized on such disposition and the United States Holder's
tax basis in the old note or the new note (or portion thereof). Except to the
extent attributable to accrued but unpaid interest, gain or loss recognized on
such disposition of an old note or a new note will be capital gain or loss. Such
capital gain or loss will generally be long-term capital gain or loss if the
United States Holder held such note (including in the holding period of the new
note, the period during which the United Stated Holder held the old notes
surrendered for it) for more than one year immediately prior to such
disposition. Long-term capital gains of individuals are eligible for
preferential rates of taxation, which have been reduced for long-term capital
gains recognized on or after May 6, 2003 and before January 1, 2009. The
deductibility of capital losses is subject to limitations.
NOTE PREMIUM
If a United States Holder acquires a new note or has acquired an old note,
in each case, for an amount more than its redemption price, the Unites States
Holder may elect to amortize such note premium on a yield to maturity basis.
Once made, such an election applies to all notes (other than notes the interest
on which is excludable from gross income) held by the United States Holder at
the beginning of the first taxable year to which the election applies or
thereafter acquired by the United States Holder, unless the IRS consents to a
revocation of the election. The basis of a new note will be reduced by any
amortizable note premium taken as a deduction.
MARKET DISCOUNT
The purchase of a new note or the purchase of an old note other than at
original issue may be affected by the market discount provisions of the Code.
These rules generally provide that, if a United States Holder purchases a new
note (or purchased an old note) at a "market discount," as defined below, and
thereafter recognizes gain upon a disposition of the new note (including
dispositions by gift or redemption), the lesser of such gain (or appreciation,
in the case of a gift) or the portion of the market discount that has accrued
("ACCRUED MARKET DISCOUNT") while the new note (and its predecessor old note, if
any) was held by such United States Holder will be treated as ordinary interest
income at the time of disposition rather than as capital gain. For a new note or
an old note, "MARKET DISCOUNT" is the excess of the stated redemption price at
maturity over the tax basis immediately after its acquisition by a United States
Holder. Market discount generally will accrue ratably during the period from the
date of acquisition to the maturity date of the new note, unless the United
States Holder elects to accrue such discount on the basis of the constant yield
method. Such an election applies only to the new note with respect to which it
is made and is irrevocable.
In lieu of including the accrued market discount income at the time of
disposition, a United States Holder of a new note acquired at a market discount
(or acquired in exchange for an old note acquired at a market discount) may
elect to include the accrued market discount in income currently either ratably
or using the constant yield method. Once made, such an election applies to all
other obligations that the United States Holder purchases at a market discount
during the taxable year for which the election is made and in all subsequent
taxable years of the United States Holder, unless the Internal Revenue Service
consents to a revocation of the election. If an election is made to include
accrued market discount in income currently, the basis of a new note (or, where
applicable, a predecessor old note) in the hands of the United States Holder
will be increased by the accrued market discount thereon as it is includible in
income. A United States Holder of a market discount new note who does not elect
to include market discount in income currently generally will be required to
defer deductions for interest on borrowings allocable to such new note, if any,
in an amount not exceeding the accrued market discount on such new note until
the maturity or disposition of such new note.
BACKUP WITHHOLDING AND INFORMATION REPORTING
Payments of interest and principal on, and the proceeds of sale or other
disposition of the old notes or the new notes payable to a United States Holder,
may be subject to information reporting requirements and backup withholding at
the applicable statutory rate will apply to such payments if the United States
Holder fails to provide an accurate taxpayer identification number or to report
all interest and dividends required to be shown on its federal income tax
returns. Certain United States Holders (including, among others, corporations)
are not subject to backup withholding. United States Holders should consult
their tax advisors as to their qualification for exemption from backup
withholding and the procedure for obtaining such an exemption.
143
PLAN OF DISTRIBUTION
Each broker-dealer that receives new notes for its own account pursuant
the Exchange Offer must acknowledge that it will deliver a prospectus in
connection with any resale of such new notes. This prospectus, as it may be
amended or supplemented from time to time, may be used by a broker-dealer in
connections with resales of the new notes received in exchange for the old notes
where such old notes were acquired as a result of market-making activities or
other trading activities. CMS has agreed that, starting on the Expiration Date
and ending on the close of business on the first anniversary of the Expiration
Date, it will make this prospectus, as amended or supplemented, available to any
broker-dealer for use in connection with any such resale.
CMS will not receive any proceeds from any sale of the new notes by
broker-dealers. The new notes received by broker-dealers for their own account
pursuant to the Exchange Offer may be sold from time to time in one or more
transactions in the over-the counter market, in negotiated transaction, through
the writing of options on the new notes or a combination of such methods of
resale, at market prices or negotiated prices. Any such resale may be made
directly to purchasers or to or through brokers or dealers who may receive
compensation in the form of commissions or concessions from any such
broker-dealer and/or the purchasers of any such new notes. Any broker-dealer
that resells new notes that were received by it for its own account pursuant to
the Exchange Offer and any broker or dealer that participates in a distribution
of such new notes may be deemed to be an "UNDERWRITER" within the meaning of the
Securities Act and any profit of any such resale of new notes and any
commissions or concessions received by any such persons may be deemed to be
underwriting compensation under the Securities Act. The Letter of Transmittal
states that by acknowledging that it will deliver and by delivering a
prospectus, a broker-dealer will not be deemed to admit that it is an
"UNDERWRITER" within the meaning of the Securities Act.
For a period of one year after the Expiration Date, CMS will promptly send
additional copies of this prospectus and any amendment or supplement to this
prospectus to any broker-dealer that requests such documents in the Letter of
Transmittal. CMS has agreed to pay all expenses incident to the Exchange Offer
and will indemnify the holders of the new notes against certain liabilities,
including liabilities under the Securities Act.
LEGAL OPINION
Robert C. Shrosbree, Assistant General Counsel for CMS Energy Corporation,
will render opinions as to the legality of the new notes for CMS.
EXPERTS
The consolidated financial statements and schedule of CMS at December 31,
2003 and 2002, and for each of the three years in the period ended December 31,
2003, appearing in this prospectus and registration statement have been audited
by Ernst & Young LLP, independent registered public accounting firm, as set
forth in their report thereon appearing elsewhere herein which are based in part
on the reports of Price Waterhouse for Jorf Lasfar and PricewaterhouseCoopers
LLP for 2003 and 2002, independent registered public accounting firm and Arthur
Andersen LLP (who have ceased operations) for 2001 for the MCV Partnership,
independent auditors. The consolidated financial statements and schedule
referred to above are included in reliance upon such reports given on the
authority of such firms as experts in accounting and auditing.
The financial statements of Emirates CMS Power Company PJSC at December
31, 2003 and for the year ended December 31, 2003 appearing in this prospectus
and registration statement have been audited by Ernst & Young, independent
registered public accounting firm, as set forth in their report thereon
appearing elsewhere herein, and are included in reliance upon such report given
on the authority of such firm as experts in accounting and auditing.
The financial statements of Jorf Lasfar as of December 31, 2003 and 2002
and for each of the three years in the period ended December 31, 2003 included
in this prospectus have been so included in reliance on the report of Price
Waterhouse, independent accountants, given on the authority of said firm as
experts in auditing and accounting.
The consolidated financial statements of the MCV Partnership as of and for
the years ended December 31, 2003 and 2002 included in this Prospectus have been
so included in reliance on the report of PricewaterhouseCoopers
144
LLP, independent registered public accounting firm, given on the authority of
said firm as experts in auditing and accounting.
The audited consolidated financial statements of the MCV Partnership for
the year ended December 31, 2001, included in this prospectus, have been audited
by Arthur Andersen LLP, independent accountants. Arthur Andersen LLP has not
consented to the inclusion of their report on the financial statements of the
MCV Partnership for the year ended December 31, 2001 in this prospectus, and we
have dispensed with the requirement to file their consent in reliance upon Rule
437a of the Securities Act of 1933. Because Arthur Andersen LLP has not
consented to the incorporation by reference of their report in this prospectus,
you will not be able to recover against Arthur Andersen LLP under Section 11 of
the Securities Act of 1933 for any untrue statements of a material fact
contained in the financial statements audited by Arthur Andersen LLP or any
omissions to state a material fact required to be stated therein.
145
GLOSSARY
Certain terms used in the text of "Our Business," the 10-K MD&A and the
Notes to the December 31, 2003 Financial Statements, and the 10-Q MD&A and the
Notes to the June 30, 2004 Financial Statements are defined below.
ABATE............................................................... Association of Businesses Advocating Tariff Equity
Accumulated Benefit Obligation...................................... The liabilities of a pension plan based on service and
pay to date. This differs from the Projected
Benefit Obligation that is typically
disclosed in that it does not reflect
expected future salary increases.
AEP................................................................. American Electric Power, a non-affiliated company
AFUDC............................................................... Allowance for Funds Used During Construction
ALJ................................................................. Administrative Law Judge
Alliance RTO........................................................ Alliance Regional Transmission Organization
Alstom.............................................................. Alstom Power Company
AMT................................................................. Alternative minimum tax
APB................................................................. Accounting Principles Board
APB Opinion No. 18.................................................. APB Opinion No. 18, "The Equity Method of Accounting for
Investments in Common Stock"
APB Opinion No. 30.................................................. APB Opinion No. 30, "Reporting Results of Operations--
Reporting the Effects of Disposal of a Segment of a
Business"
APT................................................................. Australian Pipeline Trust
ARO................................................................. Asset retirement obligation
Articles............................................................ Articles of Incorporation
Attorney General.................................................... Michigan Attorney General
bcf................................................................. Billion cubic feet
Big Rock............................................................ Big Rock Point nuclear power plant, owned by Consumers
Board of Directors.................................................. Board of Directors of CMS Energy
Btu................................................................. British thermal unit
Centennial.......................................................... Centennial Pipeline, LLC, in which Panhandle, formerly a
wholly owned subsidiary of CMS Gas Transmission, owned a
one-third interest
CEO................................................................. Chief Executive Officer
CFO................................................................. Chief Financial Officer
CFTC................................................................ Commodity Futures Trading Commission
Clean Air Act....................................................... Federal Clean Air Act, as amended
CMS Electric and Gas................................................ CMS Electric and Gas Company, a subsidiary of
Enterprises
CMS Energy.......................................................... CMS Energy Corporation, the parent of Consumers and
Enterprises
CMS Energy Common Stock or common stock............................. Common stock of CMS Energy, par value $.01 per share
CMS ERM............................................................. CMS Energy Resource Management Company, formerly CMS
MST, a subsidiary of Enterprises
CMS Field Services.................................................. CMS Field Services, formerly a wholly owned subsidiary
of CMS Gas Transmission. The sale of this subsidiary
closed in July 2003.
CMS Gas Transmission................................................ CMS Gas Transmission Company, a subsidiary of
Enterprises
CMS Generation...................................................... CMS Generation Co., a subsidiary of Enterprises
CMS Holdings........................................................ CMS Midland Holdings Company, a subsidiary of Consumers
CMS Land............................................................ CMS Land Company, a subsidiary of Enterprises
CMS Midland......................................................... CMS Midland Inc., a subsidiary of Consumers
CMS MST............................................................. CMS Marketing, Services and Trading Company, a wholly
owned subsidiary of Enterprises, whose name was changed
to CMS ERM effective January 2004
CMS Oil and Gas..................................................... CMS Oil and Gas Company, formerly a subsidiary of
Enterprises
146
CMS PEPS............................................................ CMS Energy Premium Equity Participating
Security Units (CMS Energy Trust III)
CMS Pipeline Assets................................................. CMS Enterprises pipeline assets in Michigan and
Australia
CMS Viron........................................................... CMS Viron Energy Services, formerly a wholly owned
subsidiary of CMS MST. The sale of this subsidiary
closed in June 2003.
Common Stock........................................................ All classes of Common Stock of CMS Energy and each of
its subsidiaries, or any of them individually, at the
time of an award or grant under the Performance
Incentive Stock Plan
Consumers........................................................... Consumers Energy Company, a subsidiary of CMS Energy
Consumers Funding................................................... Consumers Funding LLC, a wholly-owned special purpose
subsidiary of Consumers for the issuance of
securitization bonds dated November 8, 2001
Consumers Receivables Funding II.................................... Consumers Receivables Funding II LLC, a wholly-owned
subsidiary of Consumers
Court of Appeals.................................................... Michigan Court of Appeals
CPEE................................................................ Companhia Paulista de Energia Eletrica, a
subsidiary of Enterprises
Customer Choice Act................................................. Customer Choice and Electricity Reliability Act, a
Michigan statute enacted in June 2000 that allows all
retail customers choice of alternative electric
suppliers as of January 1, 2002, provides for full
recovery of net stranded costs and implementation costs,
establishes a five percent reduction in residential
rates, establishes rate freeze and rate cap, and allows
for Securitization
Detroit Edison...................................................... The Detroit Edison Company, a non-affiliated company
DIG................................................................. Dearborn Industrial Generation, LLC, a wholly owned
subsidiary of CMS Generation
DOE................................................................. U.S. Department of Energy
DOJ................................................................. U.S. Department of Justice
Dow................................................................. The Dow Chemical Company, a non-affiliated company
EBITDA.............................................................. Earnings before income taxes, depreciation, and amortization
EISP................................................................ Executive Incentive Separation Plan
EITF................................................................ Emerging Issues Task Force
EITF Issue No. 02-03................................................ Issues Involved in Accounting for Derivative Contracts
Held for Trading Purposes and Contracts Involved in
Energy Trading and Risk Management Activities
EITF Issue No. 97-04................................................ Deregulation of the Pricing of Electricity-- Issues
Related to the Application of FASB Statements No. 71 and
101
El Chocon........................................................... The 1,200 MW hydro power plant located in Argentina, in
which CMS Generation holds a 17.23 percent ownership
Interest
Enterprises......................................................... CMS Enterprises Company, a subsidiary of CMS Energy
EPA................................................................. U.S. Environmental Protection Agency
EPS................................................................. Earnings per share
ERISA............................................................... Employee Retirement Income Security Act
Ernst & Young....................................................... Ernst & Young LLP
Exchange Act........................................................ Securities Exchange Act of 1934, as amended
FASB................................................................ Financial Accounting Standards Board
FASB Staff Position, No. SFAS 106-1................................. Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003
(January 12, 2004)
FASB Staff Position, No. SFAS 106-2................................. Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003
(May 19, 2004)
FERC................................................................ Federal Energy Regulatory Commission
147
FMB................................................................. First Mortgage Bonds
FMLP................................................................ First Midland Limited Partnership, a partnership that
holds a lessor interest in the MCV facility
Ford................................................................ Ford Motor Company
GasAtacama.......................................................... An integrated natural gas pipeline and
electric generation project located in
Argentina and Chile which includes 702 miles
of natural gas pipeline and a 720 MW gross
capacity power plant
GCR................................................................. Gas cost recovery
GEII................................................................ General Electric International Inc.
Goldfields.......................................................... A pipeline business located in Australia, in
which CMS Energy holds a 39.7 percent
ownership interest
Guardian............................................................ Guardian Pipeline, LLC, in which CMS Gas
Transmission owned a one-third interest
Health Care Plan.................................................... The medical, dental, and prescription drug programs
offered to eligible employees of Consumers and CMS
Energy
HL Power............................................................ H.L. Power Company, a California Limited Partnership,
owner of the Honey Lake generation project in Wendel,
California
Integrum............................................................ Integrum Energy Ventures, LLC
IPP................................................................. Independent Power Production
ITC................................................................. Investment tax credit
JOATT............................................................... Joint Open Access Transmission Tariff
Jorf Lasfar......................................................... The 1,356 MW coal-fueled power plant in Morocco, jointly
owned by CMS Generation and ABB Energy Ventures, Inc.
Karn................................................................ D.E. Karn/J.C. Weadock Generating Complex,
which is owned by Consumers
kWh................................................................. Kilowatt-hour
LIBOR............................................................... London Inter-Bank Offered Rate
Loy Yang............................................................ The 2,000 MW brown coal fueled Loy Yang A power plant
and an associated coal mine in Victoria, Australia, in
which CMS Generation holds a 50 percent ownership
interest
LNG................................................................. Liquefied natural gas
Ludington........................................................... Ludington pumped storage plant, jointly owned
by Consumers and Detroit Edison
MAPL................................................................ Marathon Ashland Petroleum, LLC, partner in Centennial
Marysville.......................................................... CMS Marysville Gas Liquids Company, a Michigan
corporation and a subsidiary of CMS Gas Transmission
that held a 100 percent interest in Marysville
Fractionation Partnership and a 51 percent interest in
St. Clair Underground Storage Partnership
mcf................................................................. Thousand cubic feet
MCV Expansion, LLC.................................................. An agreement entered into with General Electric Company
to expand the MCV Facility
MCV Facility........................................................ A natural gas-fueled, combined-cycle cogeneration
facility operated by the MCV Partnership
MCV Partnership..................................................... Midland Cogeneration Venture Limited Partnership in
which Consumers has a 49 percent interest through CMS
Midland
MD&A................................................................ Management's Discussion and Analysis
METC................................................................ Michigan Electric Transmission Company, formerly a
subsidiary of Consumers Energy and now an indirect
subsidiary of Trans-Elect
Michigan Power...................................................... CMS Generation Michigan Power, LLC, owner of the
Kalamazoo River Generating Station and the Livingston
Generating Station
MISO................................................................ Midwest Independent System Operator
Moody's............................................................. Moody's Investors Service, Inc.
MPSC................................................................ Michigan Public Service Commission
148
MSBT.............................................. Michigan Single Business Tax
MTH............................................... Michigan Transco Holdings, Limited Partnership
MW................................................ Megawatts
NEIL.............................................. Nuclear Electric Insurance Limited, an industry mutual
insurance company owned by member utility companies
NMC............................................... Nuclear Management Company, LLC, formed in 1999 by
Northern States Power Company (now Xcel Energy Inc.),
Alliant Energy, Wisconsin Electric Power Company, and
Wisconsin Public Service Company to operate and manage
nuclear generating facilities owned by the four
Utilities
NERC.............................................. North American Electric Reliability Council
NRC............................................... Nuclear Regulatory Commission
NYMEX............................................. New York Mercantile Exchange
OATT.............................................. Open Access Transmission Tariff
OPEB.............................................. Postretirement benefit plans other than pensions for retired Employees
Palisades......................................... Palisades nuclear power plant, which is owned by Consumers
Panhandle Eastern Pipe Line or Panhandle.......... Panhandle Eastern Pipe Line Company, including its subsidiaries
Trunkline, Pan Gas Storage, Panhandle Storage, and Panhandle
Holdings. Panhandle was a wholly owned subsidiary of CMS Gas
Transmission. The sale of this subsidiary closed in June 2003.
Parmelia.......................................... A business located in Australia comprised of a pipeline, processing
facilities, and a gas storage facility, a subsidiary of CMS Gas
Transmission
PCB............................................... Polychlorinated biphenyl
Pension Plan...................................... The trusteed, non-contributory, defined benefit pension plan of
Panhandle, Consumers and CMS Energy
PJM RTO........................................... Pennsylvania-Jersey-Maryland Regional Transmission Organization
Powder River...................................... CMS Oil & Gas previously owned a significant interest in coalbed
methane fields or projects developed within the Powder
River Basin Which spans the border between Wyoming and Montana.
The Powder River properties have been sold.
PPA............................................... The Power Purchase Agreement between Consumers and the MCV Partnership
with a 35-year term commencing in March 1990
Price Anderson Act................................ Price Anderson Act, enacted in 1957 as an amendment to the Atomic
Energy Act of 1954, as revised and extended over the years. This act
stipulates between nuclear licensees and the U.S. government the
insurance, financial responsibility, and legal liability for
nuclear accidents.
PSCR.............................................. Power supply cost recovery
PUHCA............................................. Public Utility Holding Company Act of 1935
PURPA............................................. Public Utility Regulatory Policies Act of 1978
RCP............................................... Resource Conservation Plan
ROA............................................... Retail Open Access
RTO............................................... Regional Transmission Organization
Rouge............................................. Rouge Steel Industries
SCP............................................... Southern Cross Pipeline in Australia, in which CMS Gas
Transmission holds a 45 percent ownership interest
SEC............................................... U.S. Securities and Exchange Commission
Securitization.................................... A financing method authorized by statute and approved by the
MPSC which allows a utility to sell its right to receive a portion
of the rate payments received from its customers for the repayment
of Securitization bonds issued by a special purpose entity affiliated
with such utility
SENECA............................................ Sistema Electrico del Estado Nueva Esparta, C.A., a subsidiary of
Enterprises
SERP.............................................. Supplemental Executive Retirement Plan
SFAS.............................................. Statement of Financial Accounting Standards
149
SFAS No. 5........................................ SFAS No. 5, "Accounting for Contingencies"
SFAS No. 52....................................... SFAS No. 52, "Foreign Currency Translation"
SFAS No. 71....................................... SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS No. 87....................................... SFAS No. 87, "Employers' Accounting for Pensions"
SFAS No. 88....................................... SFAS No. 88, "Employers' Accounting for Settlements and Curtailments
of Defined Benefit Pension Plans and for Termination Benefits"
SFAS No. 98....................................... SFAS No. 98, "Accounting for Leases"
SFAS No. 106...................................... SFAS No. 106, "Employers' Accounting for Postretirement Benefits
Other Than Pensions"
SFAS No. 107...................................... Disclosures about Fair Value of Financial Instruments
SFAS No. 109...................................... SFAS No. 109, "Accounting for Income Taxes"
SFAS No. 115...................................... SFAS No. 115, "Accounting for Certain Investments in Debt and
Equity Securities"
SFAS No. 123...................................... SFAS No. 123, "Accounting for Stock-Based Compensation"
SFAS No. 128...................................... SFAS No. 128, "Earnings per Share"
SFAS No. 133...................................... SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities, as amended and interpreted"
SFAS No. 143...................................... SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS No. 144...................................... SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets"
SFAS No. 148...................................... SFAS No. 148, "Accounting for Stock-Based Compensation--
Transition and Disclosure"
SFAS No. 149...................................... SFAS No. 149, "Amendment of Statement No. 133 on Derivative
Instruments and Hedging Activities"
SFAS No. 150...................................... SFAS No. 150, "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
Southern Union.................................... Southern Union Company, a non-affiliated company
Special Committee................................. A special committee of independent directors, established by CMS
Energy's Board of Directors, to investigate matters surrounding
Round-trip trading
Stranded Costs.................................... Costs incurred by utilities in order to serve their customers in a
regulated monopoly environment, which may not be recoverable in a
competitive environment because of customers leaving their systems
and ceasing to pay for their costs. These costs could include owned
and purchased generation and regulatory assets.
Superfund......................................... Comprehensive Environmental Response, Compensation and Liability Act
Taweelah.......................................... Al Taweelah A2, a power and desalination plant of Emirates CMS Power
Company, in which CMS Generation holds a forty percent interest
TEPPCO............................................ Texas Eastern Products Pipeline Company, LLC
Toledo Power...................................... Toledo Power Company, the 135 MW coal and fuel oil power plant
located on Cebu Island, Phillipines, in which CMS Generation
held a 47.5 percent interest.
Transition Costs.................................. Stranded Costs, as defined, plus the costs incurred in the transition
to competition
Trunkline......................................... Trunkline Gas Company, LLC, formerly a subsidiary of CMS Panhandle
Holdings, LLC
Trunkline LNG..................................... Trunkline LNG Company, LLC, formerly a subsidiary of LNG Holdings,
LLC
Trust Preferred Securities........................ Securities representing an undivided beneficial interest in the
Assets of statutory business trusts, the interests of which have a
preference with respect to certain trust distributions over the
interests of either CMS Energy or Consumers, as applicable, as owner
of the common beneficial interests of the trusts
Union............................................. Utility Workers of America, AFL-CIO
VEBA Trusts....................................... VEBA (voluntary employees' beneficiary association) Trusts accounts
established to specifically set aside employer contributed assets to
pay for future expenses of the OPEB plan
150
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2004 FINANCIAL STATEMENTS
Consolidated Statements of Income....................................................................... F-2
Consolidated Statements of Cash Flows................................................................... F-4
Consolidated Balance Sheets............................................................................. F-5
Consolidated Statements of Common Stockholder's Equity.................................................. F-7
Notes to Consolidated Financial Statements.............................................................. F-8
DECEMBER 31, 2003 FINANCIAL STATEMENTS
Selected Financial Information.......................................................................... F-51
Consolidated Statements of Income (Loss)................................................................ F-53
Consolidated Statements of Cash Flows................................................................... F-55
Consolidated Balance Sheets............................................................................. F-57
Consolidated Statements of Common Stockholder's Equity.................................................. F-59
Notes to Consolidated Financial Statements.............................................................. F-61
Reports of Independent Registered Public Accounting Firm................................................ F-127
Quarterly Financial Information (Found in Note 19 of Notes to Consolidated
Financial Statements)
JORF LASFAR ENERGY COMPANY DECEMBER 31, 2003 FINANCIAL STATEMENTS
Report of Independent Auditors.......................................................................... F-131
Balance Sheets.......................................................................................... F-134
Statement of Income..................................................................................... F-135
Statement of Stockholders' Equity....................................................................... F-136
Statement of Cash Flows................................................................................. F-137
Notes to U.S. GAAP Financial Statements................................................................. F-138
MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP DECEMBER 31, 2003 FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP.................... F-160
Report of Independent Public Accountants - Arthur Andersen, LLP......................................... F-161
Consolidated Balance Sheets............................................................................. F-162
Consolidated Statements of Operations................................................................... F-163
Consolidated Statements of Partners' Equity............................................................. F-164
Consolidated Statements of Cash Flows................................................................... F-165
Notes to Consolidated Financial Statements.............................................................. F-166
EMIRATES CMS POWER COMPANY DECEMBER 31, 2003 FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm................................................. F-183
Balance Sheets.......................................................................................... F-184
Income Statements....................................................................................... F-185
Statements of Cash Flow................................................................................. F-186
Statements of Stockholders' Equity...................................................................... F-187
Notes to the Financial Statements....................................................................... F-188
Pursuant to Regulation S-X, Rule 3-09, the financial statements for the fiscal
years ended June 30, 2002, 2003 and 2004 for SCP Investments (1) PTY. LTD. which
is a foreign business will be filed by CMS Energy by December 31, 2004.
F-1
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
RESTATED RESTATED
JUNE 30 2004 2003 2004 2003
------- ------- ------- ------- -------
In Millions,
Except Per Share Amounts
OPERATING REVENUE $ 1,093 $ 1,126 $ 2,847 $ 3,094
EARNINGS FROM EQUITY METHOD INVESTEES 41 50 60 97
OPERATING EXPENSES
Fuel for electric generation 184 98 356 206
Purchased and interchange power 80 102 157 341
Purchased power - related parties - 124 - 260
Cost of gas sold 263 298 1,024 1,135
Other operating expenses 224 217 442 415
Maintenance 65 61 122 119
Depreciation, depletion and amortization 108 90 252 218
General taxes 62 7 136 76
Assets impairment charges - 3 125 9
------- ------- ------- -------
986 1,000 2,614 2,779
------- ------- ------- -------
OPERATING INCOME 148 176 293 412
OTHER INCOME (DEDUCTIONS)
Accretion expense (6) (9) (12) (16)
Gain (loss) on asset sales, net 1 (3) 3 (8)
Interest and dividends 7 7 14 11
Foreign currency gains (losses), net (3) 5 (6) 11
Other income 15 3 27 6
Other expense (2) (1) (4) (3)
------- ------- ------- -------
12 2 22 1
------- ------- ------- -------
FIXED CHARGES
Interest on long-term debt 126 128 256 225
Interest on long-term debt - related parties 14 - 29 -
Other interest 7 11 12 18
Capitalized interest (1) (3) (3) (5)
Preferred dividends of subsidiaries 1 1 2 1
Preferred securities distributions - 18 - 36
------- ------- ------- -------
147 155 296 275
------- ------- ------- -------
INCOME BEFORE INCOME TAXES AND MINORITY INTERESTS 13 23 19 138
INCOME TAX EXPENSE (BENEFIT) (7) 34 (10) 73
MINORITY INTERESTS 1 1 12 2
------- ------- ------- -------
INCOME (LOSS) FROM CONTINUING OPERATIONS
19 (12) 17 63
LOSS FROM DISCONTINUED OPERATIONS, NET OF $- AND $1
TAX BENEFIT IN 2004 AND $3 AND $21 TAX EXPENSE IN 2003 - (53) (2) (22)
------- ------- ------- -------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING 19 (65) 15 41
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF $13
TAX BENEFIT IN 2003:
DERIVATIVES (NOTE 6) - - - (23)
ASSET RETIREMENT OBLIGATIONS, SFAS NO. 143 (NOTE 10) - - - (1)
------- ------- ------- -------
- - - (24)
------- ------- ------- -------
NET INCOME (LOSS) 19 (65) 15 17
PREFERRED DIVIDENDS 3 - 6 -
------- ------- ------- -------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCK $ 16 $ (65) $ 9 $ 17
======= ======= ======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
F-2
THREE MONTHS ENDED SIX MONTHS ENDED
RESTATED RESTATED
JUNE 30 2004 2003 2004 2003
------- ------- ------- ------- -------
In Millions,
Except Per Share Amounts
CMS ENERGY
NET INCOME (LOSS)
Net Income (Loss) Available to Common Stock $ 16 $ (65) $ 9 $ 17
======= ======= ======= =======
BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (Loss) from Continuing Operations $ 0.10 $ (0.08) $ 0.07 $ 0.43
Income (Loss) from Discontinued Operations - (0.37) (0.01) (0.15)
Loss from Changes in Accounting - - - (0.16)
------- ------- ------- -------
Net Income (Loss) Attributable to Common Stock $ 0.10 $ (0.45) $ 0.06 $ 0.12
======= ======= ======= =======
DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (Loss) from Continuing Operations $ 0.10 $ (0.08) $ 0.07 $ 0.43
Income (Loss) from Discontinued Operations - (0.37) (0.01) (0.14)
Loss from Changes in Accounting - - - (0.15)
------- ------- ------- -------
Net Income (Loss) Attributable to Common Stock $ 0.10 $ (0.45) $ 0.06 $ 0.14
======= ======= ======= =======
DIVIDENDS DECLARED PER COMMON SHARE $ - $ - $ - $ -
------- ------- ------- -------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
F-3
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
SIX MONTHS ENDED
RESTATED
JUNE 30 2004 2003
------- ------- -------
In Millions
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 15 $ 17
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization (includes nuclear
decommissioning of $3 and $3, respectively) 252 218
Loss on disposal of discontinued operations 1 49
Asset impairments (Note 2) 125 9
Capital lease and debt discount amortization 14 12
Accretion expense 12 16
Bad debt expense 5 8
Undistributed earnings from related parties (44) (69)
Loss (gain) on the sale of assets (3) 8
Cumulative effect of accounting changes - 24
Changes in other assets and liabilities:
Increase in accounts receivable and accrued revenues (112) (69)
Decrease (increase) in inventories 81 (2)
Increase (decrease) in accounts payable and accrued expenses 66 (298)
Deferred income taxes and investment tax credit 44 169
Decrease in other assets 16 91
Increase (decrease) in other liabilities 9 (36)
------- -------
Net cash provided by operating activities $ 481 $ 147
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease) $ (237) $ (261)
Cost to retire property (37) (35)
Restricted cash (12) (167)
Investment in Electric Restructuring Implementation Plan (3) (4)
Investments in nuclear decommissioning trust funds (3) (3)
Proceeds from nuclear decommissioning trust funds 23 18
Maturity of MCV restricted investment securities held-to-maturity 300 -
Purchase of MCV restricted investment securities held-to-maturity (300) -
Proceeds from sale of assets 66 726
Other investing (11) 18
------- -------
Net cash provided by (used in) investing activities $ (214) $ 292
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from notes, bonds, and other long-term debt $ 9 $ 1,449
Retirement of bonds and other long-term debt (274) (830)
Payment of preferred stock dividends (6) -
Decrease in notes payable - (487)
Payment of capital lease obligations (5) (7)
------- -------
Net cash provided by (used in) financing activities $ (276) $ 125
------- -------
EFFECT OF EXCHANGE RATES ON CASH (1) 2
------- -------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $ (10) $ 566
CASH AND CASH EQUIVALENTS FROM EFFECT OF REVISED FASB
INTERPRETATION NO. 46 CONSOLIDATION 174 -
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 532 351
------- -------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 696 $ 917
======= =======
OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE:
CASH TRANSACTIONS
Interest paid (net of amounts capitalized) $ 246 $ 233
Income taxes paid (net of refunds) - (33)
OPEB cash contribution 33 40
NON-CASH TRANSACTIONS
Other assets placed under capital leases $ 1 $ 10
======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
F-4
CMS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
JUNE 30
JUNE 30 2003
2004 DECEMBER 31 RESTATED
(UNAUDITED) 2003 (UNAUDITED)
----------- ----------- -----------
In Millions
PLANT AND PROPERTY (AT COST)
Electric utility $ 7,776 $ 7,600 $ 7,465
Gas utility 2,898 2,875 2,805
Enterprises 3,392 895 706
Other 28 32 37
----------- ----------- -----------
14,094 11,402 11,013
Less accumulated depreciation, depletion and amortization 5,958 4,846 4,777
----------- ----------- -----------
8,136 6,556 6,236
Construction work-in-progress 392 388 438
----------- ----------- -----------
8,528 6,944 6,674
----------- ----------- -----------
INVESTMENTS
Enterprises 754 724 740
Midland Cogeneration Venture Limited Partnership - 419 422
First Midland Limited Partnership - 224 263
Other 24 23 2
----------- ----------- -----------
778 1,390 1,427
----------- ----------- -----------
CURRENT ASSETS
Cash and cash equivalents at cost, which approximates market 696 532 917
Restricted cash 213 201 205
Accounts receivable, notes receivable and accrued revenue, less allowances of
$28, $29 and $17, respectively 531 367 473
Accounts receivable - Energy Resource Management, less allowances of $10,
$11and $9, respectively 36 36 145
Accounts receivable and notes receivable - related parties 60 73 182
Inventories at average cost:
Gas in underground storage 665 741 460
Materials and supplies 107 110 102
Generating plant fuel stock 60 41 42
Assets held for sale 14 24 79
Price risk management assets 99 102 101
Regulatory assets 19 19 19
Derivative instruments 114 2 2
Prepayments and other 238 246 308
----------- ----------- -----------
2,852 2,494 3,035
----------- ----------- -----------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs 627 648 669
Postretirement benefits 151 162 174
Abandoned Midland Project 10 10 11
Other 318 266 255
Assets held for sale - 2 213
Price risk management assets 192 177 213
Nuclear decommissioning trust funds 559 575 553
Prepaid pension costs 378 388 -
Goodwill 23 25 36
Notes receivable - related parties 231 242 147
Notes receivable 125 125 126
Other 535 390 406
----------- ----------- -----------
3,149 3,010 2,803
----------- ----------- -----------
TOTAL ASSETS $ 15,307 $ 13,838 $ 13,939
=========== =========== ===========
F-5
STOCKHOLDERS' INVESTMENT AND LIABILITIES
JUNE 30
JUNE 30 2003
2004 DECEMBER 31 RESTATED
(UNAUDITED) 2003 (UNAUDITED)
----------- ----------- -----------
In Millions
CAPITALIZATION
Common stockholders' equity
Common stock, authorized 350.0 shares; outstanding 161.3 shares,
161.1 shares and 144.1 shares, respectively $ 2 $ 2 $ 1
Other paid-in-capital 3,848 3,846 3,608
Accumulated other comprehensive loss (313) (419) (690)
Retained deficit (1,835) (1,844) (1,783)
----------- ----------- -----------
1,702 1,585 1,136
Preferred stock of subsidiary 44 44 44
Preferred stock 261 261 -
Company-obligated convertible Trust Preferred Securities
of subsidiaries - - 393
Company-obligated mandatorily redeemable Trust Preferred Securities
of Consumers' subsidiaries - - 490
Long-term debt 5,816 6,020 6,062
Long-term debt - related parties 684 684 -
Non-current portion of capital and finance lease obligations 338 58 119
----------- ----------- -----------
8,845 8,652 8,244
----------- ----------- -----------
MINORITY INTERESTS 740 73 43
----------- ----------- -----------
CURRENT LIABILITIES
Current portion of long-term debt, capital and finance leases 903 519 544
Accounts payable 358 296 334
Accounts payable - Energy Resource Management 21 21 52
Accounts payable - related parties 2 40 47
Accrued interest 170 130 126
Accrued taxes 239 285 180
Liabilities held for sale 2 2 66
Price risk management liabilities 93 89 93
Current portion of purchase power contracts 13 27 26
Current portion of gas supply contract obligations 30 29 28
Deferred income taxes 29 27 32
Other 301 185 185
----------- ----------- -----------
2,161 1,650 1,713
----------- ----------- -----------
NON-CURRENT LIABILITIES
Regulatory Liabilities
Cost of removal 1,016 983 950
Income taxes, net 321 312 313
Other 165 172 155
Postretirement benefits 252 265 791
Deferred income taxes 651 615 487
Deferred investment tax credit 82 85 87
Asset retirement obligation 407 359 364
Liabilities held for sale - - 45
Price risk management liabilities 188 175 206
Gas supply contract obligations 190 208 221
Power purchase agreement - MCV Partnership - - 14
Other 289 289 306
----------- ----------- -----------
3,561 3,463 3,939
----------- ----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 1, 3 and 4)
TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $ 15,307 $ 13,838 $ 13,939
=========== =========== ===========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
F-6
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
RESTATED RESTATED
JUNE 30 2004 2003 2004 2003
------- ------- ------- ------- -------
In Millions
COMMON STOCK
At beginning and end of period $ 2 $ 1 $ 2 $ 1
------- ------- ------- -------
OTHER PAID-IN CAPITAL
At beginning of period 3,846 3,605 3,846 3,605
Common stock reacquired (1) (1) (1) (1)
Common stock issued 3 4 3 4
------- ------- ------- -------
At end of period 3,848 3,608 3,848 3,608
------- ------- ------- -------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Minimum Pension Liability
At beginning of period - (241) - (241)
Minimum pension liability adjustments (a) - (20) - (20)
------- ------- ------- -------
At end of period - (261) - (261)
------- ------- ------- -------
Investments
At beginning of period 9 2 8 2
Unrealized gain (loss) on investments (a) (1) 3 - 3
------- ------- ------- -------
At end of period 8 5 8 5
------- ------- ------- -------
Derivative Instruments
At beginning of period (13) (29) (8) (31)
Unrealized gain (loss) on derivative instruments (a) 22 (14) 19 (7)
Reclassification adjustments included in consolidated net income
(loss) (a) (3) 21 (5) 16
------- ------- ------- -------
At end of period 6 (22) 6 (22)
------- ------- ------- -------
Foreign Currency Translation
At beginning of period (313) (445) (419) (458)
Change in foreign currency translation (a) (14) 33 92 46
------- ------- ------- -------
At end of period (327) (412) (327) (412)
------- ------- ------- -------
At end of period (313) (690) (313) (690)
------- ------- ------- -------
RETAINED DEFICIT
At beginning of period (1,851) (1,718) (1,844) (1,800)
Net income (loss) (a) 19 (65) 15 17
Preferred stock dividends declared (3) - (6) -
Common stock dividends declared - - - -
------- ------- ------- -------
At end of period (1,835) (1,783) (1,835) (1,783)
------- ------- ------- -------
TOTAL COMMON STOCKHOLDERS' EQUITY $ 1,702 $ 1,136 $ 1,702 $ 1,136
======= ======= ======= =======
(a) DISCLOSURE OF OTHER COMPREHENSIVE INCOME (LOSS):
Minimum Pension Liability
Minimum pension liability adjustments, net of tax benefit of
$-, $(10), $- and $(10), respectively $ - $ (20) $ - $ (20)
Investments
Unrealized gain (loss) on investments, net of tax of $-, $1,
$- and $1, respectively (1) 3 - 3
Derivative Instruments
Unrealized loss on derivative instruments, net of tax (tax benefit)
of $2, $(3), $7 and $2, respectively 22 (14) 19 (7)
Reclassification adjustments included in net income (loss),
net of tax (tax benefit) of $(2), $14, $(3) and $11, respectively (3) 21 (5) 16
Foreign currency translation, net (14) 33 92 46
Net income (loss) 19 (65) 15 17
------- ------- ------- -------
Total Other Comprehensive Income (Loss) $ 23 $ (42) $ 121 $ 55
======= ======= ======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
F-7
CMS ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
These interim Consolidated Financial Statements have been prepared by CMS
Energy in accordance with accounting principles generally accepted in the United
States for interim financial information and with the instructions to Form 10-Q
and Article 10 of Regulation S-X. As such, certain information and footnote
disclosures normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States have been
condensed or omitted. Certain prior year amounts have been reclassified to
conform to the presentation in the current year. In management's opinion, the
unaudited information contained in this report reflects all adjustments of a
normal recurring nature necessary to assure the fair presentation of financial
position, results of operations and cash flows for the periods presented. The
Condensed Notes to Consolidated Financial Statements and the related
Consolidated Financial Statements should be read in conjunction with the
Consolidated Financial Statements and Notes to Consolidated Financial Statements
contained in CMS Energy's Form 10-K/A for the year ended December 31, 2003. Due
to the seasonal nature of CMS Energy's operations, the results as presented for
this interim period are not necessarily indicative of results to be achieved for
the fiscal year.
RESTATEMENT OF 2003 FINANCIAL STATEMENTS
Our financial statements as of and for the three and six months ended June
30, 2003, as presented in this Form 10-Q, have been restated for the following
matters that were disclosed previously in Note 19, Quarterly Financial and
Common Stock Information (Unaudited), in our 2003 Form 10-K/A:
- International Energy Distribution, which includes SENECA and CPEE,
is no longer considered "discontinued operations," due to a change
in our expectations as to the timing of the sales,
- certain derivative accounting corrections at our equity affiliates,
and
- the net loss recorded in the second quarter of 2003 relating to the
sale of Panhandle, reflected as Discontinued Operations, was
understated by approximately $14 million, net of tax.
1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES
CORPORATE STRUCTURE: CMS Energy is an integrated energy company with a
business strategy focused primarily in Michigan. We are the parent holding
company of Consumers and Enterprises. Consumers is a combination electric and
gas utility company serving Michigan's Lower Peninsula. Enterprises, through
various subsidiaries and equity investments, is engaged in domestic and
international diversified energy businesses including: independent power
production and natural gas transmission, storage and processing. We manage our
businesses by the nature of services each provides and operate principally in
three business segments: electric utility, gas utility, and enterprises.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include
the accounts of CMS Energy, Consumers, Enterprises, and all other entities in
which we have a controlling financial interest or are the primary beneficiary,
in accordance with Revised FASB Interpretation No. 46. The primary beneficiary
of a variable interest entity is the party that absorbs or receives a majority
of the entity's expected losses or expected residual returns or both as a result
of holding variable interests, which are ownership, contractual, or other
economic interests. In 2004, we consolidated the MCV Partnership and the FMLP in
accordance with Revised FASB Interpretation No. 46. For additional details, see
Note 11, Implementation of New Accounting Standards. We use the equity method of
accounting for investments in companies and partnerships that are not
consolidated, where we have significant influence over operations and financial
policies, but are not the primary beneficiary. Intercompany transactions and
balances have been eliminated.
USE OF ESTIMATES: We prepare our financial statements in conformity with
accounting principles generally accepted in the United States. We are required
to make estimates using assumptions that may affect the reported amounts and
disclosures. Actual results could differ from those estimates.
F-8
We are required to record estimated liabilities in the financial
statements when it is probable that a loss will be incurred in the future as a
result of a current event, and when an amount can be reasonably estimated. We
have used this accounting principle to record estimated liabilities as discussed
in Note 3, Uncertainties.
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of
electricity and natural gas, and the transportation, processing, and storage of
natural gas when services are provided. Sales taxes are recorded as liabilities
and are not included in revenues. Revenues on sales of marketed electricity,
natural gas, and other energy products are recognized at delivery.
Mark-to-market changes in the fair values of energy trading contracts that
qualify as derivatives are recognized as revenues in the periods in which the
changes occur.
CAPITALIZED INTEREST: We are required to capitalize interest on certain
qualifying assets that are undergoing activities to prepare them for their
intended use. Capitalization of interest for the period is limited to the actual
interest cost that is incurred, and our non-regulated businesses are prohibited
from imputing interest costs on any equity funds. Our regulated businesses are
permitted to capitalize an allowance for funds used during construction on
regulated construction projects and to include such amounts in plant in service.
CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with
an original maturity of three months or less are considered cash equivalents. At
June 30, 2004, our restricted cash on hand was $213 million. Restricted cash
primarily includes cash collateral for letters of credit to satisfy certain debt
agreements and cash dedicated for repayment of Securitization bonds. It is
classified as a current asset as the related letters of credit mature within one
year and the payments on the related Securitization bonds occur within one year.
EARNINGS PER SHARE: Basic and diluted earnings per share are based on the
weighted average number of shares of common stock and dilutive potential common
stock outstanding during the period. Potential common stock, for purposes of
determining diluted earnings per share, includes the effects of dilutive stock
options, warrants and convertible securities. The effect on number of shares of
such potential common stock is computed using the treasury stock method or the
if-converted method, as applicable. For earnings per share computation, see Note
5, Earnings Per Share and Dividends.
FINANCIAL INSTRUMENTS: We account for investments in debt and equity
securities using SFAS No. 115. Debt and equity securities can be classified into
one of three categories: held-to-maturity, trading, or available-for-sale. Our
debt securities are classified as held-to-maturity securities and are reported
at cost. Our investments in equity securities are classified as
available-for-sale securities. They are reported at fair value, with any
unrealized gains or losses resulting from changes in fair value reported in
equity as part of accumulated other comprehensive income and are excluded from
earnings unless such changes in fair value are determined to be other than
temporary. Unrealized gains or losses resulting from changes in the fair value
of our nuclear decommissioning investments are reflected in Regulatory
Liabilities. The fair value of our equity securities is determined from quoted
market prices. For additional details regarding financial instruments, see Note
6, Financial and Derivative Instruments.
FOREIGN CURRENCY TRANSLATION: Our subsidiaries and affiliates whose
functional currency is not the U.S. dollar translate their assets and
liabilities into U.S. dollars at the exchange rates in effect at the end of the
fiscal period. We translate revenue and expense accounts of such subsidiaries
and affiliates into U.S. dollars at the average exchange rates that prevailed
during the period. The gains or losses that result from this process, and gains
and losses on intercompany foreign currency transactions that are long-term in
nature that we do not intend to settle in the foreseeable future, are shown in
the stockholders' equity section in the Consolidated Balance Sheets. For
subsidiaries operating in highly inflationary economies, the U.S. dollar is
considered to be the functional currency, and transaction gains and losses are
included in determining net income. Gains and losses that arise from exchange
rate fluctuations on transactions denominated in a currency other than the
functional currency, except those that are hedged, are included in determining
net income.
IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: We evaluate potential
impairments of our investments in long-lived assets other than goodwill based on
various analyses, including the projection of undiscounted cash flows, whenever
events or changes in circumstances indicate that the carrying amount of the
assets may not be recoverable. If the carrying amount of the asset exceeds its
estimated undiscounted future cash flows, an impairment loss is recognized and
the asset is written down to its estimated fair value.
F-9
NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on
the quantity of heat produced for electric generation. For nuclear fuel used
after April 6, 1983, we charge disposal costs to nuclear fuel expense, recover
these costs through electric rates, and remit them to the DOE quarterly. We
elected to defer payment for disposal of spent nuclear fuel burned before April
7, 1983. As of June 30, 2004, we have recorded a liability to the DOE for $140
million, including interest, which is payable upon the first delivery of spent
nuclear fuel to the DOE. The amount of this liability, excluding a portion of
interest, was recovered through electric rates. For additional details on
disposal of spent nuclear fuel, see Note 3, Uncertainties, "Other Consumers'
Electric Utility Uncertainties - Nuclear Matters."
OTHER INCOME AND OTHER EXPENSE: The following tables show the components
of Other income and Other expense:
IN MILLIONS
--------------------------------------
THREE MONTHS ENDED SIX MONTHS ENDED
------------------ ----------------
JUNE 30 2004 2003 2004 2003
------- ------ ------ ------ ------
Other income
Interest and dividends - related parties $ 1 $ 1 $ 2 $ 2
PA141 Return on capital expenditures 9 - 18 -
Electric restructuring return 1 2 3 3
Investment sale gain 1 - 1 -
All other 3 - 3 1
------ ------ ------ ------
Total other income $ 15 $ 3 $ 27 $ 6
====== ====== ====== ======
IN MILLIONS
--------------------------------------
THREE MONTHS ENDED SIX MONTHS ENDED
------------------ ----------------
JUNE 30 2004 2003 2004 2003
------- ------ ------ ------ ------
Other expense
Loss on SERP investment $ (1) $ - $ (1) $ (1)
Civic and political expenditures - - (1) (1)
All other (1) (1) (2) (1)
------ ------ ------ ------
Total other expense $ (2) $ (1) $ (4) $ (3)
====== ====== ====== ======
PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment
at original cost when placed into service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, the original cost is
charged to accumulated depreciation and cost of removal, less salvage is
recorded as a regulatory liability. For additional details, see Note 10, Asset
Retirement Obligations. An allowance for funds used during construction is
capitalized on regulated construction projects. With respect to the retirement
or disposal of non-regulated assets, the resulting gains or losses are
recognized in income.
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the years presented.
UTILITY REGULATION: We account for the effects of regulation based on the
regulated utility accounting standard SFAS No. 71. As a result, the actions of
regulators affect when we recognize revenues, expenses, assets, and liabilities.
SFAS No. 144 imposes strict criteria for retention of regulatory-created
assets by requiring that such assets be probable of future recovery at each
balance sheet date. Management believes these assets are probable of future
recovery.
2: DISCONTINUED OPERATIONS, OTHER ASSET SALES, IMPAIRMENTS, AND RESTRUCTURING
Our continued focus on financial improvement has led to discontinuing
operations, completing many asset sales, impairing some assets, and incurring
costs to restructure our business. Gross cash proceeds received from the sale
F-10
of assets totaled $66 million for the six months ended June 30, 2004 and $726
million for the six months ended June 30, 2003.
DISCONTINUED OPERATIONS
We have discontinued the following operations:
IN MILLIONS
--------------------------------------------------------------------------------------
PRETAX AFTER-TAX
BUSINESS/PROJECT DISCONTINUED GAIN(LOSS) GAIN(LOSS) STATUS
------------------ ------------- ---------- ----------- ------------------
CMS Viron June 2002 $ (14) $ (9) Sold June 2003
Panhandle December 2002 (39) (44) Sold June 2003
CMS Field Services December 2002 (5) (1) Sold July 2003
Marysville June 2003 2 1 Sold November 2003
Parmelia (a) December 2003 - - Held for sale
================== ============= ========== =========== ==================
(a) We expect the sale of Parmelia to occur in 2004. In December 2003, we
reduced the carrying amount of our Parmelia business by $26 million to
reflect fair value. This after-tax loss was reported in discontinued
operations in December 2003.
At June 30, 2004, "Assets held for sale" includes Parmelia. At December
31, 2003, "Assets held for sale" includes Parmelia, Bluewater Pipeline, and our
investment in the American Gas Index Fund. At June 30, 2003, "Assets held for
sale" includes CMS Field Services, Marysville, and Parmelia. The major classes
of assets and liabilities held for sale on our Consolidated Balance Sheet are as
follows:
IN MILLIONS
-----------------------------------------------------------------------------------------------
RESTATED
JUNE 30, 2004 DECEMBER 31, 2003 JUNE 30, 2003
------------- ----------------- -------------
Assets
Cash $ 8 $ 7 $ 2
Accounts receivable 3 2 71
Property, plant and equipment - net - 2 197
Other 3 15 22
--- --- -----
Total assets held for sale $14 $26 $ 292
=== === =====
Liabilities
Accounts payable $ 1 $ 2 $ 61
Minority interest - - 44
Other 1 - 6
--- --- -----
Total liabilities held for sale $ 2 $ 2 $ 111
=== === =====
F-11
The following amounts are reflected in the Consolidated Statements of
Income, in the Loss From Discontinued Operations line:
IN MILLIONS
------------------------------------------------------------------------------
RESTATED
THREE MONTHS ENDED JUNE 30 2004 2003
-------------------------------------------------- ------ --------
Revenues $ 5 $ 250
====== ========
Discontinued operations:
Pretax income from discontinued operations $ - $ 6
Income tax expense - 4
------ --------
Income from discontinued operations - 2
Pretax loss on disposal of discontinued operations - (56)
Income tax benefit - (1)
------ --------
Loss on disposal of discontinued operations - (55)
------ --------
Loss from discontinued operations $ - $ (53)
====== ========
IN MILLIONS
------------------------------------------------------------------------------
RESTATED
SIX MONTHS ENDED JUNE 30 2004 2003
-------------------------------------------------- ------ --------
Revenues $ 10 $ 496
====== ========
Discontinued operations:
Pretax income (loss) from discontinued operations $ (1) $ 46
Income tax expense - 19
------ --------
Income (loss) from discontinued operations (1) 27
Pretax loss on disposal of discontinued operations (2) (47)
Income tax expense (benefit) (1) 2
------ --------
Loss on disposal of discontinued operations (1) (49)
------ --------
Loss from discontinued operations $ (2) $ (22)
====== ========
The loss from discontinued operations includes a reduction in asset
values, a provision for anticipated closing costs, and a portion of CMS Energy's
interest expense. Interest expense of less than $1 million for the six months
ended June 30, 2004 and $21 million for the six months ended June 30, 2003 has
been allocated based on a ratio of the expected proceeds for the asset to be
sold divided by CMS Energy's total capitalization of each discontinued operation
times CMS Energy's interest expense.
OTHER ASSET SALES
Our other asset sales include the following non-strategic and
under-performing assets. The impacts of these sales are included in "Gain (loss)
on asset sales, net" in the Consolidated Statements of Income (Loss).
F-12
For the six months ended June 30, 2004, we sold the following assets that
did not meet the definition of, and therefore were not reported as, discontinued
operations:
IN MILLIONS
---------------------------------------------------------------------
PRETAX AFTER-TAX
DATE SOLD BUSINESS/PROJECT GAIN GAIN
---------------------------------------------------------------------
February Bluewater Pipeline (a) $ 1 $ 1
April Loy Yang (b) - -
May American Gas Index fund (c) 1 1
Various Other 1 -
---------------------------------------------------------------------
Total gain on asset sales $ 3 $ 2
=====================================================================
(a) Bluewater Pipeline is a 24.9 mile pipeline that extends from Marysville,
Michigan to Armada, Michigan.
(b) In April 2004, we and our partners sold the 2,000 MW Loy Yang power plant
and adjacent coal mine in Victoria, Australia for about A$3.5 billion
($2.6 billion in U.S. dollars), including A$145 million for the project
equity. Our share of the proceeds, net of transaction costs and closing
adjustments, was $44 million. In anticipation of the sale, we recorded an
impairment in the first quarter as discussed in "Asset Impairments" within
this Note.
(c) In May 2004, we sold our interest in the American Gas Index fund for $7
million.
For the six months ended June 30, 2003, we sold the following assets that
did not meet the definition of, and therefore were not reported as, discontinued
operations:
IN MILLIONS
---------------------------------------------------------------------
PRETAX AFTER-TAX
DATE SOLD BUSINESS/PROJECT GAIN(LOSS) GAIN(LOSS)
---------------------------------------------------------------------
January CMS MST Wholesale Gas $ (6) $ (4)
March CMS MST Wholesale Power 2 1
June Guardian Pipeline (4) (3)
---------------------------------------------------------------------
Total loss on asset sales $ (8) $ (6)
=====================================================================
SUBSEQUENT EVENT: In July 2004, we entered into a definitive agreement to
sell our interests in Parmelia and Goldfields to APT for approximately $208
million Australian (approximately $145 million in U.S. dollars). The sale is
subject to customary closing conditions. We expect the sale to close in the
third quarter of 2004.
ASSET IMPAIRMENTS
We record an asset impairment when we determine that the expected future
cash flows from an asset would be insufficient to provide for recovery of the
asset's carrying value. An asset held-in-use is evaluated for impairment by
calculating the undiscounted future cash flows expected to result from the use
of the asset and its eventual disposition. If the undiscounted future cash flows
are less than the carrying amount, we recognize an impairment loss. The
impairment loss recognized is the amount by which the carrying amount exceeds
the fair value. We estimate the fair market value of the asset utilizing the
best information available. This information includes quoted market prices,
market prices of similar assets, and discounted future cash flow analyses. The
assets written down include both domestic and foreign electric power plants, gas
processing facilities, and certain equity method and other investments. In
addition, we have written off the carrying value of projects under development
that will no longer be pursued.
F-13
The table below summarizes our asset impairments:
IN MILLIONS
-------------------------------------------------------------------------------------------------
SIX MONTHS ENDED JUNE 30 PRETAX 2004 AFTER-TAX 2004 PRETAX 2003 AFTER-TAX 2003
----------------------------------- ----------- -------------- ----------- --------------
Asset impairments:
Enterprises (a) $ - $ - $ 7 $ 4
International Energy Distribution - - 2 1
Loy Yang (b) 125 81 - -
----- ---- --- ---
Total asset impairments $ 125 $ 81 $ 9 $ 5
===== ==== === ===
(a) Primarily represents an impairment recorded to reflect the fair value of
two generators.
(b) In the first quarter of 2004, an impairment charge was recorded to
recognize the reduction in fair value as a result of the sale of Loy Yang,
completed in April 2004, which included a cumulative net foreign currency
translation loss of approximately $110 million.
RESTRUCTURING AND OTHER COSTS
In June 2002, we announced a series of initiatives to reduce our annual
operating costs by an estimated $50 million. As such, we:
- relocated CMS Energy's corporate headquarters from Dearborn,
Michigan to a new combined CMS Energy and Consumers headquarters in
Jackson, Michigan in July 2003,
- implemented changes to our 401(k) savings program,
- implemented changes to our health care plan, and
- completed the termination of numerous employees, including five
officers.
The following tables shows the amount charged to expense for restructuring
costs, the payments made, and the unpaid balance of accrued costs for the six
months ended June 30, 2004 and June 30, 2003.
IN MILLIONS
--------------------------------------------------------------------------------
INVOLUNTARY LEASE
TERMINATION TERMINATION TOTAL
----------- ----------- -------
Beginning accrual balance, January 1, 2004 $ 3 $ 6 $ 9
Expense - - -
Payments (1) (2) (3)
----------- ----------- -------
Ending accrual balance at June 30, 2004 $ 2 $ 4 $ 6
=========== =========== =======
IN MILLIONS
--------------------------------------------------------------------------------
INVOLUNTARY LEASE
TERMINATION TERMINATION TOTAL
----------- ----------- -------
Beginning accrual balance, January 1, 2003 $ 12 $ 8 $ 20
Expense 3 - 3
Payments (8) - (8)
----------- ----------- -------
Ending accrual balance at June 30, 2003 $ 7 $ 8 $ 15
=========== =========== =======
3: UNCERTAINTIES
Several business trends or uncertainties may affect our financial results
and condition. These trends or uncertainties have, or we reasonably expect could
have, a material impact on net sales, revenues, or income from continuing
operations. Such trends and uncertainties are discussed in detail below.
F-14
SEC AND OTHER INVESTIGATIONS: As a result of round-trip trading
transactions by CMS MST, CMS Energy's Board of Directors established a Special
Committee to investigate matters surrounding the transactions and retained
outside counsel to assist in the investigation. The Special Committee completed
its investigation and reported its findings to the Board of Directors in October
2002. The Special Committee concluded, based on an extensive investigation, that
the round-trip trades were undertaken to raise CMS MST's profile as an energy
marketer with the goal of enhancing its ability to promote its services to new
customers. The Special Committee found no effort to manipulate the price of CMS
Energy Common Stock or affect energy prices. The Special Committee also made
recommendations designed to prevent any recurrence of this practice. Previously,
CMS Energy terminated its speculative trading business and revised its risk
management policy. The Board of Directors adopted, and CMS Energy has
implemented the recommendations of the Special Committee.
CMS Energy is cooperating with an investigation by the DOJ concerning
round-trip trading. CMS Energy is unable to predict the outcome of this matter
and what effect, if any, this investigation will have on its business. In March
2004, the SEC approved a cease-and-desist order settling an administrative
action against CMS Energy related to round-trip trading. The order did not
assess a fine and CMS Energy neither admitted to nor denied the order's
findings. The settlement resolved the SEC investigation involving CMS Energy and
CMS MST.
SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of
securities class action complaints were filed against CMS Energy, Consumers, and
certain officers and directors of CMS Energy and its affiliates. The complaints
were filed as purported class actions in the United States District Court for
the Eastern District of Michigan, by shareholders who allege that they purchased
CMS Energy's securities during a purported class period. The cases were
consolidated into a single lawsuit and an amended and consolidated class action
complaint was filed on May 1, 2003. The consolidated complaint contains a
purported class period beginning on May 1, 2000 and running through March 31,
2003. It generally seeks unspecified damages based on allegations that the
defendants violated United States securities laws and regulations by making
allegedly false and misleading statements about CMS Energy's business and
financial condition, particularly with respect to revenues and expenses recorded
in connection with round-trip trading by CMS MST. The judge issued an opinion
and order dated March 31, 2004 in connection with various pending motions,
including plaintiffs' motion to amend the complaint and the motions to dismiss
the complaint filed by CMS Energy, Consumers and other defendants. The judge
directed plaintiffs to file an amended complaint under seal and ordered an
expedited hearing on the motion to amend, which was held on May 12, 2004. At the
hearing, the judge ordered plaintiffs to file a Second Amended Consolidated
Class Action complaint deleting Counts III and IV relating to purchasers of CMS
PEPS, which the judge ordered dismissed with prejudice. Plaintiffs filed this
complaint on May 26, 2004. CMS Energy, Consumers, and the individual defendants
filed new motions to dismiss on June 21, 2004. A hearing on those motions
occurred on August 2, 2004 and the judge has taken the matter under advisement.
CMS Energy, Consumers and the individual defendants will defend themselves
vigorously but cannot predict the outcome of this litigation.
DEMAND FOR ACTIONS AGAINST OFFICERS AND DIRECTORS: In May 2002, the Board
of Directors of CMS Energy received a demand, on behalf of a shareholder of CMS
Energy Common Stock, that it commence civil actions (i) to remedy alleged
breaches of fiduciary duties by certain CMS Energy officers and directors in
connection with round-trip trading by CMS MST, and (ii) to recover damages
sustained by CMS Energy as a result of alleged insider trades alleged to have
been made by certain current and former officers of CMS Energy and its
subsidiaries. In December 2002, two new directors were appointed to the Board.
The Board formed a special litigation committee in January 2003 to determine
whether it is in CMS Energy's best interest to bring the action demanded by the
shareholder. The disinterested members of the Board appointed the two new
directors to serve on the special litigation committee.
In December 2003, during the continuing review by the special litigation
committee, CMS Energy was served with a derivative complaint filed on behalf of
the shareholder in the Circuit Court of Jackson County, Michigan in furtherance
of his demands. The date for CMS Energy and other defendants to answer or
otherwise respond to the complaint has been extended to September 1, 2004,
subject to such further extensions as may be mutually agreed upon by the parties
and authorized by the Court. CMS Energy cannot predict the outcome of this
matter.
ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS
MST, and certain named and unnamed officers and directors, in two lawsuits
brought as purported class actions on behalf of participants and beneficiaries
of the CMS Employees' Savings and Incentive Plan (the Plan). The two cases,
filed in July 2002 in United States District Court for the Eastern District of
Michigan, were consolidated by the trial judge and an
F-15
amended consolidated complaint was filed. Plaintiffs allege breaches of
fiduciary duties under ERISA and seek restitution on behalf of the Plan with
respect to a decline in value of the shares of CMS Energy Common Stock held in
the Plan. Plaintiffs also seek other equitable relief and legal fees. The judge
issued an opinion and order dated March 31, 2004 in connection with the motions
to dismiss filed by CMS Energy, Consumers and the individuals. The judge
dismissed certain of the amended counts in the plaintiffs' complaint and denied
CMS Energy's motion to dismiss the other claims in the complaint. CMS Energy,
Consumers and the individual defendants filed answers to the amended complaint
on May 14, 2004. A trial date has not been set, but is expected to be no earlier
than late in 2005. CMS Energy and Consumers will defend themselves vigorously
but cannot predict the outcome of this litigation.
GAS INDEX PRICE REPORTING INVESTIGATION: CMS Energy has notified
appropriate regulatory and governmental agencies that some employees at CMS MST
and CMS Field Services appeared to have provided inaccurate information
regarding natural gas trades to various energy industry publications which
compile and report index prices. CMS Energy is cooperating with an ongoing
investigation by the DOJ regarding this matter. CMS Energy is unable to predict
the outcome of the DOJ investigation and what effect, if any, this investigation
will have on its business.
GAS INDEX PRICE REPORTING LITIGATION: In August 2003, Cornerstone Propane
Partners, L.P. (Cornerstone) filed a putative class action complaint in the
United States District Court for the Southern District of New York against CMS
Energy and dozens of other energy companies. The court ordered the Cornerstone
complaint to be consolidated with similar complaints filed by Dominick Viola and
Roberto Calle Gracey. The plaintiffs filed a consolidated complaint on January
20, 2004. The consolidated complaint alleges that false natural gas price
reporting by the defendants manipulated the prices of NYMEX natural gas futures
and options. The complaint contains two counts under the Commodity Exchange Act,
one for manipulation and one for aiding and abetting violations. CMS Energy is
no longer a defendant, however, CMS MST and CMS Field Services are named as
defendants. (CMS Energy sold CMS Field Services to Cantera Natural Gas, Inc. but
is required to indemnify Cantera Natural Gas, Inc. with respect to this action).
In a similar but unrelated matter, Texas-Ohio Energy, Inc. filed a
putative class action lawsuit in the United States District Court for the
Eastern District of California against a number of energy companies engaged in
the sale of natural gas in the United States. CMS Energy is named as a
defendant. The complaint alleges defendants entered into a price-fixing
conspiracy by engaging in activities to manipulate the price of natural gas in
California. The complaint contains counts alleging violations of the Sherman
Act, Cartwright Act (a California statute), and the California Business and
Profession Code relating to unlawful, unfair and deceptive business practices.
There is currently pending in the Nevada federal district court a multi-district
court litigation (MDL) matter involving seven complaints originally filed in
various state courts in California. These complaints make allegations similar to
those in the Texas-Ohio case regarding price reporting, although none contain a
Sherman Act claim and some of the defendants in the MDL matter are also
defendants in the Texas-Ohio case. Those defendants successfully argued to have
the Texas-Ohio case transferred to the MDL proceeding. The plaintiff in the
Texas-Ohio case agreed to extend the time for all defendants to answer or
otherwise respond until May 28, 2004 and on that date a number of defendants
filed motions to dismiss. In order to negotiate possible dismissal and/or
substitution of defendants, CMS Energy and two other parent holding company
defendants were given further extensions to answer or otherwise respond to the
complaint until August 16, 2004.
Benscheidt v. AEP Energy Services, Inc., et al., a new class action
complaint containing allegations similar to those made in the Texas-Ohio case,
albeit limited to California state law claims, was filed in California state
court in February 2004. CMS Energy and CMS MST are named as defendants.
Defendants filed a notice to remove this action to California federal district
court, which was granted, and had it transferred to the MDL proceeding in
Nevada. However, the plaintiff is seeking to have the case remanded back to
California and until the issue is resolved, no further action will be taken.
Three new, virtually identical actions were filed in San Diego Superior
Court in July 2004, one by the County of Santa Clara (Santa Clara), one by the
County of San Diego (San Diego), and one by the City of and County of San
Francisco and the San Francisco City Attorney (collectively San Francisco).
Defendants, consisting of a number of energy companies including CMS Energy, CMS
MS&T, Cantera Natural Gas and Cantera Gas Company, are alleged to have engaged
in false reporting of natural gas price and volume information and sham sales to
artificially
F-16
inflate natural gas retail prices in California. All three complaints allege
claims for unjust enrichment and violations of the Cartwright Act, and the San
Francisco action also alleges a claim for violation of the California Business
and Profession Code relating to unlawful, unfair and deceptive business
practices.
CMS Energy and the other CMS defendants will defend themselves vigorously,
but cannot predict the outcome of these matters.
CONSUMERS' UNCERTAINTIES
Several business trends or uncertainties may affect our financial results
and condition. These trends or uncertainties have, or we reasonably expect could
have, a material impact on revenues or income from continuing electric and gas
operations. Such trends and uncertainties include:
Environmental
- increased capital expenditures and operating expenses for Clean Air
Act compliance, and
- potential environmental liabilities arising from various
environmental laws and regulations, including potential liability or
expense relating to the Michigan Natural Resources and Environmental
Protection Acts, Superfund, and at former manufactured gas plant
facilities.
Restructuring
- response of the MPSC and Michigan legislature to electric industry
restructuring issues,
- ability to meet peak electric demand requirements at a reasonable
cost, without market disruption,
- ability to recover any of our net Stranded Costs under the
regulatory policies being followed by the MPSC,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer, instead of an electric
transmission owner.
Regulatory
- recovery of nuclear decommissioning costs,
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel,
- inadequate regulatory response to applications for requested rate
increases, and
- response to increases in gas costs, including adverse regulatory
response and reduced gas use by customers.
Other
- pending litigation regarding PURPA qualifying facilities, and
- other pending litigation.
CONSUMERS' ELECTRIC UTILITY CONTINGENCIES
ELECTRIC ENVIRONMENTAL MATTERS: Our operations are subject to
environmental laws and regulations. Costs to operate our facilities in
compliance with these laws and regulations generally have been recovered in
customer rates.
Clean Air: The EPA and the state regulations require us to make
significant capital expenditures estimated to be $771 million. As of June 30,
2004, we have incurred $489 million in capital expenditures to comply with the
EPA regulations and anticipate that the remaining $282 million of capital
expenditures will be made between 2004 and 2009. These expenditures include
installing catalytic reduction technology at some of our coal-fired electric
plants. Based on the Customer Choice Act, beginning January 2004, an annual
return of and on these types of capital
F-17
expenditures, to the extent they are above depreciation levels, is expected to
be recoverable from customers, subject to the MPSC prudency hearing.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants and potentially pay fines.
Additionally, the viability of certain plants remaining in operation could be
called into question.
In addition to modifying the coal-fired electric plants, we expect to
purchase nitrogen oxide emissions credits for years 2004 through 2008. The cost
of these credits is estimated to average $8 million per year and is accounted
for as inventory. The credit inventory is expensed as the coal-fired electric
plants generate electricity. The price for nitrogen oxide emissions credits is
volatile and could change substantially.
The EPA has proposed a Clean Air Interstate Rule that would require
additional coal-fired electric plant emission controls for nitrogen oxides and
sulfur dioxide. If implemented, this rule would potentially require expenditures
equivalent to those efforts in progress required to reduce nitrogen oxide
emissions under the Title I provisions of the Clean Air Act. The rule proposes a
two-phase program to reduce emissions of sulfur dioxide by 70 percent and
nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two
alternative sets of rules to reduce emissions of mercury and nickel from
coal-fired and oil-fired electric plants. Until the proposed environmental rules
are finalized, an accurate cost of compliance cannot be determined.
Several bills have been introduced in the United States Congress that
would require reductions in emissions of greenhouse gases. We cannot predict
whether any federal mandatory greenhouse gas emission reduction rules ultimately
will be enacted, or the specific requirements of any such rules if they were to
become law.
To the extent that greenhouse gas emission reduction rules come into
effect, such mandatory emissions reduction requirements could have far-reaching
and significant implications for the energy sectors. We cannot estimate the
potential effect of United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows or financial position
due to the speculative nature of the policy. We stay abreast of and engage in
the greenhouse gas policy developments, and will continue to assess and respond
to their potential implications on our business operations.
Water: In March 2004, the EPA changed the rules that govern generating
plant cooling water intake systems. The new rules require significant reduction
in fish killed by operating equipment. Some of our facilities will be required
to comply by 2006. We are studying the rules to determine the most
cost-effective solutions for compliance.
Cleanup and Solid Waste: Under the Michigan Natural Resources and
Environmental Protection Act, we expect that we will ultimately incur
investigation and remedial action costs at a number of sites. We believe that
these costs will be recoverable in rates under current ratemaking policies.
We are a potentially responsible party at several contaminated sites
administered under Superfund. Superfund liability is joint and several, meaning
that many other creditworthy parties with substantial assets are potentially
responsible with respect to the individual sites. Based on past experience, we
estimate that our share of the total liability for the known Superfund sites
will be between $1 million and $9 million. As of June 30, 2004, we have recorded
a liability for the minimum amount of our estimated Superfund liability.
In October 1998, during routine maintenance activities, we identified PCB
as a component in certain paint, grout, and sealant materials at the Ludington
Pumped Storage facility. We removed and replaced part of the PCB material. We
have proposed a plan to deal with the remaining materials and are awaiting a
response from the EPA.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities
selling power to us filed a lawsuit in Ingham County Circuit Court. The lawsuit
alleges that we incorrectly calculated the energy charge payments made
F-18
pursuant to power purchase agreements with qualifying facilities. More
specifically, the lawsuit alleges that we should be basing the energy charge
calculation on the cost of more expensive eastern coal, rather than on the cost
of the coal actually burned by us for use in our coal-fired generating plants.
We believe we have been performing the calculation in the manner prescribed by
the power purchase agreements, and have filed a request with the MPSC (as a
supplement to the PSCR plan) that asks the MPSC to review this issue and to
confirm that our method of performing the calculation is correct. We filed a
motion to dismiss the lawsuit in the Ingham County Circuit Court due to the
pending request at the MPSC concerning the PSCR plan case. In February 2004, the
judge ruled on the motion and deferred to the primary jurisdiction of the MPSC.
This ruling resulted in a dismissal of the circuit court case without prejudice.
Although only eight qualifying facilities have raised the issue, the same energy
charge methodology is used in the PPA with the MCV Partnership and in
approximately 20 additional power purchase agreements with us, representing a
total of 1,670 MW of electric capacity. The eight plaintiff qualifying
facilities have appealed the dismissal of the circuit court case to the Michigan
Court of Appeals. We cannot predict the outcome of this matter.
CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS
ELECTRIC RESTRUCTURING LEGISLATION: The Michigan legislature passed
electric utility restructuring legislation known as the Customer Choice Act.
This Act:
- allows all customers to choose their electric generation supplier
effective January 1, 2002,
- provides a one-time five percent residential electric rate
reduction,
- froze all electric rates through December 31, 2003, and established
a rate cap for residential customers through at least December 31,
2005, and a rate cap for small commercial and industrial customers
through at least December 31, 2004,
- allows deferred recovery of an annual return of and on capital
expenditures in excess of depreciation levels incurred during and
before the rate freeze-cap period,
- allows for the use of Securitization bonds to refinance qualified
costs,
- allows recovery of net Stranded Costs and implementation costs
incurred as a result of the passage of the act,
- requires Michigan utilities to join a FERC-approved RTO or sell
their interest in transmission facilities to an independent
transmission owner,
- requires Consumers, Detroit Edison, and AEP to jointly expand their
available transmission capability by at least 2,000 MW, and
- establishes a market power supply test that, if not met, may require
transferring control of generation resources in excess of that
required to serve retail sales requirements.
The following summarizes our status under the last three provisions of the
Customer Choice Act. First, we chose to sell our interest in our transmission
facilities to an independent transmission owner to comply with the Customer
Choice Act; for additional details regarding the sale of the transmission
facility, see "Transmission Sale" within this section. Second, in July 2002, the
MPSC issued an order approving our plan to achieve the increased transmission
capacity required under the Customer Choice Act. We have completed the
transmission capacity projects identified in the plan and have submitted
verification of this fact to the MPSC. We believe we are in full compliance.
Lastly, in September 2003, the MPSC issued an order finding that we are in
compliance with the market power supply test set forth in the Customer Choice
Act.
ELECTRIC ROA: The MPSC approved revised tariffs that establish the rates,
terms, and conditions under which retail customers are permitted to choose an
electric supplier. These revised tariffs allow ROA customers, upon as little as
30 days notice to us, to return to our generation service at current tariff
rates. If any class of customers'
F-19
(residential, commercial, or industrial) ROA load reaches ten percent of our
total load for that class of customers, then returning ROA customers for that
class must give 60 days notice to return to our generation service at current
tariff rates. However, we may not have capacity available to serve returning ROA
customers that is sufficient or reasonably priced. As a result, we may be forced
to purchase electricity on the spot market at higher prices than we can recover
from our customers during the rate cap periods. We cannot predict the total
amount of electric supply load that may be lost to alternative electric
suppliers. As of July 2004, alternative electric suppliers are providing 858 MW
of load. This amount represents 11 percent of the total distribution load and an
increase of 49 percent compared to July 2003.
ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric
restructuring proceedings. They are:
- Securitization,
- Stranded Costs,
- implementation costs,
- security costs, and
- transmission rates.
The following chart summarizes the filings with the MPSC. For additional
details related to these proceedings, see related sections within this Note.
PROCEEDING YEARS FILED YEARS COVERED REQUESTED AMOUNTS STATUS
-------------- ----------- ------------- ----------------- --------------------------------------------------------
Securitization 2003 N/A $1.083 billion Received order from the MPSC authorizing the issuance of
Securitization bonds in the amount of $554 million.
Pending MPSC order resolving outstanding issues.
Stranded Costs 2002-2004 2000-2003 $137 million (a) MPSC ruled that we experienced zero Stranded Costs for
2000 through 2001, which we are appealing. Filings for
2002 and 2003 in the amount of $116 million are still
pending MPSC approval.
Implementation 1999-2004 1997-2003 $91 million (b) MPSC allowed $68 million for the years 1997-2001, plus
Costs $20 million for the cost of money through 2003.
Implementation cost filings for 2002 and 2003 in the
amount of $8 million, which includes the cost of money
through 2003, are still pending MPSC approval.
Security Costs 2004 2001-2005 $25 million Pending MPSC approval. As of June 30, 2004, we have
recorded $7 million of costs incurred as a regulatory
asset.
(a) Amount includes the cost of money through the year in which we expected to
receive recovery from the MPSC and assumes the issuance of Securitization
bonds in an amount that includes Clean Air Act investments. If Clean Air
Act investments were not included in the issuance of Securitization bonds,
Stranded Costs requested would total $304 million.
(b) Amounts include the cost of money through year incurred.
F-20
Securitization: The Customer Choice Act allows for the use of
Securitization bonds to refinance certain qualified costs. Since Securitization
involves issuing bonds secured by a revenue stream from rates collected directly
from customers to service the bonds, Securitization bonds typically have a
higher credit rating than conventional utility corporate financing. In 2000 and
2001, the MPSC issued orders authorizing us to issue Securitization bonds. We
issued our first Securitization bonds in late 2001. Securitization resulted in:
- lower interest costs, and
- longer amortization periods for the securitized assets.
We will recover the repayment of principal, interest, and other expenses
relating to the bond issuance through a Securitization charge and a tax charge
that began in December 2001. These charges are subject to an annual true up
until one year before the last scheduled bond maturity date, and no more than
quarterly thereafter. The December 2003 true up modified the total
Securitization and related tax charges from 1.746 mills per kWh to 1.718 mills
per kWh. There will be no impact on customer bills from Securitization for most
of our electric customers until the Customer Choice Act cap period expires, and
an electric rate case is processed. Securitization charge collections, $25
million for the six months ended June 30, 2004, and $25 million for the six
months ended June 30, 2003, are remitted to a trustee. Securitization charge
collections are restricted to the repayment of the principal and interest on the
Securitization bonds and payment of the ongoing expenses of Consumers Funding.
Consumers Funding is legally separate from Consumers. The assets and income of
Consumers Funding, including the securitized property, are not available to
creditors of Consumers or CMS Energy.
In March 2003, we filed an application with the MPSC seeking approval to
issue additional Securitization bonds. In June 2003, the MPSC issued a financing
order authorizing the issuance of Securitization bonds in the amount of $554
million. This amount relates to Clean Air Act expenditures and associated return
on those expenditures through December 31, 2002, ROA implementation costs and
previously authorized return on those expenditures through December 31, 2000,
and other up front qualified costs related to issuance of the Securitization
bonds. In July 2003, we filed for rehearing and clarification on a number of
features in the financing order.
In December 2003, the MPSC ordered remanded hearings in response to our
request for rehearing and clarification. In March 2004, the MPSC conducted the
remanded hearings and the matter is presently before the MPSC awaiting a
decision.
In May 2004, we withdrew our request for approved implementation costs
incurred for the years 1998 through 2000 from the Securitization case, as we
chose recovery of the approved implementation costs through the use of a
surcharge, as described in "Implementation Costs" within this section. However,
qualified Clean Air Act costs, after taking out implementation costs, still
exceed the $554 million MPSC limit on the amount of securitized bonds. As a
result, we did not request a decrease to allowable securitized costs. If and
when the MPSC issues an order with favorable terms, then the order will become
effective upon our acceptance.
Stranded Costs: The Customer Choice Act allows electric utilities to
recover their net Stranded Costs, without defining the term. The Act directs the
MPSC to establish a method of calculating net Stranded Costs and of conducting
related true-up adjustments. In December 2001, the MPSC Staff recommended a
methodology, which calculated net Stranded Costs as the shortfall between:
- the revenue required to cover the costs associated with fixed
generation assets and capacity payments associated with purchase
power agreements, and
- the revenues received from customers under existing rates available
to cover the revenue requirement.
The MPSC authorizes us to use deferred accounting to recognize the future
recovery of costs determined to be stranded. According to the MPSC, net Stranded
Costs are to be recovered from ROA customers through a Stranded Cost transition
charge. However, the MPSC has not yet allowed such a transition charge. The MPSC
has declined to resolve numerous issues regarding the net Stranded Cost
methodology in a way that would allow a reliable
F-21
prediction of the level of Stranded Costs. As a result, we have not recorded
regulatory assets to recognize the future recovery of such costs.
The following table outlines the applications filed by us with the MPSC
and the status of recovery for these costs:
IN MILLIONS
--------------------------------------------------------------------------------------------
REQUESTED, WITHOUT THE
REQUESTED, WITH THE ISSUANCE ISSUANCE OF SECURITIZATION
OF SECURITIZATION BONDS THAT BONDS THAT INCLUDE CLEAN AIR
YEAR YEAR INCLUDE CLEAN AIR ACT ACT INVESTMENT AND COST OF RECOVERABLE
FILED INCURRED INVESTMENT AND COST OF MONEY MONEY AMOUNT
----- -------- ---------------------------- ---------------------------- -----------
2002 2000 $12 $ 26 $ -
2002 2001 9 46 -
2003 2002 47 104 Pending
2004 2003 69 128 Pending
===== ==== === ===== =======
We are currently in the process of appealing the MPSC orders regarding
Stranded Costs for 2000 and 2001 with the Michigan Court of Appeals and the
Michigan Supreme Court. In June 2004, the MPSC conducted hearings for our 2002
Stranded Cost application. Once a final financing order on Securitization is
reached, we will know the amount of our request for net Stranded Cost recovery
for 2002. In July 2004, the ALJ issued a proposal for decision in our 2002 net
Stranded Cost case, which recommended that the MPSC find that we incurred net
Stranded Costs of $12 million. This recommendation includes the cost of money
through July 2004 and excludes Clean Air Act investments.
The MPSC has scheduled hearings for our 2003 Stranded Cost application for
August 2004. In July 2004, the MPSC Staff issued a position on our 2003 net
Stranded Cost application, which resulted in a Stranded Cost calculation of $52
million. The amount includes the cost of money, but excludes Clean Air Act
investments. We cannot predict how the MPSC will rule on our requests for
recoverability of 2002 and 2003 Stranded Costs or whether the MPSC will adopt a
Stranded Cost recovery method that will offset fully any associated margin loss
from ROA.
Implementation Costs: The Customer Choice Act allows electric utilities to
recover their implementation costs. The following table outlines the
applications filed by us with the MPSC and the status of recovery for these
costs:
IN MILLIONS
------------------------------------------------------------------------------------------------
(b) RECOVERABLE, INCLUDING COST
YEAR FILED YEAR INCURRED REQUESTED DISALLOWED ALLOWED OF MONEY THROUGH 2003
--------------- ------------- --------- ---------- ------- ---------------------------
1999 1997 & 1998 $ 20 $ 5 $ 15 $ 22
2000 1999 30 5 25 33
2001 2000 25 5 20 24
2002 2001 8 - 8 9
2003 & 2004 (a) 2002 7 Pending Pending Pending
2004 2003 1 Pending Pending Pending
==== ==== ========= ========== ======= =======
(a) On March 31, 2004, we requested additional 2002 implementation cost
recovery of $5 million related to our former participation in the
development of the Alliance RTO. This cost has been expensed; therefore,
the amount is not included as a regulatory asset.
(b) Amounts include the cost of money through year incurred.
F-22
In addition to seeking MPSC approval for these costs, we are pursuing
authorization at the FERC for the MISO to reimburse us for approximately $8
million, for implementation costs related to our former participation in the
development of the Alliance RTO which includes the $5 million pending approval
by the MPSC as part of 2002 implementation costs recovery. These costs have
generally either been expensed or approved as recoverable implementation costs
by the MPSC. The FERC has denied our request for reimbursement and we are
appealing the FERC ruling at the United States Court of Appeals for the District
of Columbia. We cannot predict the outcome of the appeal process or the ultimate
amount, if any, we will collect for Alliance RTO development costs.
The MPSC disallowed certain costs, determining that these amounts did not
represent costs incremental to costs already reflected in electric rates. As of
June 30, 2004, we incurred and deferred as a regulatory asset $94 million of
implementation costs, which includes $25 million associated with the cost of
money. We believe the implementation costs and associated cost of money are
fully recoverable in accordance with the Customer Choice Act.
In June 2004, following an appeal and remand of initial MPSC orders
relating to 1999 implementation costs, the MPSC authorized the recovery of all
previously approved implementation costs for the years 1997 through 2001
totaling $88 million. This total includes carrying costs through 2003.
Additional carrying costs will be added until collection occurs. The
implementation costs will be recovered through surcharges over 36-month
collection periods and phased in as applicable rate caps expire. We cannot
predict the amounts the MPSC will approve as recoverable costs for 2002 and
2003.
Security Costs: The Customer Choice Act, as amended, allows for recovery
of new and enhanced security costs, as a result of federal and state regulatory
security requirements incurred before January 1, 2006. All retail customers,
except customers of alternative electric suppliers, would pay these charges. In
April 2004, we filed a security cost recovery case with the MPSC for costs for
which recovery has not yet been granted through other means. The requested
amount includes reasonable and prudent security enhancements through December
31, 2005. The costs are for enhanced security and insurance because of federal
and state regulatory security requirements imposed after the September 11, 2001
terrorist attacks. In July 2004, a settlement was reached with the parties to
the case, which would provide for full recovery of the requested security costs
over a five-year period beginning in 2004. We are presently awaiting approval
from the MPSC. We cannot predict how the MPSC will rule on our request for the
recoverability of security costs. The following table outlines the applications
filed by us with the MPSC and the status of recovery for these costs:
IN MILLIONS
--------------------------------------------------------------------------------------------
REGULATORY ASSET AS OF JUNE
YEAR FILED YEARS INCURRED REQUESTED 30, 2004 DISALLOWED ALLOWED
---------- -------------- --------- --------------------------- ---------- -------
2004 2001-2005 $25 $7 Pending Pending
==== ========= === == ======= =======
Transmission Rates: Our application of JOATT transmission rates to
customers during past periods is under FERC review. The rates included in these
tariffs were applied to certain transmission transactions affecting both Detroit
Edison's and our transmission systems between 1997 and 2002. We believe our
reserve is sufficient to satisfy our refund obligation to any of our former
transmission customers under our former JOATT.
TRANSMISSION SALE: In May 2002, we sold our electric transmission system
to MTH, a non-affiliated limited partnership whose general partner is a
subsidiary of Trans-Elect, Inc. We are currently in arbitration with MTH
regarding property tax items used in establishing the selling price of our
electric transmission system. An unfavorable outcome could result in a reduction
of sale proceeds previously recognized of approximately $2 million to $3
million.
Under an agreement with MTH, our transmission rates are fixed by contract
at current levels through December 31, 2005, and are subject to the FERC
ratemaking thereafter. However, we are subject to certain additional MISO
surcharges, which we estimate to be $10 million in 2004.
CONSUMERS' ELECTRIC UTILITY RATE MATTERS
PERFORMANCE STANDARDS: Electric distribution performance standards
developed by the MPSC became effective in February 2004. The standards relate to
restoration after outages, safety, and customer services. The
F-23
MPSC order calls for financial penalties in the form of customer credits if the
standards for the duration and frequency of outages are not met. We met or
exceeded all approved standards for year-end results for both 2002 and 2003. As
of June 2004, we are in compliance with the acceptable level of performance. We
are a member of an industry coalition that has appealed the customer credit
portion of the performance standards to the Michigan Court of Appeals. We cannot
predict the likely effects of the financial penalties, if any, nor can we
predict the outcome of the appeal. Likewise, we cannot predict our ability to
meet the standards in the future or the cost of future compliance.
POWER SUPPLY COSTS: We were required to provide backup service to ROA
customers on a best efforts basis. In October 2003, we provided notice to the
MPSC that we would terminate the provision of backup service in accordance with
the Customer Choice Act, effective January 1, 2004.
To reduce the risk of high electric prices during peak demand periods and
to achieve our reserve margin target, we employ a strategy of purchasing
electric call options and capacity and energy contracts for the physical
delivery of electricity primarily in the summer months and to a lesser degree in
the winter months. As of June 30, 2004, we purchased capacity and energy
contracts partially covering the estimated reserve margin requirements for 2004
through 2007. As a result, we have recognized an asset of $18 million for
unexpired capacity and energy contracts. In March 2004, we filed a summer
assessment for meeting 2004 peak load demand as required by the MPSC, stating
that our summer 2004 reserve margin target is 11 percent or supply resources
equal to 111 percent of projected summer peak load. Presently, we have a reserve
margin of 14 percent, or supply resources equal to 114 percent of projected
summer peak load for summer 2004. Of the 114 percent, approximately 102 percent
is from owned electric generating plants and long-term contracts, and
approximately 12 percent is from short-term contracts. This reserve margin met
our summer 2004 reserve margin target. The total premium costs of electricity
call options and capacity and energy contracts for 2004 is expected to be
approximately $12 million, as of July 2004.
PSCR: As a result of meeting the transmission capability expansion
requirements and the market power test, as discussed within this Note, we have
met the requirements under the Customer Choice Act to return to the PSCR
process. The PSCR process provides for the reconciliation of actual power supply
costs with power supply revenues. This process assures recovery of all
reasonable and prudent power supply costs actually incurred by us. In September
2003, we submitted a PSCR filing to the MPSC that reinstates the PSCR process
for customers whose rates are no longer frozen or capped as of January 1, 2004.
The proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers, and subject to the
overall rate caps, from other customers. We estimate the recovery of increased
power supply costs from large commercial and industrial customers to be
approximately $30 million in 2004. As allowed under current regulation, we
self-implemented the proposed PSCR charge on January 1, 2004. The revenues
received from the PSCR charge are also subject to subsequent reconciliation at
the end of the year after actual costs have been reviewed for reasonableness and
prudence. We cannot predict the outcome of this reconciliation proceeding.
OTHER CONSUMERS' ELECTRIC UTILITY UNCERTAINTIES
THE MIDLAND COGENERATION VENTURE: The MCV Partnership, which leases and
operates the MCV Facility, contracted to sell electricity to Consumers for a
35-year period beginning in 1990 and to supply electricity and steam to Dow. We
hold, through two wholly owned subsidiaries, the following assets related to the
MCV Partnership and the MCV Facility:
- CMS Midland owns a 49 percent general partnership interest in the
MCV Partnership, and
- CMS Holdings holds, through the FMLP, a 35 percent lessor interest
in the MCV Facility.
In 2004, we consolidated the MCV Partnership and the FMLP into our
consolidated financial statements in accordance with Revised FASB Interpretation
No. 46. For additional details, see Note 11, Implementation of New Accounting
Standards.
Our consolidated retained earnings include undistributed earnings from the
MCV Partnership, which at June 30, 2004 are $246 million and at June 30, 2003
are $243 million.
F-24
Power Supply Purchases from the MCV Partnership: Our annual obligation to
purchase capacity from the MCV Partnership is 1,240 MW through the term of the
PPA ending in 2025. The PPA requires us to pay, based on the MCV Facility's
availability, a levelized average capacity charge of 3.77 cents per kWh and a
fixed energy charge. We also pay a variable energy charge based on our average
cost of coal consumed for all kWh delivered. Effective January 1999, we reached
a settlement agreement with the MCV Partnership that capped capacity payments
made on the basis of availability that may be billed by the MCV Partnership at a
maximum 98.5 percent availability level.
Since January 1993, the MPSC has permitted us to recover capacity charges
averaging 3.62 cents per kWh for 915 MW, plus fixed and variable energy charges.
Since January 1996, the MPSC has also permitted us to recover capacity charges
for the remaining 325 MW of contract capacity with an initial average charge of
2.86 cents per kWh increasing periodically to an eventual 3.62 cents per kWh by
2004 and thereafter. However, due to the frozen retail rates required by the
Customer Choice Act, the capacity charge for the 325 MW was frozen at 3.17 cents
per kWh until December 31, 2003. Recovery of both the 915 MW and 325 MW portions
of the PPA are subject to certain limitations discussed below.
In 1992, we recognized a loss and established a liability for the present
value of the estimated future underrecoveries of power supply costs under the
PPA based on the MPSC cost-recovery orders. The remaining liability associated
with the loss totaled $13 million at June 30, 2004 and $40 million at June 30,
2003. We expect the PPA liability to be depleted in late 2004.
We estimate that 51 percent of the actual cash underrecoveries for 2004
will be charged to the PPA liability, with the remaining portion charged to
operating expense as a result of our 49 percent ownership in the MCV
Partnership. We will expense all cash underrecoveries directly to income once
the PPA liability is depleted. If the MCV Facility's generating availability
remains at the maximum 98.5 percent level, our cash underrecoveries associated
with the PPA could be as follows:
IN MILLIONS
------------------------------------------------------------------------------
2004 2005 2006 2007
------ ------ ------ ------
Estimated cash underrecoveries at 98.5% $ 56 $ 56 $ 55 $ 39
Amount to be charged to operating expense 29 56 55 39
Amount to be charged to PPA liability 27 - - -
====== ====== ====== ======
Beginning January 1, 2004, the rate freeze for large industrial customers
was no longer in effect and we returned to the PSCR process. Under the PSCR
process, we will recover from our customers the approved capacity and fixed
energy charges based on availability, up to an availability cap of 88.7 percent
as established in previous MPSC orders.
Effects on Our Ownership Interest in the MCV Partnership and the MCV
Facility: As a result of returning to the PSCR process on January 1, 2004, we
returned to dispatching the MCV Facility on a fixed load basis, as permitted by
the MPSC, in order to maximize recovery from electric customers of our capacity
and fixed energy payments. This fixed load dispatch increases the MCV Facility's
output and electricity production costs, such as natural gas. As the spread
between the MCV Facility's variable electricity production costs and its energy
payment revenue widens, the MCV's Partnership's financial performance and our
investment in the MCV Partnership is and will be affected adversely.
Under the PPA, variable energy payments to the MCV Partnership are based
on the cost of coal burned at our coal plants and our operation and maintenance
expenses. However, the MCV Partnership's costs of producing electricity are tied
to the cost of natural gas. Because natural gas prices have increased
substantially in recent years and the price the MCV Partnership can charge us
for energy has not, the MCV Partnership's financial performance has been
impacted negatively.
Until September 2007, the PPA and settlement agreement require us to pay
capacity and fixed energy charges
F-25
based on the MCV Facility's actual availability up to the 98.5 percent cap.
After September 2007, we expect to claim relief under the regulatory out
provision in the PPA, limiting our capacity and fixed energy payments to the MCV
Partnership to the amount collected from our customers. The MPSC's future
actions on the capacity and fixed energy payments recoverable from customers
subsequent to September 2007 may affect negatively the earnings of the MCV
Partnership and the value of our investment in the MCV Partnership.
Resource Conservation Plan: In February 2004, we filed the RCP with the
MPSC that is intended to help conserve natural gas and thereby improve our
investment in the MCV Partnership. This plan seeks approval to:
- dispatch the MCV Facility based on natural gas market prices without
increased costs to electric customers,
- give Consumers a priority right to buy excess natural gas as a
result of the reduced dispatch of the MCV Facility, and
- fund $5 million annually for renewable energy sources such as wind
power projects.
The RCP will reduce the MCV Facility's annual production of electricity
and, as a result, reduce the MCV Facility's consumption of natural gas by an
estimated 30 to 40 bcf. This decrease in the quantity of high-priced natural gas
consumed by the MCV Facility will benefit Consumers' ownership interest in the
MCV Partnership. The amount of PPA capacity and fixed energy payments recovered
from retail electric customers would remain capped at 88.7 percent. Therefore,
customers will not be charged for any increased power supply costs, if they
occur. Consumers and the MCV Partnership have reached an agreement that the MCV
Partnership will reimburse Consumers for any incremental power costs incurred to
replace the reduction in power dispatched from the MCV Facility. Presently, we
are in settlement discussions with the parties to the RCP filing. However, in
July 2004, several qualifying facilities filed for a stay on the RCP proceeding
in the Ingham County Circuit Court after their previous attempt to intervene on
the proceeding was denied by the MPSC. Hearings on the stay are scheduled for
August 11, 2004. We cannot predict if or when the MPSC will approve the RCP or
the outcome of the Ingham County Circuit Court hearings.
The two most significant variables in the analysis of the MCV
Partnership's future financial performance are the forward price of natural gas
for the next 20 years and the MPSC's decision in 2007 or beyond related to
limiting our recovery of capacity and fixed energy payments. Natural gas prices
have been volatile historically. Presently, there is no consensus in the
marketplace on the price or range of future prices of natural gas. Even with an
approved RCP, if gas prices continue at present levels or increase, the
economics of operating the MCV Facility may be adverse enough to require us to
recognize an impairment of our investment in the MCV Partnership. We presently
cannot predict the impact of these issues on our future earnings, cash flows, or
on the value of our investment in the MCV Partnership.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The MCV Partnership estimates that the
decision will result in a refund to the MCV Partnership of approximately $35
million in taxes plus $9 million of interest. The Michigan Tax Tribunal decision
has been appealed to the Michigan Court of Appeals by the City of Midland and
the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals.
The MCV Partnership also has a pending case with the Michigan Tax Tribunal for
tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of
these proceedings; therefore, the above refund (net of approximately $15 million
of deferred expenses) has not been recognized in year-to-date 2004 earnings.
NUCLEAR PLANT DECOMMISSIONING: Our site-specific decommissioning cost
estimates for Big Rock and Palisades assume that each plant site will eventually
be restored to conform to the adjacent landscape and all contaminated equipment
will be disassembled and disposed of in a licensed burial facility.
Decommissioning funding practices approved by the MPSC require us to file a
report on the adequacy of funds for decommissioning at three-year intervals. We
prepared and filed updated cost estimates for each plant on March 31, 2004.
Excluding additional costs for spent nuclear fuel storage, due to the DOE's
failure to accept this spent nuclear fuel on schedule, these reports show a
decommissioning cost of $361 million for Big Rock and $868 million for
Palisades. Since Big
F-26
Rock is currently in the process of being decommissioned, the estimated cost
includes historical expenditures in nominal dollars and future costs in 2003
dollars, with all Palisades costs given in 2003 dollars.
In 1999, the MPSC orders for Big Rock and Palisades provided for fully
funding the decommissioning trust funds for both sites. In December 2000,
funding of the Big Rock trust fund stopped because the MPSC-authorized
decommissioning surcharge collection period expired. The MPSC order set the
annual decommissioning surcharge for Palisades at $6 million through 2007.
Amounts collected from electric retail customers and deposited in trusts,
including trust earnings, are credited to a regulatory liability.
However, based on current projections, the current levels of funds
provided by the trusts are not adequate to fully fund the decommissioning of Big
Rock or Palisades. This is due in part to the DOE's failure to accept the spent
nuclear fuel and lower returns on the trust funds. We are attempting to recover
our additional costs for storing spent nuclear fuel through litigation, as
discussed in "Nuclear Matters". We will also seek additional relief from the
MPSC.
In the case of Big Rock, excluding the additional nuclear fuel storage
costs due to the DOE's failure to accept this spent fuel on schedule, we are
currently projecting that the level of funds provided by the trust will fall
short of the amount needed to complete the decommissioning by $25 million. At
this point in time, we plan to provide the additional amounts needed from our
corporate funds and, subsequent to the completion of radiological
decommissioning work, seek recovery of such expenditures at the MPSC. We cannot
predict how the MPSC will rule on our request.
In the case of Palisades, again excluding additional nuclear fuel storage
costs due to the DOE's failure to accept this spent fuel on schedule, we have
concluded that the existing surcharge needs to be increased to $25 million
annually, beginning January 1, 2006, and continue through 2011, our current
license expiration date. In June 2004, we filed an application with the MPSC
seeking approval to increase the surcharge for recovery of decommissioning costs
related to Palisades beginning in 2006. We cannot predict how the MPSC will rule
on our request.
NUCLEAR MATTERS: Big Rock: With the removal and safe disposal of the
reactor vessel, steam drum, and radioactive waste processing systems in 2003,
dismantlement of plant systems is nearly complete and demolition of the
remaining plant structures is set to begin. The restoration project is on
schedule to return approximately 530 acres of the site, including the area
formerly occupied by the nuclear plant, to a natural setting for unrestricted
use in mid-2006. An additional 30 acres, the area where seven transportable dry
casks loaded with spent nuclear fuel and an eighth cask loaded with high-level
radioactive waste material are stored, will be returned to a natural state by
the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010.
The NRC and the Michigan Department of Environmental Quality continue to
find all decommissioning activities at Big Rock are being performed in
accordance with applicable regulations including license requirements.
Palisades: In March 2004, the NRC completed its end-of-cycle plant
performance assessment of Palisades. The assessment for Palisades covered the
period from January 1, 2003 through December 31, 2003. The NRC determined that
Palisades was operated in a manner that preserved public health and safety and
fully met all cornerstone objectives. As of June 2004, all inspection findings
were classified as having very low safety significance and all performance
indicators indicated performance at a level requiring no additional oversight.
Based on the plant's performance, only regularly scheduled inspections are
planned through September 2005.
The amount of spent nuclear fuel exceeds Palisades' temporary onsite
storage pool capacity. We are using dry casks for temporary onsite storage. As
of June 30, 2004, we have loaded 18 dry casks with spent nuclear fuel and are
scheduled to load additional dry casks this summer in order to continue
operation.
DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that
the DOE was to begin accepting deliveries of spent nuclear fuel for disposal by
January 1998. Subsequent U.S. Court of Appeals litigation, in which we and other
utilities participated, has not been successful in producing more specific
relief for the DOE's failure to accept the spent nuclear fuel.
F-27
There are two court decisions that support the right of utilities to
pursue damage claims in the United States Court of Claims against the DOE for
failure to take delivery of spent nuclear fuel. Over 60 utilities have initiated
litigation in the United States Court of Claims; we filed our complaint in
December 2002. In July 2004, the DOE filed an amended answer and motion to
dismiss the complaint. If our litigation against the DOE is successful, we
anticipate future recoveries from the DOE. The recoveries will be used to pay
the cost of spent nuclear fuel storage until the DOE takes possession as
required by law. We can make no assurance that the litigation against the DOE
will be successful.
In July 2002, Congress approved and the President signed a bill
designating the site at Yucca Mountain, Nevada, for the development of a
repository for the disposal of high-level radioactive waste and spent nuclear
fuel. We expect that the DOE will submit, by December 2004, an application to
the NRC for a license to begin construction of the repository. The application
and review process is estimated to take several years.
Spent nuclear fuel complaint: In March 2003, the Michigan Environmental
Council, the Public Interest Research Group in Michigan, and the Michigan
Consumer Federation filed a complaint with the MPSC, which was served on us by
the MPSC in April 2003. The complaint asks the MPSC to initiate a generic
investigation and contested case to review all facts and issues concerning costs
associated with spent nuclear fuel storage and disposal. The complaint seeks a
variety of relief with respect to Consumers, Detroit Edison, Indiana & Michigan
Electric Company, Wisconsin Electric Power Company, and Wisconsin Public Service
Corporation. The complaint states that amounts collected from customers for
spent nuclear fuel storage and disposal should be placed in an independent
trust. The complaint also asks the MPSC to take additional actions. In May 2003,
Consumers and other named utilities each filed motions to dismiss the complaint.
We are unable to predict the outcome of this matter.
Insurance: We maintain nuclear insurance coverage on our nuclear plants.
At Palisades, we maintain nuclear property insurance from NEIL totaling $2.750
billion and insurance that would partially cover the cost of replacement power
during certain prolonged accidental outages. Because NEIL is a mutual insurance
company, we could be subject to assessments of up to $27 million in any policy
year if insured losses in excess of NEIL's maximum policyholders surplus occur
at our, or any other member's, nuclear facility. NEIL's policies include
coverage for acts of terrorism.
At Palisades, we maintain nuclear liability insurance for third-party
bodily injury and off-site property damage resulting from a nuclear hazard for
up to approximately $10.761 billion, the maximum insurance liability limits
established by the Price-Anderson Act. The United States Congress enacted the
Price-Anderson Act to provide financial liability protection for those parties
who may be liable for a nuclear accident or incident. Part of the Price-Anderson
Act's financial protection is a mandatory industry-wide program where owners of
nuclear generating facilities could be assessed if a nuclear incident occurs at
any nuclear generating facility. The maximum assessment against us could be $101
million per occurrence, limited to maximum annual installment payments of $10
million.
We also maintain insurance under a program that covers tort claims for
bodily injury to nuclear workers caused by nuclear hazards. The policy contains
a $300 million nuclear industry aggregate limit. Under a previous insurance
program providing coverage for claims brought by nuclear workers, we remain
responsible for a maximum assessment of up to $6 million.
Big Rock remains insured for nuclear liability by a combination of
insurance and a NRC indemnity totaling $544 million and a nuclear property
insurance policy from NEIL.
Insurance policy terms, limits, and conditions are subject to change
during the year as we renew our policies.
COMMITMENTS FOR FUTURE PURCHASES: We enter into a number of unconditional
purchase obligations that represent normal business operating contracts. These
contracts are used to assure an adequate supply of goods and services necessary
for the operation of our business and to minimize exposure to market price
fluctuations. We believe that these future costs are prudent and reasonably
assured of recovery in future rates.
Coal Supply and Transportation: We have entered into coal supply contracts
with various suppliers and associated rail transportation contracts for our
coal-fired generating stations. Under the terms of these agreements,
F-28
we are obligated to take physical delivery of the coal and make payment based
upon the contract terms. Our coal supply contracts expire through 2005, and
total an estimated $147 million. Our coal transportation contracts expire
through 2007, and total an estimated $108 million. Long-term coal supply
contracts have accounted for approximately 60 to 90 percent of our annual coal
requirements over the last 10 years. Although future contract coverage is not
finalized at this time, we believe that it will be within the historic 60 to 90
percent range.
Power Supply, Capacity, and Transmission: As of June 30, 2004, we had
future unrecognized commitments to purchase power transmission services under
fixed price forward contracts for 2004 and 2005 totaling $8 million. We also had
commitments to purchase capacity and energy under long-term power purchase
agreements with various generating plants. These contracts require monthly
capacity payments based on the plants' availability or deliverability. These
payments for 2004 through 2030 total an estimated $3.033 billion, undiscounted.
This amount may vary depending upon plant availability and fuel costs. If a
plant was not available to deliver electricity to us, then we would not be
obligated to make the capacity payment until the plant could deliver.
CONSUMERS' GAS UTILITY CONTINGENCIES
GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remedial
costs at a number of sites under the Michigan Natural Resources and
Environmental Protection Act, a Michigan statute that covers environmental
activities including remediation. These sites include 23 former manufactured gas
plant facilities. We operated the facilities on these sites for some part of
their operating lives. For some of these sites, we have no current ownership or
may own only a portion of the original site. We have completed initial
investigations at the 23 sites. We will continue to implement remediation plans
for sites where we have received MDEQ remediation plan approval. We will also
work toward resolving environmental issues at sites as studies are completed.
We have estimated our costs for investigation and remedial action at all
23 sites using the Gas Research Institute-Manufactured Gas Plant Probabilistic
Cost Model. We expect our remaining costs to be between $37 million and $90
million. The range reflects multiple alternatives with various assumptions for
resolving the environmental issues at each site. The estimates are based on
discounted 2003 costs using a discount rate of three percent. The discount rate
represents a ten-year average of U.S. Treasury bond rates reduced for increases
in the consumer price index. We expect to fund most of these costs through
insurance proceeds and through the MPSC approved rates charged to our customers.
As of June 30, 2004, we have recorded a regulatory liability of $42 million, net
of $41 million of expenditures incurred to date, and a regulatory asset of $66
million. Any significant change in assumptions, such as an increase in the
number of sites, different remediation techniques, nature and extent of
contamination, and legal and regulatory requirements, could affect our estimate
of remedial action costs.
In its November 2002 gas distribution rate order, the MPSC authorized us
to continue to recover approximately $1 million of manufactured gas plant
facilities environmental clean-up costs annually. This amount will continue to
be offset by $2 million to reflect amounts recovered from all other sources. We
defer and amortize, over a period of 10 years, manufactured gas plant facilities
environmental clean-up costs above the amount currently included in rates.
Additional amortization of the expense in our rates cannot begin until after a
prudency review in a gas rate case.
CONSUMERS' GAS UTILITY RATE MATTERS
GAS COST RECOVERY: The MPSC is required by law to allow us to charge
customers for our actual cost of purchased natural gas. The GCR process is
designed to allow us to recover all of our gas costs; however, the MPSC reviews
these costs for prudency in an annual reconciliation proceeding.
GCR YEAR 2002-2003: In June 2003, we filed a reconciliation of GCR costs
and revenues for the 12-months ended March 2003. We proposed to recover from our
customers approximately $6 million of underrecovered gas costs using a roll-in
methodology. The roll-in methodology incorporates the GCR underrecovery in the
next GCR plan year. The approach was approved by the MPSC in a November 2002
order.
In January 2004, intervenors filed their positions in our 2002-2003 GCR
case. Their positions were that not all of our gas purchasing decisions were
prudent during April 2002 through March 2003 and they proposed
F-29
disallowances. In 2003, we reserved $11 million for a settlement agreement
associated with the 2002-2003 GCR disallowance. Interest on the disallowed
amount from April 1, 2003 through February 2004, at Consumers' authorized rate
of return, increased the cost of the settlement by $1 million. The interest was
recorded as an expense in 2003. In February 2004, the parties in the case
reached a settlement agreement that resulted in a GCR disallowance of $11
million for the GCR period. The settlement agreement was approved by the MPSC in
March 2004. The disallowance is included in our 2003-2004 GCR reconciliation
filed in June 2004.
GCR YEAR 2003-2004: In June 2004, we filed a reconciliation of GCR for the
12-months ended March 2004. We proposed to refund to our customers $28 million
of overrecovered gas cost, plus interest. The refund will be included in the
2004-2005 GCR plan year. The overrecovery includes the $11 million refund
settlement for the 2002-2003 GCR year, as well as refunds received by us from
our suppliers and required by the MPSC to be refunded to our customers.
GCR PLAN FOR YEAR 2004-2005: In December 2003, we filed an application
with the MPSC seeking approval of a GCR plan for the 12-month period of April
2004 through March 2005. The second quarter GCR adjustment resulted in a GCR
ceiling price of $6.57. In June 2004, the MPSC issued a final Order in our GCR
plan approving a settlement, which included a quarterly mechanism for setting a
GCR ceiling price. The mechanism did not change the current ceiling price of
$6.57. Actual gas costs and revenues will be subject to an annual reconciliation
proceeding. Our GCR factor for the billing month of August is $6.39 per mcf.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC
for a $156 million annual increase in our gas delivery and transportation rates
that included a 13.5 percent return on equity. In September 2003, we filed an
update to our gas rate case that lowered the requested revenue increase from
$156 million to $139 million and reduced the return on common equity from 13.5
percent to 12.75 percent. The MPSC authorized an interim gas rate increase of
$19 million annually. The interim increase is under bond and subject to refund
if the final rate relief is a lesser amount. The interim increase order includes
a $34 million reduction in book depreciation expense and related income taxes
effective only during the period of interim relief. The MPSC order allowed us to
increase our rates beginning December 19, 2003. As part of the interim order,
Consumers agreed to restrict dividend payments to its parent company, CMS
Energy, to a maximum of $190 million annually during the period of interim
relief. On March 5, 2004, the ALJ issued a Proposal for Decision recommending
that the MPSC not rely upon the projected test year data included in our filing,
which was supported by the MPSC Staff and the ALJ further recommended that the
application be dismissed. In response to the Proposal for Decision, the parties
have filed exceptions and replies to exceptions. The MPSC is not bound by the
ALJ's recommendation and will review the exceptions and replies to exceptions
prior to issuing an order on final rate relief.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our
gas utility plant depreciation case originally filed in June 2001. This case is
not affected by the 2003 gas rate case interim increase order that reduced book
depreciation expense and related income taxes only for the period that we
receive the interim relief.
The June 2001 depreciation case filing was based on December 2000 plant
balances and historical data. The December 2003 filing updates the gas
depreciation case to include December 2002 plant balances. The proposed
depreciation rates, if approved, would result in an annual increase of $12
million in depreciation expense based on December 2002 plant balances. In June
2004, the ALJ issued a Proposal for Decision recommending adoption of the
Michigan Attorney General's proposal to reduce our annual depreciation expense
by $52 million. In response to the Proposal for Decision, the parties filed
exceptions and are expected to file replies to exceptions. In our exceptions, we
proposed alternative depreciation rates that would result in an annual decrease
of $7 million in depreciation expense. The MPSC is not bound by the ALJ's
recommendation and will review the exceptions and replies to exceptions prior to
issuing an order on final depreciation rates.
In September 2002, the FERC issued an order rejecting our filing to assess
certain rates for non-physical gas title tracking services we provide. In
December 2003, the FERC ruled that no refunds were at issue and we reversed $4
million related to this matter. In January 2004, three companies filed with the
FERC for clarification or rehearing of the FERC's December 2003 order. In April
2004, the FERC issued its Order Granting Clarification. In that Order, the FERC
indicated that its December 2003 order was in error. It directed us to file
within 30 days a fair and equitable title-tracking fee and to make refunds, with
interest, to customers based on the difference between the
F-30
accepted fee and the fee paid. In response to the FERC's April 2004 order, we
filed a Request for Rehearing in May 2004. The FERC issued an Order Granting
Rehearing for Further Consideration in June 2004. We expect the FERC to issue an
order on the merits of this proceeding in the third quarter of 2004. We believe
that with respect to the FERC jurisdictional transportation, we have not charged
any customers title transfer fees, so no refunds are due. At this time, we
cannot predict the outcome of this proceeding.
OTHER UNCERTAINTIES
INTEGRUM LAWSUIT: Integrum filed a complaint in Wayne County, Michigan
Circuit Court in July 2003 against CMS Energy, Enterprises and APT. Integrum
alleges several causes of action against APT, CMS Energy, and Enterprises in
connection with an offer by Integrum to purchase the CMS Pipeline Assets. In
addition to seeking unspecified money damages, Integrum is seeking an order
enjoining CMS Energy and Enterprises from selling, and APT from purchasing, the
CMS Pipeline Assets and an order of specific performance mandating that CMS
Energy, Enterprises, and APT complete the sale of the CMS Pipeline Assets to APT
and Integrum. A certain officer and director of Integrum is a former officer and
director of CMS Energy, Consumers, and their subsidiaries. The individual was
not employed by CMS Energy, Consumers, or their subsidiaries when Integrum made
the offer to purchase the CMS Pipeline Assets. CMS Energy and Enterprises filed
a motion to change venue from Wayne County to Jackson County, which was granted.
The parties are now awaiting transfer of the file from Wayne County to Jackson
County. CMS Energy and Enterprises believe that Integrum's claims are without
merit. CMS Energy and Enterprises intend to defend vigorously against this
action but they cannot predict the outcome of this litigation.
CMS GENERATION-OXFORD TIRE RECYCLING: In an administrative order, the
California Regional Water Control Board of the state of California named CMS
Generation as a potentially responsible party for the clean up of the waste from
the fire that occurred in September 1999 at the Filbin Tire Pile, which the
state claims was owned by Oxford Tire Recycling of North Carolina, Inc. CMS
Generation reached a settlement with the state, which the court approved,
pursuant to which CMS Generation paid the state $5.5 million, $1.6 million of
which it had paid the state prior to the settlement. CMS Generation continues to
negotiate to have the insurance company pay a portion of the settlement amount,
as well as a portion of its attorney fees.
At the request of the DOJ in San Francisco, CMS Energy and other parties
contacted by the DOJ in San Francisco entered into separate Tolling Agreements
with the DOJ in San Francisco in September 2002. The Tolling Agreement stops the
running of any statute of limitations during the ninety-day period between
September 13, 2002 and (through several extensions of the tolling period) March
30, 2004, to facilitate settlement discussions between all the parties in
connection with federal claims arising from the fire at the Filbin Tire Pile. On
September 23, 2002, CMS Energy received a written demand from the U.S. Coast
Guard for reimbursement of approximately $3.5 million in costs incurred by the
U.S. Coast Guard in fighting the fire. It is CMS Energy's understanding that
these costs, together with any accrued interest, are the sole basis of any
federal claims. CMS Energy has entered into a consent judgment with the U.S.
Coast Guard to settle this matter for $475,000 that is awaiting final court
approval.
DEARBORN INDUSTRIAL GENERATION: In October 2001, Duke/Fluor Daniel (DFD)
presented DIG with a change order to their construction contract and filed an
action in Michigan state court claiming damages in the amount of $110 million,
plus interest and costs, which DFD states represents the cumulative amount owed
by DIG for delays DFD believes DIG caused and for prior change orders that DIG
previously rejected. DFD also filed a construction lien for the $110 million.
DIG, in addition to drawing down on three letters of credit totaling $30 million
that it obtained from DFD, has filed an arbitration claim against DFD asserting
in excess of an additional $75 million in claims against DFD. The judge in the
Michigan state court case entered an order staying DFD's prosecution of its
claims in the court case and permitting the arbitration to proceed. DFD has
appealed the decision by the judge in the Michigan state court case to stay the
litigation. DIG will continue to defend itself vigorously and pursue its claims.
DIG cannot predict the outcome of this matter.
DIG NOISE ABATEMENT LAWSUIT: In February 2003, DIG was served with a
three-count first amended complaint filed in Wayne County Circuit Court in the
matter of Ahmed, et al v. Dearborn Industrial Generation, LLC. The complaint
sought damages "in excess of $25,000" and injunctive relief based upon
allegations of excessive noise
F-31
and vibration created by operation of the power plant. The first amended
complaint was filed on behalf of six named plaintiffs, all alleged to be
adjacent or nearby residents or property owners. The damages alleged were injury
to persons and property of the landowners. Certification of a class of
"potentially thousands" who have been similarly affected was requested. The
parties entered into a settlement agreement on June 25, 2004, whereby DIG will
remediate the sound emitted from various pieces of plant equipment to a level
below the ambient noise level and pay a substantial portion of plaintiffs'
attorney fees and costs. A class will be certified for settlement purposes only
and remediation will take approximately 280 days. DIG is seeking proposals for
remediation and testing but DIG cannot predict the cost associated with the
settlement of this matter.
MCV EXPANSION, LLC: Under an agreement entered into with General Electric
Company (GE) in October 2002, MCV Expansion, LLC has a remaining contingent
obligation to GE in the amount of $2.2 million that may become payable in the
fourth quarter of 2004. The agreement provides that this contingent obligation
is subject to a pro rata reduction under a formula based upon certain purchase
orders being entered into with GE by June 30, 2003. MCV Expansion, LLC
anticipates but cannot assure that purchase orders will be executed with GE
sufficient to eliminate contingent obligations of $2.2 million.
FORMER CMS OIL AND GAS OPERATIONS: A Michigan trial judge granted Star
Energy, Inc. and White Pine Enterprises, LLC a declaratory judgment in an action
filed in 1999 that claimed Terra Energy Ltd., a former CMS Oil and Gas
subsidiary, violated an oil and gas lease and other arrangements by failing to
drill wells it had committed to drill. A jury then awarded the plaintiffs a $7.6
million award. Terra appealed this matter to the Michigan Court of Appeals. The
Michigan Court of Appeals reversed the trial court judgment with respect to the
appropriate measure of damages and remanded the case for a new trial on damages.
The trial judge reinstated the judgment against Terra and awarded Terra title to
the minerals. Terra has appealed this judgment. Enterprises has an indemnity
obligation with regard to losses to Terra that might result from this
litigation.
GASATACAMA: On March 24, 2004, the Argentine Government authorized the
restriction of exports of natural gas to Chile giving priority to domestic
demand in Argentina. This restriction could have a detrimental effect on
GasAtacama's earnings since GasAtacama's gas-fired power plant is located in
Chile and uses Argentine gas for fuel. On April 21, 2004, Argentina and Bolivia
signed an agreement in which Bolivian gas producers agreed to supply natural gas
to Argentina for six months. Bolivian gas began flowing to Argentina in mid-June
and will continue to flow through October 2004. The government of Argentina has
also approved an agreement with Argentine producers that should help solve
Argentina's long-term gas shortage problems. Additionally, on May 11, 2004, the
Argentine Government announced the creation of a state-owned and operated energy
company, which intends to make investments in domestic natural gas and
electricity infrastructure projects. Currently, management of GasAtacama is
working with government officials of Chile and Argentina, as well as meeting
with its electricity customers and gas producers, to attempt to mitigate the
impact of this situation. At this point, it is not possible to predict the
outcome of these events and their effect on the earnings of GasAtacama.
ARGENTINA ECONOMIC SITUATION: In January 2002, the Republic of Argentina
enacted the Public Emergency and Foreign Exchange System Reform Act. This law
repealed the fixed exchange rate of one U.S. dollar to one Argentine peso,
converted all dollar-denominated utility tariffs and energy contract obligations
into pesos at the same one-to-one exchange rate, and directed the President of
Argentina to renegotiate such tariffs.
Effective April 30, 2002, we adopted the Argentine peso as the functional
currency for our Argentine investments. We had used previously the U.S. dollar
as the functional currency. As a result, we translated the assets and
liabilities of our Argentine entities into U.S. dollars using an exchange rate
of 3.45 pesos per U.S. dollar, and recorded an initial charge to the Foreign
Currency Translation component of stockholders' equity of $400 million.
While we cannot predict future peso-to-U.S. dollar exchange rates, we do
expect that these non-cash charges reduce substantially the risk of further
material balance sheet impacts when combined with anticipated proceeds from
international arbitration currently in progress, political risk insurance, and
the eventual sale of these assets. At June 30, 2004, the net foreign currency
loss due to the unfavorable exchange rate of the Argentine peso recorded in the
Foreign Currency Translation component of stockholders' equity using an exchange
rate of 2.97 pesos per U.S. dollar was $263 million. This amount also reflects
the effect of recording, at December 31, 2002, U.S. income taxes
F-32
on temporary differences between the book and tax bases of foreign investments,
including the foreign currency translation associated with our Argentine
investments.
LEONARD FIELD DISPUTE: Pursuant to a Consent Judgment entered in Oakland
County, Michigan Circuit Court in September 2001, CMS Gas Transmission had 18
months to extract approximately one bcf of pipeline quality natural gas held in
the Leonard Field in Addison Township. The Consent Judgment provided for an
extension of that period upon certain circumstances. CMS Gas Transmission has
complied with the requirements of the Consent Judgment. Addison Township filed a
lawsuit in Oakland County Circuit Court against CMS Gas Transmission in February
2004 alleging the Leonard Field was discharging odors in violation of the
Consent Judgment. Pursuant to a Stipulated Order entered April 1, 2004, CMS Gas
Transmission agreed to certain undertakings to address the odor complaints and
further agreed to temporarily cease operations at the Leonard Field during the
month of April 2004, the last month provided for in the Consent Judgment. Also,
Addison Township was required to grant CMS Gas Transmission an extension to
withdraw its natural gas if certain conditions were met. Addison Township denied
CMS Gas Transmission's request for an extension on April 5, 2004. CMS Gas
Transmission is pursuing its legal remedies and filed a complaint against
Addison Township in June 2004. CMS Gas Transmission cannot predict the outcome
of this matter, and unless an extension is provided, it will be unable to
extract approximately 500,000 mcf of gas remaining in the Leonard Field.
CMS ENSENADA CUSTOMER DISPUTE: Pursuant to a long-term power purchase
agreement, CMS Ensenada sells power and steam to YPF Repsol at the YPF refinery
in La Plata, Argentina. As a result of the so-called "Emergency Laws," payments
by YPF Repsol under the power purchase agreement have been converted to pesos at
the exchange rate of one U.S. dollar to one Argentine peso. Such payments are
currently insufficient to cover CMS Ensenada's operating costs, including
quarterly debt service payments to the Overseas Private Investment Corporation
(OPIC). Enterprises is party to a Sponsor Support Agreement pursuant to which
Enterprises has guaranteed CMS Ensenada's debt service payments to the OPIC up
to an amount which is in dispute, but which Enterprises estimated to be
approximately $9 million at June 30, 2004. Following a payment made to the OPIC
in July 2004, Enterprises now believes this amount to be approximately $7
million.
An interim arrangement, which provided CMS Ensenada with payments under
the power purchase agreement that covered most, but not all, of CMS Ensenada's
operating costs, was agreed to with YPF Repsol in 2002 but expired on December
31, 2003. Efforts to negotiate a new agreement with YPF Repsol have been
unsuccessful.
As a result, CMS Ensenada initiated two legal actions: (1) an ex parte
action in the Argentine commercial courts, requesting injunctive relief in the
form of a temporary increase in the payments by YPF Repsol under the power
purchase agreement that would allow CMS Ensenada to continue to operate while
seeking a final and permanent resolution; and (2) an arbitration administered by
the International Chamber of Commerce seeking a ruling that the application of
the Emergency Laws to the power purchase agreement is unconstitutional, or,
alternatively, that the arbitral panel reestablish the economic equilibrium of
the power purchase agreement, as required by the Emergency Laws taking into
account that a significant portion of CMS Ensenada's operating costs are payable
in U.S. dollars. In April 2004, the injunctive relief was granted on appeal, but
in an amount lower than requested by CMS Ensenada. The injunctive relief expired
at the end of May, but the court recently extended the term of relief until the
end of the arbitration.
OTHER: Certain CMS Gas Transmission and CMS Generation affiliates in
Argentina received notice from various Argentine provinces claiming stamp taxes
and associated penalties and interest arising from various gas transportation
transactions. Although these claims total approximately $24 million, we believe
the claims are without merit and will continue to contest them vigorously.
CMS Generation does not currently expect to incur significant capital
costs at its power facilities for compliance with current U.S. environmental
regulatory standards.
In addition to the matters disclosed within this Note, Consumers and
certain other subsidiaries of CMS Energy are parties to certain lawsuits and
administrative proceedings before various courts and governmental agencies
arising from the ordinary course of business. These lawsuits and proceedings may
involve personal injury, property damage, contractual matters, environmental
issues, federal and state taxes, rates, licensing, and other matters.
F-33
We have accrued estimated losses for certain contingencies discussed within
this Note. Resolution of these contingencies is not expected to have a material
adverse impact on our financial position, liquidity, or results of operations.
4: FINANCINGS AND CAPITALIZATION
Long-term debt is summarized as follows:
IN MILLIONS
----------------------------------------
JUNE 30, 2004 DECEMBER 31, 2003
------------- -----------------
CMS ENERGY CORPORATION
Senior notes $ 2,063 $ 2,063
General term notes 236 496
Extendible tenor rate adjusted securities and other 186 187
------- -------
Total - CMS Energy Corporation 2,485 2,746
------- -------
CONSUMERS ENERGY COMPANY
First mortgage bonds 1,483 1,483
Senior notes 1,254 1,254
Bank debt and other 468 469
Securitization bonds 412 426
FMLP debt 411 -
------- -------
Total - Consumers Energy Company 4,028 3,632
------- -------
OTHER SUBSIDIARIES 200 191
------- -------
Principal amounts outstanding 6,713 6,569
Current amounts (860) (509)
Net unamortized discount (37) (40)
------- -------
Total consolidated long-term debt $ 5,816 $ 6,020
======= =======
FMLP DEBT: We consolidate the FMLP in accordance with Revised FASB
Interpretation No. 46. At June 30, 2004, long-term debt of the FMLP consists of:
IN MILLIONS
-----------------------------
MATURITY 2004
-------- -----------
11.75% subordinated secured notes 2005 $ 185
13.25% subordinated secured notes 2006 75
6.875% tax-exempt subordinated secured notes 2009 137
6.75% tax-exempt subordinated secured notes 2009 14
---- -----
Total amount outstanding $ 411
==== =====
The FMLP debt is essentially project debt secured by certain assets of the
MCV Partnership and the FMLP. The debt is non-recourse to other assets of CMS
Energy and Consumers.
DEBT MATURITIES: At June 30, 2004, the aggregate annual maturities for
long-term debt for the six months ending December 31, 2004 and the next four
years are:
IN MILLIONS
---------------------------------------------------------
PAYMENTS DUE
---------------------------------------------------------
2004 2005 2006 2007 2008
----- ----- ----- ----- -------
Long-term debt $ 342 $ 789 $ 549 $ 550 $ 1,053
===== ===== ===== ===== =======
F-34
REGULATORY AUTHORIZATION FOR FINANCINGS: Effective July 1, 2004, Consumers
received new FERC authorization to issue or guarantee up to $1.1 billion of
short-term securities and up to $1.1 billion of short-term first mortgage bonds
as collateral for such short-term securities. Effective July 1, 2004, Consumers
received new FERC authorization to issue up to $1 billion of long-term
securities for refinancing or refunding purposes, $1.5 billion of long-term
securities for general corporate purposes, and $2.5 billion of long-term first
mortgage bonds to be issued solely as collateral for other long-term securities.
SHORT-TERM FINANCINGS: At June 30, 2004, CMS Energy had a $190 million
secured revolving credit facility with banks and a $185 million
cash-collateralized letter of credit facility with banks. At June 30, 2004, all
of the $190 million is available for general corporate purposes and $17 million
is available for letters of credit. At June 30, 2004, Consumers had a $400
million secured revolving credit facility with banks. At June 30, 2004, $24
million of letters of credit are issued and outstanding under this facility and
$376 million is available for general corporate purposes, working capital, and
letters of credit. The MCV Partnership had a $50 million working capital
facility available.
As of August 3, 2004, CMS Energy obtained an amended and restated $300
million secured revolving credit facility to replace both the $190 million and
the $185 million facilities. As of August 3, 2004, Consumers obtained an amended
and restated $500 million secured revolving credit facility to replace their
$400 million facility. The amended facilities carry three-year terms and provide
for lower interest rates.
FIRST MORTGAGE BONDS: Consumers secures its first mortgage bonds by a
mortgage and lien on substantially all of its property. Its ability to issue and
sell securities is restricted by certain provisions in the first mortgage bond
indenture, its articles of incorporation, and the need for regulatory approvals
under federal law.
CAPITAL AND FINANCE LEASE OBLIGATIONS: Our capital leases are comprised
mainly of leased service vehicles and office furniture. As of June 30, 2004,
capital lease obligations totaled $64 million. In order to obtain permanent
financing for the MCV Facility, the MCV Partnership entered into a sale and
lease back agreement with a lessor group, which includes the FMLP, for
substantially all of the MCV Partnership's fixed assets. In accordance with SFAS
No. 98, the MCV Partnership accounted for the transaction as a financing
arrangement. As of June 30, 2004, finance lease obligations totaled $317
million, which represents the third-party portion of the MCV Partnership's
finance lease obligation.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we currently sell certain accounts receivable to a wholly owned,
consolidated, bankruptcy remote special purpose entity. In turn, the special
purpose entity may sell an undivided interest in up to $325 million of the
receivables. We sold no receivables at June 30, 2004 and we sold $50 million at
June 30, 2003. The Consolidated Balance Sheets exclude these sold amounts from
accounts receivable. We continue to service the receivables sold. The purchaser
of the receivables has no recourse against our other assets for failure of a
debtor to pay when due and the purchaser has no right to any receivables not
sold. No gain or loss has been recorded on the receivables sold and we retain no
interest in the receivables sold.
Certain cash flows received from and paid to us under our accounts
receivable sales program are shown below:
IN MILLIONS
------------------------
SIX MONTHS ENDED JUNE 30 2004 2003
------------------------------------------------------------------- -------- --------
Proceeds from sales (remittance of collections) under the program $ (297) $ (275)
Collections reinvested under the program $ 2,645 $ 2,459
======= =======
DIVIDEND RESTRICTIONS: Under the provisions of its articles of
incorporation, at June 30, 2004, Consumers had $396 million of unrestricted
retained earnings available to pay common stock dividends. However, covenants in
Consumers' debt facilities cap common stock dividend payments at $300 million in
a calendar year. Consumers is also under an annual dividend cap of $190 million
imposed by the MPSC during the current interim gas rate relief period. For the
six months ended June 30, 2004, CMS Energy received $105 million of common stock
dividends from Consumers.
F-35
Our amended and restated $300 million secured revolving credit facility
restricts payments of dividends on our common stock during a 12-month period to
$75 million, dependent on the aggregate amounts of unrestricted cash and unused
commitments under the facility.
For additional details on the cap on common stock dividends payable during
the current interim gas rate relief period, see Note 3, Uncertainties,
"Consumers' Gas Utility Rate Matters - 2003 Gas Rate Case."
FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE
REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF
OTHERS: This Interpretation became effective January 2003. It describes the
disclosure to be made by a guarantor about its obligations under certain
guarantees that it has issued. At the beginning of a guarantee, it requires a
guarantor to recognize a liability for the fair value of the obligation
undertaken in issuing the guarantee. The initial recognition and measurement
provision of this Interpretation does not apply to some guarantee contracts,
such as warranties, derivatives, or guarantees between either parent and
subsidiaries or corporations under common control, although disclosure of these
guarantees is required. For contracts that are within the recognition and
measurement provision of this Interpretation, the provisions were to be applied
to guarantees issued or modified after December 31, 2002.
The following table describes our guarantees at June 30, 2004:
IN MILLIONS
-----------------------------------------------------------------
ISSUE EXPIRATION MAXIMUM CARRYING RECOURSE
GUARANTEE DESCRIPTION DATE DATE OBLIGATION AMOUNT(b) PROVISION(c)
----------------------------------------- ------- ---------- ---------- --------- ------------
Indemnifications from asset sales and
other agreements(a) Various Various $1,147 $ 4 $ -
Letters of credit Various Various 235 - -
Surety bonds and other indemnifications Various Various 28 - -
Other guarantees Various Various 199 - -
Nuclear insurance retrospective premiums Various Various 134 - -
======= ======= ====== === ===
(a) The majority of this amount arises from routine provisions in stock and
asset sales agreements under which we indemnify the purchaser for losses
resulting from events such as failure of title to the assets or stock
sold by us to the purchaser. We believe the likelihood of a loss for any
remaining indemnifications to be remote.
(b) The carrying amount represents the fair market value of guarantees and
indemnities recorded on our balance sheet that are entered into
subsequent to January 1, 2003.
(c) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.
The following table provides additional information regarding our
guarantees:
GUARANTEE DESCRIPTION HOW GUARANTEE AROSE EVENTS THAT WOULD REQUIRE PERFORMANCE
---------------------------------------- ------------------------------------ -------------------------------------
Indemnifications from asset sales and Stock and asset sales agreements Findings of misrepresentation,
other agreements breach of warranties, and other
specific events or circumstances
Standby letters of credit Normal operations of coal power Noncompliance with environmental
plants regulations
Self-insurance requirement Nonperformance
Surety bonds Normal operating activity, permits Nonperformance
and license
Other guarantees Normal operating activity Nonperformance or non-payment by a
subsidiary under a related contract
Nuclear insurance retrospective premiums Normal operations of nuclear plants Call by NEIL and Price-Anderson Act
for nuclear incident
We have entered into typical tax indemnity agreements in connection with a
variety of transactions including transactions for the sale of subsidiaries and
assets, equipment leasing, and financing agreements. These indemnity
F-36
agreements generally are not limited in amount and, while a maximum amount of
exposure cannot be identified, the probability of liability is considered
remote.
We have guaranteed payment of obligations through letters of credit,
indemnities, surety bonds, and other guarantees of unconsolidated affiliates and
related parties of $462 million as of June 30, 2004. We monitor and approve
these obligations and believe it is unlikely that we would be required to
perform or otherwise incur any material losses associated with the above
obligations. The off-balance sheet commitments expire as follows:
COMMERCIAL COMMITMENTS IN MILLIONS
----------------------------------------------------------------
COMMITMENT EXPIRATION
----------------------------------------------------------------
2009 AND
TOTAL 2004 2005 2006 2007 2008 BEYOND
----- ---- ---- ---- ---- ---- --------
Off-balance sheet:
Guarantees $ 199 $ 6 $ 36 $ 5 $ - $ - $ 152
Surety bonds and other 28 1 - - - - 27
indemnifications (a)
Letters of Credit (b) 235 23 184 5 5 5 13
----- ---- ----- ---- --- --- -----
Total $ 462 $ 30 $ 220 $ 10 $ 5 $ 5 $ 192
===== ==== ===== ==== === === =====
(a) The surety bonds are continuous in nature. The need for the bonds is
determined on an annual basis.
(b) At June 30, 2004, we had $169 million of cash held as collateral for
letters of credit. The cash that collateralizes the letters of credit is
included in Restricted cash on the Consolidated Balance Sheets.
CONTINGENTLY CONVERTIBLE SECURITIES: At June 30, 2004, we have contingently
convertible debt and equity securities outstanding. The significant terms of
these securities are as follows:
Convertible Senior Notes: Our $150 million 3.375 percent convertible senior
notes are putable to CMS Energy by the note holders at par on July 15, 2008,
July 15, 2013 and July 15, 2018. The notes are convertible to Common Stock at
the option of the holder if the price of our Common Stock remains at or above
$12.81 per share for 20 of 30 consecutive trading days ending on the last
trading day of a quarter. The $12.81 price per share may be adjusted if there is
a payment or distribution to our Common Stockholders. If conversion were to
occur, the notes would be converted into 14.1 million shares of Common Stock
based on the initial conversion rate.
Convertible Preferred Stock: Our $250 million 4.50 percent cumulative
convertible perpetual preferred stock has a liquidation value of $50.00 per
share. The security is convertible to Common Stock at the option of the holder
if the price of our Common Stock remains at or above $11.87 per share for 20 of
30 consecutive trading days ending on the last trading day of a quarter. On or
after December 5, 2008, we may cause the Preferred Stock to convert into Common
Stock if the closing price of our Common Stock remains at or above $12.86 for 20
of any 30 consecutive trading days. The $11.87 and $12.86 prices per share may
be adjusted if there is a payment or distribution to our Common Stockholders. If
conversion were to occur, the securities would be converted into 25.3 million
shares of Common Stock based on the initial conversion rate.
F-37
5: EARNINGS PER SHARE AND DIVIDENDS
The following table presents the basic and diluted earnings per share
computations.
IN MILLIONS, EXCEPT PER SHARE AMOUNTS
-------------------------------------
RESTATED
------------- --------------
THREE MONTHS ENDED JUNE 30 2004 2003
------------------------------------------------------------- ------------- --------------
EARNINGS ATTRIBUTABLE TO COMMON STOCK:
Income (Loss) from Continuing Operations $ 19 $ (12)
Less Preferred Dividends (3) -
------ -------
Income (Loss) from Continuing Operations attributable
to Common Stock - Basic $ 16 $ (12)
Add conversion of Trust Preferred Securities (net of tax) - (a) - (a)
------ -------
Income (Loss) from Continuing Operations attributable
to Common Stock - Diluted $ 16 $ (12)
====== =======
AVERAGE COMMON SHARES OUTSTANDING
APPLICABLE TO BASIC AND DILUTED EPS
CMS Energy:
Average Shares - Basic 161.2 144.1
Add conversion of Trust Preferred Securities - (a) - (a)
Add dilutive Stock Options and Warrants 0.5 (b) - (b)
------ -------
Average Shares - Diluted 161.7 144.1
====== =======
EARNINGS (LOSS) PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO COMMON STOCK
Basic $ 0.10 $ (0.08)
Diluted $ 0.10 $ (0.08)
====== =======
IN MILLIONS, EXCEPT PER SHARE AMOUNTS
-------------------------------------
RESTATED
-------------
SIX MONTHS ENDED JUNE 30 2004 2003
---------------------------------------------------------- ----------- -------------
EARNINGS ATTRIBUTABLE TO COMMON STOCK:
Income from Continuing Operations $ 17 $ 63
Less Preferred Dividends (6) -
------ -------
Income from Continuing Operations attributable
to Common Stock - Basic $ 11 $ 63
Add conversion of Trust Preferred Securities (net of tax) - (a) 5 (a)
------ -------
Income from Continuing Operations attributable
to Common Stock - Diluted $ 11 $ 68
====== =======
AVERAGE COMMON SHARES OUTSTANDING
APPLICABLE TO BASIC AND DILUTED EPS
CMS Energy:
Average Shares - Basic 161.2 144.1
Add conversion of Trust Preferred Securities - (a) 16.6 (a)
Add dilutive Stock Options and Warrants 0.5 (b) - (b)
------ -------
Average Shares - Diluted 161.7 160.7
====== =======
EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO COMMON STOCK
Basic $ 0.07 $ 0.43
Diluted $ 0.07 $ 0.43
====== =======
F-38
(a) Due to antidilution, the computation of diluted earnings per share excluded
the conversion of Trust Preferred Securities into 4.2 million shares of
Common Stock and a $2.2 million reduction of interest expense, net of tax,
for the three months ended June 30, 2004 and the three months ended June
30, 2003 and a $4.3 million reduction of interest expense, net of tax, for
the six months ended June 30, 2004 and the six months ended June 30, 2003.
Effective July 2001, we can revoke the conversion rights if certain
conditions are met.
(b) Since the exercise price was greater than the average market price of the
Common Stock, options and warrants to purchase 5.4 million and 5.1 million
shares of Common Stock were excluded from the computation of diluted EPS
for the three and six months ended June 30, 2004 and the three and six
months ended June 30, 2003, respectively.
Computation of diluted earnings per share for the three months and the six
months ended June 30, 2004 excluded conversion of our $150 million 3.375 percent
convertible senior notes and our 5 million shares of 4.50 percent cumulative
convertible preferred stock. Both are "contingently convertible" securities and,
as of June 30, 2004, none of the stated contingencies have been met. For
additional details on these securities, see Note 4, Financings and
Capitalization.
In January 2003, the Board of Directors suspended the payment of common
stock dividends.
6: FINANCIAL AND DERIVATIVE INSTRUMENTS
FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term investments,
and current liabilities approximate their fair values because of their
short-term nature. We estimate the fair values of long-term financial
instruments based on quoted market prices or, in the absence of specific market
prices, on quoted market prices of similar instruments or other valuation
techniques. The carrying amount of all long-term financial instruments, except
as shown below, approximates fair value. Our held-to-maturity investments
consist of debt securities held by the MCV Partnership totaling $140 million as
of June 30, 2004. These securities represent funds restricted primarily for
future lease payments and are classified as Other Assets on the Consolidated
Balance Sheets. These investments have original maturity dates of approximately
one year or less and, because of their short maturities, their carrying amounts
approximate their fair values. For additional details, see Note 1, Corporate
Structure and Accounting Policies.
IN MILLIONS
-----------------------------------------------------------------------
JUNE 30 2004 2003
--------------------------- --------------------------------- ---------------------------------
FAIR UNREALIZED FAIR UNREALIZED
COST VALUE GAIN(LOSS) COST VALUE GAIN
------ -------- ---------- ------- ------- ----------
Long-term debt (a) $ 6,676 $ 6,834 $ (158) $ 6,594 $ 6,813 $ (219)
Long-term debt - related parties (b) 684 644 40 - - -
Trust Preferred Securities (b) - - - 883 769 114
Available-for-sale securities:
Nuclear decommissioning (c) 434 559 125 453 553 100
SERP 54 66 12 55 61 6
======= ======= ======== ======= ======= ======
(a) Includes a principal amount of $860 million at June 30, 2004 and $532
million at June 30, 2003 relating to current maturities. Settlement of
long-term debt is generally not expected until maturity.
(b) We determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company Obligated Trust Preferred
Securities totaling $663 million that were previously included in mezzanine
equity, have been eliminated due to deconsolidation and are reflected in
Long-term debt - related parties on the Consolidated Balance Sheets. For
additional details, see Note 11, Implementation of New Accounting
Standards. In addition, company obligated Trust Preferred Securities
totaling $220 million have been converted to Common Stock as of August
2003.
(c) On January 1, 2003, we adopted SFAS No. 143 and began classifying our
unrealized gains and losses on nuclear decommissioning investments as
regulatory liabilities. We previously included the unrealized gains and
losses on these investments in accumulated depreciation.
F-39
DERIVATIVE INSTRUMENTS: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, currency exchange
rates, and equity security prices. We manage these risks using established
policies and procedures, under the direction of both an executive oversight
committee consisting of senior management representatives and a risk committee
consisting of business-unit managers. We may use various contracts to manage
these risks including swaps, options, futures and forward contracts.
We intend that any gains or losses on these contracts will be offset by an
opposite movement in the value of the item at risk. Risk management contracts
are classified as either trading or other than trading. These contracts contain
credit risk if the counterparties, including financial institutions and energy
marketers, fail to perform under the agreements. We minimize such risk by
performing financial credit reviews using, among other things, publicly
available credit ratings of such counterparties.
Contracts used to manage interest rate, foreign currency, and commodity
price risk may be considered derivative instruments that are subject to
derivative and hedge accounting pursuant to SFAS No. 133. If a contract is
accounted for as a derivative instrument, it is recorded in the financial
statements as an asset or a liability, at the fair value of the contract. The
recorded fair value of the contract is then adjusted quarterly to reflect any
change in the market value of the contract, a practice known as marking the
contract to market. Changes in the fair value of a derivative (that is, gains or
losses) are reported either in earnings or accumulated other comprehensive
income depending on whether the derivative qualifies for special hedge
accounting treatment.
For derivative instruments to qualify for hedge accounting under SFAS No.
133, the hedging relationship must be formally documented at inception and be
highly effective in achieving offsetting cash flows or offsetting changes in
fair value attributable to the risk being hedged. If hedging a forecasted
transaction, the forecasted transaction must be probable. If a derivative
instrument, used as a cash flow hedge, is terminated early because it is
probable that a forecasted transaction will not occur, any gain or loss as of
such date is immediately recognized in earnings. If a derivative instrument,
used as a cash flow hedge, is terminated early for other economic reasons, any
gain or loss as of the termination date is deferred and recorded when the
forecasted transaction affects earnings. We use a combination of quoted market
prices and mathematical valuation models to determine fair value of those
contracts requiring derivative accounting. The ineffective portion, if any, of
all hedges is recognized in earnings.
The majority of our contracts are not subject to derivative accounting
because they qualify for the normal purchases and sales exception of SFAS No.
133, or are not derivatives because there is not an active market for the
commodity. Certain of our electric capacity and energy contracts are not
accounted for as derivatives due to the lack of an active energy market in the
state of Michigan, as defined by SFAS No. 133, and the significant
transportation costs that would be incurred to deliver the power under the
contracts to the closest active energy market at the Cinergy hub in Ohio. If an
active market develops in the future, we may be required to account for these
contracts as derivatives. The mark-to-market impact on earnings related to these
contracts could be material to the financial statements.
F-40
Derivative accounting is required for certain contracts used to limit our
exposure to commodity price risk and interest rate risk. The following table
reflects the fair value of all contracts requiring derivative accounting:
IN MILLIONS
---------------------------------------------------------
JUNE 30 2004 2003
----------------------------------------- --------------------------- -------------------------
FAIR UNREALIZED FAIR UNREALIZED
DERIVATIVE INSTRUMENTS COST VALUE GAIN (LOSS) COST VALUE GAIN (LOSS)
----------------------------------------- ---- ----- ---------- ---- ----- ----------
Other than trading
Electric - related contracts $ - $ - $ - $ 8 $ - $ (8)
Gas contracts 3 6 3 2 1 (1)
Interest rate risk contracts - (2) (2) - - -
Derivative contracts associated with
Consumers' investment in the MCV Partnership:
Prior to consolidation - - - - 20 20
After consolidation:
Gas fuel contracts - 80 80 - - -
Gas fuel futures, options, and swaps - 54 54 - - -
Trading
Electric / gas contracts (5) 10 15 - 15 15
Derivative contracts associated with equity
investments in:
Shuweihat - (19) (19) - (39) (39)
Taweelah (35) (19) 16 - (36) (36)
Jorf Lasfar - (10) (10) - (14) (14)
Other - (1) (1) - (4) (4)
==== ==== === ==== ===== ======
The fair value of our other than trading derivative contracts is included in
Derivative Instruments, Other Assets, or Other Liabilities on the Consolidated
Balance Sheets. The fair value of our trading derivative contracts is included
in either Price Risk Management Assets or Price Risk Management Liabilities on
the Consolidated Balance Sheets. The fair value of derivative contracts
associated with our equity investments is included in Enterprises Investments on
the Consolidated Balance Sheets. The fair value of derivative contracts
associated with our investment in the MCV Partnership for 2003 is included in
Investments - Midland Cogeneration Venture Limited Partnership on the
Consolidated Balance Sheets.
ELECTRIC CONTRACTS: Our electric utility business uses purchased electric
call option contracts to meet, in part, our regulatory obligation to serve. This
obligation requires us to provide a physical supply of electricity to customers,
to manage electric costs, and to ensure a reliable source of capacity during
peak demand periods.
GAS CONTRACTS: Our gas utility business uses fixed price and index-based gas
supply contracts, fixed price weather-based gas supply call options, fixed price
gas supply call and put options, and other types of contracts, to meet our
regulatory obligation to provide gas to our customers at a reasonable and
prudent cost. Unrealized gains and losses associated with these options are
reported directly in earnings as part of other income, and then directly offset
in earnings and recorded on the balance sheet as a regulatory asset or liability
as part of the GCR process.
INTEREST RATE RISK CONTRACTS: We use interest rate swaps to hedge the risk
associated with forecasted interest payments on variable-rate debt and to reduce
the impact of interest rate fluctuations. Most of our interest rate swaps are
designated as cash flow hedges. As such, we record changes in the fair value of
these contracts in accumulated other comprehensive income unless the swaps are
sold. For interest rate swaps that did not qualify for hedge accounting
treatment, we record changes in the fair value of these contracts in Other
income.
F-41
The following table reflects the outstanding floating-to-fixed interest
rates swaps:
IN MILLIONS
-------------------------------------
FLOATING TO FIXED NOTIONAL MATURITY FAIR
INTEREST RATE SWAPS AMOUNT DATE VALUE
--------------------- -------- --------- -----
June 30, 2004 $ 26 2005-2006 $ (2)
==== ========= ====
June 30, 2003 3 2006 -
==== ========= ====
Notional amounts reflect the volume of transactions but do not represent the
amount exchanged by the parties to the financial instruments. Accordingly,
notional amounts do not necessarily reflect our exposure to credit or market
risks. The weighted average interest rate associated with outstanding swaps was
approximately 7.3 percent at June 30, 2004 and 9.0 percent at June 30, 2003.
There was no ineffectiveness associated with any of the interest rate swaps
that qualified for hedge accounting treatment. As of June 30, 2004, we have
recorded an unrealized loss of $1 million, net of tax, in accumulated other
comprehensive income related to interest rate risk contracts accounted for as
cash flow hedges. We expect to reclassify $1 million of this amount as a
decrease to earnings during the next 12 months primarily to offset the
variable-rate interest expense on hedged debt.
Certain equity method investees have issued interest rate swaps to hedge the
risk associated with variable-rate debt, as listed in the table under
"Derivative Instruments" within this Note. These instruments are not included in
this analysis, but can have an impact on financial results. The accounting for
these instruments depends on whether they qualify for cash flow hedge accounting
treatment. The interest rate swap held by Taweelah and certain interest rate
swaps held by Shuweihat do not qualify as cash flow hedges, and therefore, we
record our proportionate share of the change in the fair value of these
contracts in Earnings from Equity Method Investees. The remainder of these
instruments do qualify as cash flow hedges, and we record our proportionate
share of the change in the fair value of these contracts in accumulated other
comprehensive income.
DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV
PARTNERSHIP:
Gas Fuel Contracts: The MCV Partnership uses natural gas fuel contracts to
buy gas as fuel for generation, and to manage gas fuel costs. The MCV
Partnership believes that its long-term natural gas contracts, which do not
contain volume optionality, qualify under SFAS No. 133 for the normal purchases
and normal sales exception. Therefore, these contracts are currently not
recognized at fair value on the balance sheet. Should significant changes in the
level of the MCV Facility operational dispatch or purchases of long-term gas
occur, the MCV Partnership would be required to re-evaluate its accounting
treatment for these long-term gas contracts. This re-evaluation may result in
recording mark-to-market activity on some contracts, which could add to earnings
volatility.
At June 30, 2004, the MCV Partnership had six long-term gas contracts that
contained both an option and forward component. Because of the option component,
these contracts do not qualify for the normal purchases and sales exception and
are accounted for as derivatives, with changes in fair value recorded in
earnings each quarter. The MCV Partnership expects future earnings volatility on
these six contracts, since gains or losses will be recorded on a quarterly basis
during the remaining life of approximately four years for these gas contracts.
For the six months ended June 30, 2004, the MCV Partnership recorded in Fuel for
electric generation a $6 million net gain in earnings associated with these
contracts.
Gas Fuel Futures, Options, and Swaps: To manage market risks associated with
the volatility of natural gas prices, the MCV Partnership maintains a gas
hedging program. The MCV Partnership enters into natural gas futures contracts,
option contracts, and over-the-counter swap transactions in order to hedge
against unfavorable changes in the market price of natural gas in future months
when gas is expected to be needed. These financial instruments are being used
principally to secure anticipated natural gas requirements necessary for
projected electric and steam sales, and to lock in sales prices of natural gas
previously obtained in order to optimize the MCV Partnership's existing gas
supply, storage, and transportation arrangements.
These financial instruments are accounted for as derivatives under SFAS No.
133. The contracts that are used to secure anticipated natural gas requirements
necessary for projected electric and steam sales qualify as cash flow hedges
under SFAS No. 133. The MCV Partnership also engages in cost mitigation
activities to offset the fixed
F-42
charges the MCV Partnership incurs in operating the MCV Facility. These cost
mitigation activities include the use of futures and options contracts to
purchase and/or sell natural gas to maximize the use of the transportation and
storage contracts when it is determined that they will not be needed for the MCV
Facility operation. Although these cost mitigation activities do serve to offset
the fixed monthly charges, these cost mitigation activities are not considered a
normal course of business for the MCV Partnership and do not qualify as hedges
under SFAS No. 133. Therefore, the mark-to-market gains and losses from these
cost mitigation activities are recorded in earnings each quarter.
For the six months ended June 30, 2004, the MCV Partnership has recorded an
unrealized gain of $24 million in other comprehensive income on those futures
contracts that qualify as cash flow hedges, which resulted in a cumulative net
gain of $55 million in other comprehensive income as of June 30, 2004. This
balance represents natural gas futures, options, and swaps with maturities
ranging from July 2004 to December 2009, of which $34 million of this gain is
expected to be reclassified as an increase to earnings within the next 12
months. As of June 30, 2004, Consumers' pretax proportionate share of the MCV
Partnership's $55 million net gain recorded in other comprehensive income is $27
million, of which $17 million is expected to be reclassified as an increase to
earnings within the next 12 months. In addition, for the six months ended June
30, 2004, the MCV Partnership has recorded a net gain of $16 million in earnings
from hedging activities related to natural gas requirements for the MCV Facility
operations and a net gain of $1 million in earnings from cost mitigation
activities.
TRADING ACTIVITIES: Through December 31, 2002, our wholesale power and gas
trading activities were accounted for under the mark-to-market method of
accounting in accordance with EITF Issue No. 98-10. Effective January 1, 2003,
EITF Issue No. 98-10 was rescinded and replaced by EITF Issue No. 02-03. As a
result, only energy contracts that meet the definition of a derivative under
SFAS No. 133 are to be carried at fair value. The impact of this change was
recognized as a cumulative effect of a change in accounting principle loss of
$23 million, net of tax, for the three month period ended March 31, 2003.
During 2003, we sold a majority of our wholesale natural gas and
power-trading portfolio, and exited the energy services and retail customer
choice business. As a result, our trading activities have been significantly
reduced. Our current activities center around entering into energy contracts
that are related to the activities considered to be an integral part of our
ongoing operations. The intent of holding these energy contracts is to optimize
the financial performance of our owned generating assets and to fulfill
contractual obligations. These contracts are classified as trading activities in
accordance with EITF No. 02-03 and are accounted for using the criteria defined
in SFAS No. 133. Energy trading contracts that meet the definition of a
derivative are recorded as assets or liabilities in the financial statements at
the fair value of the contracts. Gains or losses arising from changes in fair
value of these contracts are recognized in earnings as a component of operating
revenues in the period in which the changes occur. Energy trading contracts that
do not meet the definition of a derivative are accounted for as executory
contracts (i.e., on an accrual basis).
The market prices we use to value our energy trading contracts reflect our
consideration of, among other things, closing exchange and over-the-counter
quotations. In certain contracts, long-term commitments may extend beyond the
period in which market quotations for such contracts are available. Mathematical
models are developed to determine various inputs into the fair value calculation
including price and other variables that may be required to calculate fair
value. Realized cash returns on these commitments may vary, either positively or
negatively, from the results estimated through application of the mathematical
model. Market prices are adjusted to reflect the impact of liquidating our
position in an orderly manner over a reasonable period of time under present
market conditions.
In connection with the market valuation of our energy trading contracts, we
maintain reserves for credit risks based on the financial condition of
counterparties. We also maintain credit policies that management believes will
minimize its overall credit risk with regard to our counterparties.
Determination of our counterparties' credit quality is based upon a number of
factors, including credit ratings, disclosed financial condition, and collateral
requirements. Where contractual terms permit, we employ standard agreements that
allow for netting of positive and negative exposures associated with a single
counterparty. Based on these policies, our current exposures, and our credit
reserves, we do not anticipate a material adverse effect on our financial
position or results of operations as a result of counterparty nonperformance.
F-43
FOREIGN EXCHANGE DERIVATIVES: We may use forward exchange and option
contracts to hedge certain receivables, payables, long-term debt, and equity
value relating to foreign investments. The purpose of our foreign currency
hedging activities is to protect the company from the risk associated with
adverse changes in currency exchange rates that could affect cash flow
materially. These contracts would not subject us to risk from exchange rate
movements because gains and losses on such contracts offset losses and gains,
respectively, on assets and liabilities being hedged. At June 30, 2004 and June
30, 2003, we had no outstanding foreign exchange contracts.
As of June 30, 2004, Taweelah, one of our equity method investees, held a
foreign exchange contract that hedged the foreign currency risk associated with
payments to be made under an operating and maintenance service agreement. This
contract did not qualify as a cash flow hedge; and therefore, we record our
proportionate share of the change in the fair value of the contract in Earnings
from Equity Method Investees.
7: RETIREMENT BENEFITS
We provide retirement benefits to our employees under a number of different
plans, including:
- non-contributory, defined benefit Pension Plan,
- a cash balance pension plan for certain employees hired after June 30,
2003,
- benefits to certain management employees under SERP,
- health care and life insurance benefits under OPEB,
- benefits to a select group of management under EISP, and
- a defined contribution 401(k) plan.
Pension Plan: The Pension Plan includes funds for our employees and our
non-utility affiliates, including former Panhandle employees. The Pension Plan's
assets are not distinguishable by company.
As of June 30, 2004, we have recorded a prepaid pension asset of $398
million, $20 million of which is in Other current assets on our Consolidated
Balance Sheet.
OPEB: We adopted SFAS No. 106, effective as of the beginning of 1992.
Consumers recorded a liability of $466 million for the accumulated transition
obligation and a corresponding regulatory asset for anticipated recovery in
utility rates. For additional details, see Note 1, Corporate Structure and
Accounting Policies, "Utility Regulation." In 1994, the MPSC authorized recovery
of the electric utility portion of these costs over 18 years and in 1996, the
MPSC authorized recovery of the gas utility portion of these costs over 16
years. We have made contributions of $33 million to our 401(h) and VEBA trust
funds in 2004. We plan to make additional contributions of $30 million in 2004.
F-44
Costs: The following table recaps the costs incurred in our retirement
benefits plans:
IN MILLIONS
--------------------------------------------
PENSION
--------------------------------------------
THREE MONTHS ENDED SIX MONTHS ENDED
------------------- ------------------
JUNE 30 2004 2003 2004 2003
----- ----- ---- ----
Service cost $ 9 $ 9 $ 19 $ 19
Interest expense 18 18 36 37
Expected return on plan assets (27) (21) (54) (41)
Amortization of:
Net loss 4 3 7 5
Prior service cost 2 2 3 4
---- ---- ---- ----
Net periodic pension cost $ 6 $ 11 $ 11 $ 24
Service cost $ 5 $ 6 $ 10 $ 11
Interest expense 14 16 29 33
Expected return on plan assets (12) (10) (24) (21)
Amortization of:
Net loss 3 5 5 10
Prior service cost (2) (2) (5) (4)
---- ---- ---- ----
Net periodic postretirement benefit cost $ 8 $ 15 $ 15 $ 29
==== ==== ==== ====
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003
(the Act) was signed into law in December 2003. The Act establishes a
prescription drug benefit under Medicare (Medicare Part D) and a federal
subsidy, which is exempt from federal taxation, to sponsors of retiree health
care benefit plans that provide a benefit that is actuarially equivalent to
Medicare Part D.
We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004 in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $158 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months ended June 30, 2004,
$12 million for the six months ended June 30, 2004, and an expected total
reduction of $24 million for 2004. The reduction of $24 million includes $7
million in capitalized OPEB costs. For additional details, see Note 11,
Implementation of New Accounting Standards.
8: EQUITY METHOD INVESTMENTS
Where ownership is more than 20 percent but less than a majority, we account
for certain investments in other companies, partnerships and joint ventures by
the equity method of accounting in accordance with APB Opinion No. 18. Net
income from these investments included undistributed earnings of $38 million for
the three months ended June 30, 2004 and $36 million for the three months ended
June 30, 2003 and $44 million for the six months ended June 30, 2004 and $69
million for the six months ended June 30, 2003. The most significant of these
investments is our 50 percent interest in Jorf Lasfar, our 45 percent interest
in SCP, and our 40 percent interest in Taweelah. Summarized income statement
information for our most significant equity method investments is as follows:
INCOME STATEMENT DATA
IN MILLIONS
-------------------------------------------------
JORF
THREE MONTHS ENDED JUNE 30, 2004 LASFAR SCP TAWEELAH TOTAL
--------------------------------- ------ ----- -------- ------
Operating revenue $ 102 $ 18 $ 26 $ 146
Operating expenses (56) (5) (12) (73)
----- ---- ----- -----
Operating income 46 13 14 73
Other income (expense), net (14) (5) 33 14
----- ---- ----- -----
Net income $ 32 $ 8 $ 47 $ 87
===== ==== ===== =====
F-45
\
IN MILLIONS
--------------------------------------------------
JORF
THREE MONTHS ENDED JUNE 30, 2003 LASFAR SCP TAWEELAH TOTAL
-------------------------------- ------- -------- -------- --------
Operating revenue $ 91 $ 13 $ 25 $ 129
Operating expenses (43) (4) (9) (56)
-------- -------- -------- --------
Operating income 48 9 16 73
Other expense, net (5) (5) (24) (34)
-------- -------- -------- --------
Net income (loss) $ 43 $ 4 $ (8) $ 39
======== ======== ======== ========
INCOME STATEMENT DATA
IN MILLIONS
--------------------------------------------------
JORF
SIX MONTHS ENDED JUNE 30, 2004 LASFAR SCP TAWEELAH TOTAL
------------------------------ -------- -------- -------- --------
Operating revenue $ 212 $ 37 $ 48 $ 297
Operating expenses (121) (10) (22) (153)
-------- -------- -------- --------
Operating income 91 27 26 144
Other income (expense), net (29) (12) 8 (33)
-------- -------- -------- --------
Net income $ 62 $ 15 $ 34 $ 111
======== ======== ======== ========
IN MILLIONS
--------------------------------------------------
JORF
SIX MONTHS ENDED JUNE 30, 2003 LASFAR SCP TAWEELAH TOTAL
------------------------------ -------- -------- -------- --------
Operating revenue $ 181 $ 25 $ 48 $ 254
Operating expenses (86) (8) (18) (112)
-------- -------- -------- --------
Operating income 95 17 30 142
Other expense, net (24) (9) (26) (59)
-------- -------- -------- --------
Net income $ 71 $ 8 $ 4 $ 83
======== ======== ======== ========
9: REPORTABLE SEGMENTS
Our reportable segments consist of business units organized and managed by
their products and services. We evaluate performance based upon the net income
of each segment. We operate principally in three reportable segments: electric
utility, gas utility, and enterprises.
The electric utility segment consists of the generation and distribution
of electricity in the state of Michigan through our subsidiary, Consumers. The
gas utility segment consists of regulated activities associated with the
transportation, storage, and distribution of natural gas in the state of
Michigan through our subsidiary, Consumers. The enterprises segment consists of:
- investing in, acquiring, developing, constructing, managing, and
operating non-utility power generation plants and natural gas
facilities in the United States and abroad, and
- providing gas, oil, and electric marketing services to energy users.
The following tables show our financial information by reportable segment.
The "Other" net income segment includes corporate interest and other,
discontinued operations, and the cumulative effect of accounting changes.
REVENUES
IN MILLIONS
----------------------
RESTATED
THREE MONTHS ENDED JUNE 30 2004 2003
-------------------------- -------- --------
Electric utility $ 611 $ 602
Gas utility 300 299
Enterprises 182 225
-------- --------
$ 1,093 $ 1,126
======== ========
F-46
NET INCOME (LOSS) AVAILABLE TO COMMON STOCK
IN MILLIONS
----------------------
RESTATED
THREE MONTHS ENDED JUNE 30 2004 2003
-------------------------- -------- --------
Electric utility $ 27 $ 35
Gas utility 1 5
Enterprises 38 8
Other (50) (113)
-------- --------
$ 16 $ (65)
======== ========
REVENUES
IN MILLIONS
----------------------
RESTATED
SIX MONTHS ENDED JUNE 30 2004 2003
------------------------ -------- --------
Electric utility $ 1,241 $ 1,252
Gas utility 1,205 1,088
Enterprises 401 754
-------- --------
$ 2,847 $ 3,094
======== ========
NET INCOME (LOSS) AVAILABLE TO COMMON STOCK
IN MILLIONS
----------------------
RESTATED
SIX MONTHS ENDED JUNE 30 2004 2003
------------------------ -------- --------
Electric utility $ 75 $ 86
Gas utility 57 59
Enterprises (23) 29
Other (100) (157)
-------- --------
$ 9 $ 17
======== ========
TOTAL ASSETS
IN MILLIONS
----------------------
RESTATED
JUNE 30 2004 2003
------- -------- --------
Electric utility $ 6,935 $ 6,603
Gas utility 2,886 2,586
Enterprises 5,030 4,277
Other 456 473
-------- --------
$ 15,307 $ 13,939
======== ========
10: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143: This standard became effective January 2003. It requires
companies to record the fair value of the cost to remove assets at the end of
their useful life, if there is a legal obligation to do so. We have legal
obligations to remove some of our assets, including our nuclear plants, at the
end of their useful lives.
Before adopting this standard, we classified the removal cost of assets
included in the scope of SFAS No. 143 as part of the reserve for accumulated
depreciation. For these assets, the removal cost of $448 million that was
classified as part of the reserve at December 31, 2002, was reclassified in
January 2003, in part, as a:
- $364 million ARO liability,
- $134 million regulatory liability,
- $42 million regulatory asset, and
- $7 million net increase to property, plant, and equipment as
prescribed by SFAS No. 143.
We are reflecting a regulatory asset and liability as required by SFAS No.
71 for regulated entities instead of a cumulative effect of a change in
accounting principle.
F-47
The fair value of ARO liabilities has been calculated using an expected
present value technique. This technique reflects assumptions, such as costs,
inflation, and profit margin that third parties would consider to assume the
settlement of the obligation. Fair value, to the extent possible, should include
a market risk premium for unforeseeable circumstances. No market risk premium
was included in our ARO fair value estimate since a reasonable estimate could
not be made. If a five percent market risk premium were assumed, our ARO
liability would increase by $22 million.
If a reasonable estimate of fair value cannot be made in the period the
ARO is incurred, such as for assets with indeterminate lives, the liability is
to be recognized when a reasonable estimate of fair value can be made.
Generally, transmission and distribution assets have indeterminate lives.
Retirement cash flows cannot be determined and there is a low probability of a
retirement date. Therefore, no liability has been recorded for these assets.
Also, no liability has been recorded for assets that have insignificant
cumulative disposal costs, such as substation batteries. The measurement of the
ARO liabilities for Palisades and Big Rock are based on decommissioning studies
that largely utilize third-party cost estimates.
In addition, in 2003, we recorded an ARO liability for certain pipelines
and non-utility generating plants and a $1 million, net of tax, cumulative
effect of change in accounting for accretion and depreciation expense for ARO
liabilities incurred prior to 2003.
The following tables describe our assets that have legal obligations to be
removed at the end of their useful life:
JUNE 30, 2004
IN MILLIONS
----------------------------------------------------------------
IN SERVICE TRUST
ARO DESCRIPTION DATE LONG LIVED ASSETS FUND
----------------------------------------- ----------------------------------------------------------------
Palisades-decommission plant site 1972 Palisades nuclear plant $ 495
Big Rock-decommission plant site 1962 Big Rock nuclear plant 64
JHCampbell intake/discharge water line 1980 Plant intake/discharge water line -
Closure of coal ash disposal areas Various Generating plants coal ash areas -
Closure of wells at gas storage fields Various Gas storage fields -
Indoor gas services equipment relocations Various Gas meters located inside structures -
Closure of gas pipelines Various Gas transmission pipelines -
Dismantle natural gas-fired power plant 1997 Gas fueled power plant -
JUNE 30, 2004
IN MILLIONS
----------------------------------------------------------------------------
ARO LIABILITY ARO
------------------ CASH FLOW LIABILITY
ARO DESCRIPTION 1/1/03 12/31/03 INCURRED SETTLED ACCRETION REVISIONS 6/30/04
------------------------------- ------ -------- -------- ------- --------- --------- ---------
Palisades-decommission $ 249 $ 268 $ - $ - $ 10 $ 31 $ 309
Big Rock-decommission 61 35 - (24) 6 22 39
JHCampbell intake line - - - - - - -
Coal ash disposal areas 51 52 - (1) 3 - 54
Wells at gas storage fields 2 2 - - - - 2
Indoor gas services relocations 1 1 - - - - 1
Closure of gas pipelines (a) 8 - - - - - -
Natural gas-fired power plant 1 1 - - 1 - 2
------ ------ --- ----- ------ ------- ------
Total $ 373 $ 359 $ - $ (25) $ 20 $ 53 $ 407
====== ====== === ===== ====== ======= ======
(a) ARO Liability was settled in 2003 as a result of the sales of Panhandle and
CMS Field Services.
The Palisades and Big Rock cash flow revisions resulted from new
decommissioning reports filed with the MPSC in March 2004. For additional
details, see Note 3, Uncertainties, "Other Consumers' Electric Utility
Uncertainties - Nuclear Plant Decommissioning."
Reclassification of certain types of Cost of Removal: Beginning in
December 2003, the SEC requires the quantification and reclassification of the
estimated cost of removal obligations arising from other than legal
F-48
obligations. These cost of removal obligations have been accrued through
depreciation charges. We estimate that we had $1.016 billion at June 30, 2004
and $950 million at June 30, 2003 of previously accrued asset removal costs
related to our regulated obligations arising from other than legal operations.
These obligations, which were previously classified as a component of
accumulated depreciation, are now classified as regulatory liabilities in the
accompanying Consolidated Balance Sheets.
11: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES:
The FASB issued this Interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46.
For entities that have not previously adopted FASB Interpretation No. 46,
Revised FASB Interpretation No. 46 provided an implementation deferral until the
first quarter of 2004. As of and for the quarter ended March 31, 2004, we
adopted Revised FASB Interpretation No. 46 for all entities.
We determined that we are the primary beneficiary of both the MCV
Partnership and the FMLP. We have a 49 percent partnership interest in the MCV
Partnership and a 46.4 percent partnership interest in the FMLP. Consumers is
the primary purchaser of power from the MCV Partnership through a long-term
power purchase agreement. In addition, the FMLP holds a 75.5 percent lessor
interest in the MCV Facility, which results in Consumers holding a 35 percent
lessor interest in the MCV Facility. Collectively, these interests make us the
primary beneficiary of these entities. As such, we consolidated their assets,
liabilities, and activities into our financial statements for the first time as
of and for the quarter ended March 31, 2004. These partnerships have third-party
obligations totaling $728 million at June 30, 2004. Property, plant, and
equipment serving as collateral for these obligations has a carrying value of
$1.453 billion at June 30, 2004. The creditors of these partnerships do not have
recourse to the general credit of CMS Energy.
At December 31, 2003, we determined that we are the primary beneficiary of
three other entities that are determined to be variable interest entities. We
have 50 percent partnership interest in the T.E.S. Filer City Station Limited
Partnership, the Grayling Generating Station Limited Partnership, and the
Genesee Power Station Limited Partnership. Additionally, we have operating and
management contracts and are the primary purchaser of power from each
partnership through long-term power purchase agreements. Collectively, these
interests make us the primary beneficiary as defined by the Interpretation.
Therefore, we consolidated these partnerships into our consolidated financial
statements for the first time as of December 31, 2003. These partnerships have
third-party obligations totaling $118 million at June 30, 2004. Property, plant,
and equipment serving as collateral for these obligations has a carrying value
of $169 million as of June 30, 2004. Other than outstanding letters of credit
and guarantees of $5 million, the creditors of these partnerships do not have
recourse to the general credit of CMS Energy.
We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company Obligated Trust Preferred
Securities totaling $663 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $684 million of long-term debt - related parties
and reflected an investment in related parties of $21 million.
We are not required to restate prior periods for the impact of this
accounting change.
Additionally, we have variable interest entities in which we are not the
primary beneficiary. FASB Interpretation No. 46 requires us to disclose certain
information about these entities. The chart below details our involvement in
these entities at June 30, 2004:
F-49
INVESTMENT OPERATING TOTAL
NAME (OWNERSHIP NATURE OF THE INVOLVEMENT BALANCE AGREEMENT WITH GENERATING
INTEREST) ENTITY COUNTRY DATE (IN MILLIONS) CMS ENERGY CAPACITY
--------------- ------------- ---------- ----------- ------------- -------------- ----------
Taweelah (40%) Generator United Arab 1999 $ 93 Yes 777 MW
Emirates
Jubail (25%) Generator - Saudi Arabia 2001 $ - Yes 250 MW
Under
Construction
Shuweihat (20%) Generator - United Arab 2001 $ (16)(a) Yes 1,500 MW
Under Emirates
Construction
--------------- ------------ ------------ ---- ----- --- --------
Total $ 77 2,527 MW
=============== ============ ============ ==== ===== === ========
(a) At June 30, 2004, we carried a negative investment in Shuweihat. The
balance is comprised of our investment of $3 million reduced by our
proportionate share of the negative fair value of derivative instruments
of $19 million. We are required to record the negative investment due to
our future commitment to make an equity investment in Shuweihat.
Our maximum exposure to loss through our interests in these variable
interest entities is limited to our investment balance of $77 million, and
letters of credit, guarantees, and indemnities relating to Taweelah and
Shuweihat totaling $129 million. Included in that total is a letter of credit
relating to our required initial investment in Shuweihat of $70 million. We plan
to contribute our initial investment when the project becomes commercially
operational in 2004.
FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE
REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND
MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and
Modernization Act of 2003 (the Act) was signed into law in December 2003. The
Act establishes a prescription drug benefit under Medicare (Medicare Part D) and
a federal subsidy, which is exempt from federal taxation, to sponsors of retiree
health care benefit plans that provide a benefit that is actuarially equivalent
to Medicare Part D. At December 31, 2003, we elected a one-time deferral of the
accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1.
The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff
Position, No. SFAS 106-1 and provides further accounting guidance. FASB Staff
Position, No. SFAS 106-2 states that for plans that are actuarially equivalent
to Medicare Part D, employers' measures of accumulated postretirement benefit
obligations and postretirement benefit costs should reflect the effects of the
Act.
We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $158 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months ended June 30, 2004,
$12 million for the six months ended June 30, 2004, and an expected total
reduction of $24 million for 2004. Consumers capitalizes a portion of OPEB cost
in accordance with regulatory accounting. As such, the remeasurement resulted in
a net reduction of OPEB expense of $4 million, or $0.03 per share, for the three
months ended June 30, 2004, $9 million, or $0.05 per share, for the six months
ended June 30, 2004, and an expected total net expense reduction of $17 million
for 2004.
EITF NO. 03-6, PARTICIPATING SECURITIES AND THE TWO-CLASS METHOD UNDER
SFAS NO. 128: EITF No. 03-6, effective June 30, 2004, addresses the treatment of
participating securities in earnings per share calculations. This EITF defines
participating securities and describes their treatment using a two-class method
of calculating earnings per share. Since we have not issued any participating
securities, as defined by EITF No. 03-6 and SFAS No. 128, there was no impact on
earnings per share upon adoption.
F-50
CMS ENERGY CORPORATION
SELECTED FINANCIAL INFORMATION
CMS ENERGY CORPORATION
----------------------------------------------------------
RESTATED RESTATED RESTATED
2003 2002(E) 2001(E) 2000(E) 1999
---- -------- -------- -------- ----
Operating revenue (in millions)...................................... ($) 5,513 8,673 8,006 6,623 5,114
Earnings from equity method investees (in millions).................. ($) 164 92 172 213 136
Income (loss) from continuing operations (in millions)............... ($) (43) (394) (327) (85) 191
Cumulative effect of change in accounting (in millions).............. ($) (24) 18 (4) -- --
Consolidated net income (loss) (in millions)......................... ($) (44) (650) (459) 5 277
Average common shares outstanding (in thousands)..................... 150,434 139,047 130,758 113,128 110,140
Income (loss) from continuing operations per average common share
CMS Energy -- Basic................................................ ($) (0.30) (2.84) (2.50) (0.76) 1.66(a)
-- Diluted... .......................................... ($) (0.30) (2.84) (2.50) (0.76) 1.66(a)
Class G -- Basic and Diluted...................................... ($) -- -- -- -- 4.21(a)
Cumulative effect of change in accounting per average common share
CMS Energy -- Basic................................................ ($) (0.16) 0.13 (0.03) -- --(a)
-- Diluted.............................................. ($) (0.16) 0.13 (0.03) -- --(a)
Net income (loss) per average common share
CMS Energy -- Basic................................................ ($) (0.30) (4.68) (3.51) 0.04 2.18(a)
-- Diluted... .......................................... ($) (0.30) (4.68) (3.51) 0.04 2.17(a)
Class G -- Basic and Diluted....................................... ($) -- -- -- -- 4.21(a)
Cash from (used in) operations (in millions)......................... ($) (251) 614 372 600 917
Capital expenditures, excluding acquisitions, capital lease
additions and DSM (in millions).................................... ($) 535 747 1,239 1,032 1,124
Total assets (in millions)(f)........................................ ($) 13,838 14,781 17,633 17,801 16,336
Long-term debt, excluding current maturities (in millions)........... ($) 6,020 5,357 5,842 6,052 6,428
Long-term debt, related parties (in millions)(b)..................... ($) 684 -- -- -- --
Non-current portion of capital leases (in millions).................. ($) 58 116 71 49 88
Total preferred stock (in millions).................................. ($) 305 44 44 44 44
Total Trust Preferred Securities (in millions)....................... ($) --(b) 883 1,214 1,088 1,119
Cash dividends declared per common share
CMS Energy......................................................... ($) -- 1.09 1.46 1.46 1.39
Class G............................................................ ($) -- -- -- -- 0.99
Market price of common stock at year-end
CMS Energy......................................................... ($) 8.52 9.44 24.03 31.69 31.19
Class G............................................................ ($) -- -- -- -- 24.56(c)
Book value per common share at year-end
CMS Energy......................................................... ($) 9.84 7.48 14.98 19.62 21.17
Number of employees at year-end (full-time equivalents)............ . 8,411 10,477 11,510 11,652 11,462
ELECTRIC UTILITY STATISTICS
Sales (billions of kWh)............................................ 39 39 40 41 41
Customers (in thousands)........................................... 1,754 1,734 1,712 1,691 1,665
Average sales rate per kWh......................................... (C) 6.91 6.88 6.65 6.56 6.54
GAS UTILITY STATISTICS
Sales and transportation deliveries (bcf).......................... 380 376 367 410 389
Customers (in thousands)(d)........................................ 1,671 1,652 1,630 1,611 1,584
Average sales rate per mcf......................................... ($) 6.72 5.67 5.34 4.39 4.52
(a) 1999 earnings per average common share includes allocation of the premium
on redemption of Class G Common Stock of $(0.26) per CMS Energy basic
share, $(0.25) per CMS Energy diluted share and $3.31 per Class G basic
and diluted share.
F-51
(b) Effective December 31, 2003, Trust Preferred Securities are classified on
the balance sheet as Long term debt -- related parties.
(c) Reflects closing price at the October 25, 1999 exchange date.
(d) Excludes off-system transportation customers.
(e) For additional details, see Note 18, Restatement and Reclassification.
(f) For additional details on the reclassification of non-legal
cost-of-removal, see Note 16, Asset Retirement Obligations,
"Reclassification of Non-Legal Cost of Removal." Following is the amount
of cost of removal reclassified from accumulated depreciation to a
regulatory liability by year: $983 million in 2003; $907 million in 2002;
$870 million in 2001; $896 million in 2000; and $874 million in 1999.
F-52
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
YEARS ENDED DECEMBER 31
RESTATED RESTATED
2003 2002 2001
--------- --------- ---------
In Millions
OPERATING REVENUE .................................................. $ 5,513 $ 8,673 $ 8,006
164 92 172
EARNINGS FROM EQUITY METHOD INVESTEES
OPERATING EXPENSES
Fuel for electric generation...................................... 256 341 297
Purchased and interchange power .................................. 689 2,677 1,834
Purchased power -- related parties ............................... 455 564 555
Cost of gas sold ................................................. 1,791 2,745 3,233
Other operating expenses ......................................... 951 915 932
Maintenance ...................................................... 226 212 225
Depreciation, depletion and amortization ......................... 428 412 408
General taxes .................................................... 191 222 220
Asset impairment charges ......................................... 95 602 323
--------- --------- ---------
5,082 8,690 8,027
--------- --------- ---------
OPERATING INCOME (LOSS) ............................................ 595 75 151
OTHER INCOME (DEDUCTIONS)
Accretion expense ................................................ (29) (31) (37)
Gain (loss) on asset sales, net .................................. (3) 37 (2)
Interest and dividends ........................................... 28 15 23
Foreign currency gains (losses), net ............................. 15 (7) (3)
Other income ..................................................... 24 16 11
Other expense .................................................... (21) (30) (5)
14 -- (13)
--------- --------- ---------
FIXED CHARGES
Interest on long-term debt ....................................... 473 404 420
Interest on long-term debt -- related parties .................... 58 -- --
Other interest ................................................... 59 32 83
Capitalized interest ............................................. (9) (16) (35)
Preferred dividends .............................................. 3 2 2
Preferred securities distributions ............................... 10 86 96
--------- --------- ---------
594 508 566
--------- --------- ---------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS ........... 15 (433) (428)
INCOME TAX EXPENSE (BENEFIT) ....................................... 58 (41) (94)
MINORITY INTERESTS ................................................. -- 2 (7)
--------- --------- ---------
LOSS FROM CONTINUING OPERATIONS .................................... (43) (394) (327)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF $50 TAX
EXPENSE IN 2003, $118 TAX BENEFIT IN 2002 AND $92 TAX
EXPENSE IN 2001 .................................................. 23 (274) (128)
--------- --------- ---------
LOSS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE ........................................................ (20) (668) (455)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF $13 TAX
BENEFIT IN 2003, $10 TAX EXPENSE IN 2002 AND $ -- IN 2001
DERIVATIVES (NOTE 7 AND NOTE 15) ................................. (23) 18 (4)
ASSET RETIREMENT OBLIGATION, SFAS NO. 143 (NOTE 16) .............. (1) -- --
--------- --------- ---------
(24) 18 (4)
NET LOSS ........................................................... $ (44) $ (650) $ (459)
========= ========= =========
F-53
YEARS ENDED DECEMBER 31
---------------------------------------
RESTATED RESTATED
2003 2002 2001
--------- --------- ---------
In Millions
EXCEPT PER SHARE AMOUNTS
CMS ENERGY
NET LOSS
Net Loss Available to Common Stock .............................. $ (44) $ (650) $ (459)
========= ========= =========
BASIC LOSS PER AVERAGE COMMON SHARE
Loss from Continuing Operations ................................. $ (0.30) $ (2.84) $ (2.50)
Income (Loss) from Discontinued Operations ...................... 0.16 (1.97) (0.98)
Income (Loss) from Changes in Accounting ........................ (0.16) 0.13 (0.03)
--------- --------- ---------
Net Loss Attributable to Common Stock ........................... $ (0.30) $ (4.68) $ (3.51)
========= ========= =========
DILUTED LOSS PER AVERAGE COMMON SHARE
Loss from Continuing Operations ................................. $ (0.30) $ (2.84) $ (2.50)
Income (Loss) from Discontinued Operations ...................... 0.16 (1.97) (0.98)
Income (Loss) from Changes in Accounting ........................ (0.16) 0.13 (0.03)
--------- --------- ---------
Net Loss Attributable to Common Stock ........................... $ (0.30) $ (4.68) $ (3.51)
========= ========= =========
DIVIDENDS DECLARED PER COMMON SHARE ................................ $ -- $ 1.09 $ 1.46
--------- --------- ---------
The accompanying notes are an integral part of these statements.
F-54
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31
---------------------------------------
RESTATED RESTATED
2003 2002 2001
--------- --------- ---------
IN MILLIONS
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss ................................................................ $ (44) $ (650) $ (459)
Adjustments to reconcile net loss to net cash provided
by operating activities
Depreciation, depletion and amortization (includes
nuclear decommissioning of $6, $6, and $6, respectively) .......... 428 412 408
Depreciation and amortization of discontinued operations ........... 34 73 186
Loss (gain) on disposal of discontinued operations (Note 2) ........ 46 237 (8)
Asset writedowns (Note 2) .......................................... 95 602 323
Capital lease and debt discount amortization ....................... 25 18 11
Accretion expense .................................................. 29 31 37
Bad debt expense ................................................... 28 22 22
Distributions from related parties in excess of (less
than) earnings .................................................... (41) (39) 68
Loss (gain) on sale of assets ...................................... 3 (37) 2
Cumulative effect of accounting changes ............................ 24 (18) 4
Pension contribution ............................................... (560) (64) (65)
Changes in assets and liabilities:
Decrease in accounts receivable and accrued revenue ............. 200 99 337
Decrease (increase) in inventories .............................. (288) 140 (339)
Decrease in accounts payable and accrued expenses ............... (280) (48) (388)
Deferred income taxes and investment tax credit ................. 242 (398) 228
Changes in other assets ......................................... 50 (198) 687
Changes in other liabilities .................................... (242) 432 (682)
--------- --------- ---------
Net cash provided by (used in) operating activities ................ (251) 614 372
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease)........ (535) (747) (1,239)
Investments in partnerships and unconsolidated subsidiaries ............. -- (55) (111)
Cost to retire property ................................................. (72) (66) (118)
Restricted cash ......................................................... (163) (34) (4)
Investments in Electric Restructuring Implementation Plan ............... (8) (8) (13)
Investments in nuclear decommissioning trust funds ...................... (6) (6) (6)
Proceeds from nuclear decommissioning trust funds ....................... 34 30 29
Proceeds from sale of assets ............................................ 939 1,659 134
Other investing ......................................................... 14 56 (21)
--------- --------- ---------
Net cash provided by (used in) investing activities ................ 203 829 (1,349)
--------- --------- ---------
F-55
YEARS ENDED DECEMBER 31
---------------------------------------
RESTATED RESTATED
2003 2002 2001
--------- --------- ---------
IN MILLIONS
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from notes, bonds and other long-term debt ..................... 2,080 725 2,021
Proceeds from trust preferred securities ................................ -- -- 125
Issuance of common stock ................................................ -- -- 326
Issuance of preferred stock ............................................. 272 -- --
Retirement of bonds and other long-term debt ............................ (1,656) (1,834) (1,343)
Common stock repurchased ................................................ -- (8) (5)
Payment of common stock dividends ....................................... -- (149) (190)
Payment of capital lease obligations .................................... (13) (15) (20)
Increase (decrease) in notes payable .................................... (470) 75 21
Other financing ......................................................... 17 (17) 32
--------- --------- ---------
Net cash provided by (used in) financing activities ................ 230 (1,223) 967
--------- --------- ---------
EFFECT OF EXCHANGE RATES ON CASH .......................................... (1) 8 (10)
NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS ............ 181 228 (20)
CASH AND TEMPORARY CASH INVESTMENTS, BEGINNING OF PERIOD .................. 351 123 143
--------- --------- ---------
CASH AND TEMPORARY CASH INVESTMENTS, END OF PERIOD ........................ $ 532 $ 351 $ 123
========= ========= =========
OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND
FINANCING ACTIVITIES WERE:
CASH TRANSACTIONS
Interest paid (net of amounts capitalized) .............................. $ 564 $ 409 $ 447
Income taxes paid (net of refunds) ...................................... (33) (217) (60)
OPEB cash contribution .................................................. 76 84 57
NON-CASH TRANSACTIONS
Nuclear fuel placed under capital leases ................................ $ -- $ -- $ 13
Other assets placed under capital lease ................................. 19 62 37
========= ========= =========
The accompanying notes are an integral part of these statements.
F-56
CMS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31
------------------------
RESTATED
2003 2002
--------- ---------
IN MILLIONS
ASSETS
PLANT AND PROPERTY (AT COST)
Electric utility ........................................................ $ 7,600 $ 7,523
Gas utility ............................................................. 2,875 2,719
Enterprises ............................................................. 895 644
Other ................................................................... 32 45
--------- ---------
11,402 10,931
Less accumulated depreciation, depletion and amortization (Note 16) ..... 4,846 5,385
--------- ---------
6,556 5,546
Construction work-in-progress ........................................... 388 557
--------- ---------
6,944 6,103
--------- ---------
INVESTMENTS
Enterprises Investments ................................................. 724 724
Midland Cogeneration Venture Limited Partnership ........................ 419 388
First Midland Limited Partnership ....................................... 224 255
Other ................................................................... 23 2
--------- ---------
1,390 1,369
--------- ---------
CURRENT ASSETS
Cash and temporary cash investments at cost, which approximates market .. 532 351
Restricted cash ......................................................... 201 38
Accounts receivable, notes receivable and accrued revenue,
less allowances of $29 in 2003 and $15 in 2002 ....................... 367 349
Accounts receivable -- Marketing, services and trading,
less allowances of $11 in 2003 and $8 in 2002 ........................ 36 248
Accounts receivable and notes receivable -- related parties ............. 73 186
Inventories at average cost
Gas in underground storage ........................................... 741 491
Materials and supplies ............................................... 110 96
Generating plant fuel stock .......................................... 41 37
Assets held for sale .................................................... 24 595
Price risk management assets ............................................ 102 115
Prepayments and other ................................................... 267 233
--------- ---------
2,494 2,739
--------- ---------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs .................................................... 648 689
Postretirement benefits .............................................. 162 185
Abandoned Midland project ............................................ 10 11
Other ................................................................ 266 168
Assets held for sale .................................................... 2 2,084
Price risk management assets ............................................ 177 135
Nuclear decommissioning trust funds ..................................... 575 536
Prepaid pension costs ................................................... 388 --
Goodwill ................................................................ 25 31
Notes receivable -- related parties ..................................... 242 160
Notes receivable ........................................................ 125 126
Other ................................................................... 390 445
--------- ---------
3,010 4,570
--------- ---------
TOTAL ASSETS .............................................................. $ 13,838 $ 14,781
========= =========
The accompanying notes are an integral part of these statements.
F-57
CMS ENERGY CORPORATION
DECEMBER 31
------------------------
RESTATED
2003 2002
--------- ---------
IN MILLIONS
STOCKHOLDERS' INVESTMENT AND LIABILITIES
CAPITALIZATION
Common stockholders' equity
Common stock, authorized 250.0 shares; outstanding 161.1
shares in 2003 and 144.1 shares in 2002 .............................. $ 2 $ 1
Other paid-in capital ................................................... 3,846 3,605
Accumulated other comprehensive loss .................................... (419) (728)
Retained deficit ........................................................ (1,844) (1,800)
--------- ---------
1,585 1,078
Preferred stock of subsidiary (Note 5) .................................. 44 44
Preferred stock ......................................................... 261 --
Company-obligated convertible Trust Preferred Securities
of subsidiaries (Note 5) ............................................. -- 393
Company-obligated mandatorily redeemable Trust Preferred
Securities of Consumers' subsidiaries (Note 5) ....................... -- 490
Long-term debt .......................................................... 6,020 5,357
Long-term debt -- related parties (Note 5) .............................. 684 --
Non-current portion of capital leases ................................... 58 116
--------- ---------
8,652 7,478
--------- ---------
MINORITY INTERESTS ........................................................ 73 38
--------- ---------
CURRENT LIABILITIES
Current portion of long-term debt and capital leases .................... 519 646
Notes payable ........................................................... -- 458
Accounts payable ........................................................ 296 377
Accounts payable -- Marketing, services and trading ..................... 21 119
Accounts payable -- related parties ..................................... 40 53
Accrued interest ........................................................ 130 131
Accrued taxes ........................................................... 285 291
Liabilities held for sale ............................................... 2 427
Price risk management liabilities ....................................... 89 96
Current portion of purchase power contracts ............................. 27 26
Current portion of gas supply contract obligations ...................... 29 25
Deferred income taxes ................................................... 27 15
Other ................................................................... 185 225
--------- ---------
1,650 2,889
--------- ---------
NON-CURRENT LIABILITIES
Postretirement benefits ................................................. 265 725
Deferred income taxes ................................................... 615 438
Deferred investment tax credit .......................................... 85 91
Regulatory liabilities for income taxes, net ............................ 312 297
Regulatory liabilities for cost of removal (Note 16) .................... 983 907
Other regulatory liabilities ............................................ 172 4
Asset retirement obligation ............................................. 359 --
Liabilities held for sale ............................................... -- 1,218
Price risk management liabilities ....................................... 175 135
Gas supply contract obligations ......................................... 208 241
Power purchase agreement -- MCV Partnership ............................. -- 27
Other ................................................................... 289 293
--------- ---------
3,463 4,376
--------- ---------
Commitments and Contingencies (Notes 2, 4, 5, 8, 10, 11)
TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES ............................ $ 13,838 $ 14,781
========= =========
F-58
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31
------------------------------------------------------------------
RESTATED RESTATED
2003 2002 2001 2003 2002 2001
------- ------- ------- -------- -------- --------
NUMBER OF SHARES IN THOUSANDS IN MILLIONS
COMMON STOCK
At beginning and end of period............... $ 2 $ 1 $ 1
OTHER PAID-IN CAPITAL
At beginning of period....................... 144,088 132,989 121,201 3,605 3,257 2,936
Common stock repurchased..................... (14) (39) (232) -- (8) (5)
Common stock reacquired...................... (217) (220) (11) (5) (1) (1)
Common stock issued.......................... 17,273 11,358 11,681 234 357 320
Common stock reissued........................ -- -- 350 1 -- 7
Issuance cost of preferred stock............. -- -- -- (8) -- --
Deferred gain (Note 5)....................... -- -- -- 19 -- --
------- ------- ------- -------- -------- -------
At end of period........................ 161,130 144,088 132,989 3,846 3,605 3,257
------- ------- ------- -------- -------- --------
ACCUMULATED OTHER COMPREHENSIVE LOSS
Minimum Pension Liability
At beginning of period.................... (241) -- --
Minimum pension liability
adjustments(a).......................... 241 (241) --
-------- -------- -------
At end of period........................ -- (241) --
-------- -------- -------
Investments
At beginning of period.................... 2 (5) (2)
Unrealized gain (loss) on
investments(a).......................... 6 -- (3)
Realized gain on investments(a)........... -- 7 --
-------- -------- -------
At end of period........................ 8 2 (5)
-------- -------- --------
Derivative Instruments
At beginning of period(b)................. (31) (28) 10
Unrealized gain (loss) on
derivative instruments(a)............... 4 (7) (31)
Reclassification adjustments
included in consolidated net
income (loss)(a)........................ 19 4 (7)
-------- -------- --------
At end of period........................ (8) (31) (28)
-------- -------- --------
FOREIGN CURRENCY TRANSLATION
At beginning of period....................... (458) (233) (206)
Change in foreign currency
translation(a)............................ 39 (225) (27)
-------- -------- --------
At end of period........................ (419) (458) (233)
-------- -------- --------
At end of period..................... (419) (728) (266)
-------- -------- --------
RETAINED DEFICIT (1,800) (1,001) (352)
At beginning of period(c)....................
Consolidated net loss(a)..................... (44) (650) (459)
Common stock dividends declared.............. -- (149) (190)
-------- -------- --------
At end of period........................ (1,844) (1,800) (1,001)
-------- -------- --------
TOTAL COMMON STOCKHOLDERS' EQUITY.............. $ 1,585 $ 1,078 $ 1,991
======== ======== ========
F-59
YEARS ENDED DECEMBER 31
--------------------------------
RESTATED RESTATED
2003 2002 2001
--------- ------------ --------
IN MILLIONS
(a) DISCLOSURE OF OTHER COMPREHENSIVE INCOME (LOSS):
Minimum pension liability
Minimum pension liability adjustments, net of tax
(tax benefit) of $132, $(132), and $ -- , respectively................ $ 241 $ (241) $ --
Investments
Unrealized gain (loss) on investments, net of tax
(tax benefit) of $3, $ -- , and $(2), respectively.................... 6 -- (3)
Realized gain on investments, net of tax of $ -- , $ -- , and $ -- ,
respectively............................................................. -- 7 --
Derivative Instruments
Unrealized gain (loss) on derivative instruments,
net of tax (tax benefit) of $ -- , $(4), and $(13), respectively.... 4 (7) (31)
Reclassification adjustments included in net loss,
net of tax (tax benefit) of $11, $2, and $(3), respectively........ 19 4 (7)
Foreign currency translation, net.......................................... 39 (225) (27)
Consolidated net loss...................................................... (44) (650) (459)
------- --------- --------
Total Other Comprehensive Income (Loss).................................. $ 265 $ (1,112) $ (527)
======= ========= ========
(b) YEAR ENDED DECEMBER 31, 2001 REFLECTS THE CUMULATIVE CHANGE IN ACCOUNTING
PRINCIPLE, NET OF $7 TAX (NOTE 7.)
(c) BEGINNING BALANCE FOR YEAR ENDED DECEMBER 31, 2001 WAS DECREASED BY $38
MILLION DUE TO AN ADJUSTMENT TO DEFERRED TAXES RELATED TO LOY YANG (NOTE 8.)
The accompanying notes are an integral part of these statements.
F-60
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We have determined the need to make certain adjustments to our
consolidated financial statements for the fiscal years ended December 31, 2002,
December 31, 2001, and December 31, 2000. Therefore, the consolidated financial
statements for 2002 and 2001 have been restated from amounts previously
reported. See Note 18, Restatement and Reclassification.
1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES
CORPORATE STRUCTURE: CMS Energy is the parent holding company of Consumers
and Enterprises. Consumers is a combination electric and gas utility company
serving Michigan's Lower Peninsula. Enterprises, through subsidiaries, is
engaged in domestic and international diversified energy businesses including
independent power production, natural gas transmission, storage and processing,
and energy services.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include
the accounts of CMS Energy, Consumers and Enterprises and all other entities in
which we have a controlling financial interest, in accordance with Revised FASB
Interpretation No. 46. Intercompany transactions and balances have been
eliminated. We use the equity method of accounting for investments in companies
and partnerships that are not consolidated where we have significant influence
over operations and financial policies, but not a controlling financial
interest.
USE OF ESTIMATES: We prepare our financial statements in conformity with
accounting principles generally accepted in the United States. Management is
required to make estimates using assumptions that affect the reported amounts
and disclosures. Actual results could differ from those estimates.
We are required to record estimated liabilities in the financial
statements when it is probable that a loss will be incurred in the future as a
result of a current event, and when an amount can be reasonably estimated. We
have used this accounting principle to record estimated liabilities as discussed
in Note 4, Uncertainties.
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of
electricity and natural gas, and the transportation, processing, and storage of
natural gas when services are provided. Sales taxes are recorded as liabilities
and are not included in revenues. Revenues on sales of marketed electricity,
natural gas, and other energy products are recognized at delivery.
Mark-to-market changes in the fair values of energy trading contracts that
qualify as derivatives are recognized as revenues in the periods in which the
changes occur.
CAPITALIZED INTEREST: We are required to capitalize interest on certain
qualifying assets that are undergoing activities to prepare them for their
intended use. Capitalization of interest for the period is limited to the actual
interest cost that is incurred, and our non-regulated businesses are prohibited
from imputing interest costs on any equity funds. Our regulated businesses are
permitted to capitalize an allowance for funds used during construction on
regulated construction projects and to include such amounts in plant in service.
CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with
an original maturity of three months or less are considered cash equivalents. At
December 31, 2003, our restricted cash on hand was $201 million. Restricted cash
primarily includes cash collateral for letters of credit to satisfy certain debt
agreements and cash dedicated for repayment of securitization bonds. It is
classified as a current asset as the related letters of credit mature within one
year and the payments on the related securitization bonds occur within one year.
COAL INVENTORY: We use the weighted average cost method for valuing coal
inventory.
EARNINGS PER SHARE: Basic and diluted earnings per share are based on the
weighted average number of shares of common stock and potential common stock
outstanding during the period. Potential common stock, for purposes of
determining diluted earnings per share, includes the effects of dilutive stock
options and convertible securities. The effect on number of shares of such
potential common stock is computed using the treasury stock method or the
if-converted method, as applicable. For earnings per share computation, see Note
6, Earnings Per Share and Dividends.
F-61
FINANCIAL INSTRUMENTS: We account for investments in debt and equity
securities in accordance with SFAS No. 115. These debt and equity securities are
classified into three categories: held-to-maturity, trading, or
available-for-sale. Our investments in equity securities are classified as
available-for-sale. They are reported at fair value, with any unrealized gains
or losses resulting from changes in fair value reported in equity as part of
accumulated other comprehensive income, and are excluded from earnings unless
such changes in fair value are determined to be other than temporary. Unrealized
gains or losses from changes in the fair value of our nuclear decommissioning
investments are reported as regulatory liabilities. The fair value of these
investments is determined from quoted market prices. For additional details
regarding financial instruments, see Note 7, Financial and Derivative
Instruments.
FOREIGN CURRENCY TRANSLATION: Our subsidiaries and affiliates whose
functional currency is not the U.S. dollar translate their assets and
liabilities into U.S. dollars at the exchange rates in effect at the end of the
fiscal period. We translate revenue and expense accounts of such subsidiaries
and affiliates into U.S. dollars at the average exchange rates that prevailed
during the period. The gains or losses that result from this process, and gains
and losses on intercompany foreign currency transactions that are long-term in
nature that we do not intend to settle in the foreseeable future, are shown in
the stockholders' equity section of the balance sheet. For subsidiaries
operating in highly inflationary economies, the U.S. dollar is considered to be
the functional currency, and transaction gains and losses are included in
determining net income. Gains and losses that arise from exchange rate
fluctuations on transactions denominated in a currency other than the functional
currency, except those that are hedged, are included in determining net income.
The change in the foreign currency translation adjustment increased equity by
$39 million for the year ended December 31, 2003. The change in the foreign
currency translation adjustment decreased equity by $225 million for the year
ended December 31, 2002.
GAS INVENTORY: Consumers uses the weighted average cost method for valuing
working gas and recoverable cushion gas in underground storage facilities.
GOODWILL: Goodwill represents the excess of the purchase price over the
fair value of the net assets of acquired companies. Goodwill is not amortized,
but is tested annually for impairment. For additional information, see Note 3,
Goodwill.
IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: We evaluate potential
impairments of our investments in long-lived assets other than goodwill based on
various analyses, including the projection of undiscounted cash flows, whenever
events or changes in circumstances indicate that the carrying amount of the
assets may not be recoverable. If the carrying amount of the asset exceeds its
estimated undiscounted future cash flows, an impairment loss is recognized and
the asset is written down to its estimated fair value.
MAINTENANCE AND DEPRECIATION: We charge property repairs and minor
property replacements to maintenance expense. We also charge planned major
maintenance activities to operating expense unless the cost represents the
acquisition of additional components or the replacement of an existing
component. We capitalize the cost of plant additions and replacements. We
depreciate utility property on straight-line and units-of-production rates
approved by the MPSC. The composite depreciation rates for our properties are:
YEARS ENDED
DECEMBER 31
---------------------
2003 2002 2001
------ ------ ------
Electric utility property... 3.1% 3.1% 3.1%
Gas utility property........ 4.6% 4.5% 4.4%
Other property.............. 8.1% 7.2% 11.2%
NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on
the quantity of heat produced for electric generation. For nuclear fuel used
after April 6, 1983, we charge disposal costs to nuclear fuel expense, recover
these costs through electric rates, and remit them to the DOE quarterly. We
elected to defer payment for disposal of spent nuclear fuel burned before April
7, 1983. As of December 31, 2003, we have recorded a liability to the DOE for
$139 million, including interest, which is payable upon the first delivery of
spent nuclear fuel to the DOE. The amount of this liability, excluding a portion
of interest, was recovered through electric rates. For
F-62
additional details on disposal of spent nuclear fuel, see Note 4, Uncertainties,
"Other Consumers' Electric Utility Uncertainties -- Nuclear Matters."
NUCLEAR PLANT DECOMMISSIONING: Our site-specific decommissioning cost
estimates for Big Rock and Palisades assume that each plant site will eventually
be restored to conform to the adjacent landscape and all contaminated equipment
will be disassembled and disposed of in a licensed burial facility.
Trust Funds: MPSC orders, received in March 1999 for Big Rock and December
1999 for Palisades, provided for fully funding the decommissioning trust funds
for both sites. The December 1999 order set the annual decommissioning surcharge
for Palisades at $6 million. In 2003, we collected $6 million from our electric
customers for the decommissioning of our Palisades nuclear plant. Amounts
collected from electric retail customers and deposited in trusts, including
trust earnings, are credited to a regulatory liability.
In December 2000, we stopped depositing funds in the Big Rock trust fund
based on its funding status at that time. However, the current level of funds
provided by the trust may not be adequate to fully fund the decommissioning of
Big Rock. This is due in part to the DOE's failure to accept spent nuclear fuel
and lower returns on the trust fund. We are attempting to recover our additional
costs for storing spent nuclear fuel through litigation, as discussed in Note 4,
Uncertainties, "Other Consumers' Electric Utility Uncertainties -- Nuclear
Matters." To the extent the funds are not sufficient, we would seek additional
relief from the MPSC. We can make no assurance that the MPSC would grant this
request.
In March 2001, we filed with the MPSC a "Report on the Adequacy of the
Existing Provision for Nuclear Plant Decommissioning" for each plant reflecting
decommissioning cost estimates of $349 million for Big Rock, excluding spent
nuclear fuel storage costs, and $739 million for Palisades, in 2000 dollars. We
are required to file the next such reports with the MPSC by March 31, 2004 for
Big Rock and Palisades and we are in the process of preparing updated cost
estimates.
Big Rock: In 1997, Big Rock closed permanently and plant decommissioning
began. We estimate that the Big Rock site will be returned to a natural state by
the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010. The
following table shows our Big Rock decommissioning activities:
YEAR-TO-DATE ACCUMULATIVE
DECEMBER 31, 2003 TOTAL-TO-DATE
----------------- -------------
IN MILLIONS
Decommissioning expenditures..... $ 45 $ 263
Withdrawals from trust funds..... 34 243
These activities had no material impact on net income. At December 31,
2003, we have an investment in nuclear decommissioning trust funds of $88
million for Big Rock. In addition, at December 31, 2003, we have charged $7
million to our FERC jurisdictional depreciation reserve for the decommissioning
of Big Rock.
Palisades: In December 2000, the NRC extended the Palisades operating
license to March 2011 and the impact of this extension was included as part of
our March 2001 filing with the MPSC.
At December 31, 2003, we have an investment in the MPSC nuclear
decommissioning trust funds of $477 million for Palisades. In addition, at
December 31, 2003, we have a FERC decommissioning trust fund with a balance of
$10 million. For additional details on decommissioning costs accounted for as
asset retirement obligations, see Note 16, Asset Retirement Obligations.
F-63
OTHER INCOME AND EXPENSE: The following tables show the components of
Other income and Other expense:
YEARS ENDED DECEMBER 31
-------------------------------------------
RESTATED RESTATED
2003 2002 2001
------------ ------------- ------------
IN MILLIONS
Other income
Interest and dividends - related parties.. $ 6 $ 3 $ 5
Electric restructuring return............. 8 5 3
Gain on sale of investment................ 4 -- --
All other................................. 6 8 3
------- ------- -------
Total other income......................... $ 24 $ 16 $ 11
======= ======= =======
YEARS ENDED DECEMBER 31
-------------------------------------------
RESTATED RESTATED
2003 2002 2001
------------ ------------- --------
IN MILLIONS
Other expense
Loss on SERP investment.................. $ (1) $ (10) $ --
Donations................................ (1) (9) (1)
CMS MST remediation costs................ (6) (1) --
Civic and political expenditures......... (2) (3) (2)
All other................................ (11) (7) (2)
------- ------- -------
Total other expense..................... $ (21) $ (30) $ (5)
======= ======= =======
PROPERTY, PLANT, AND EQUIPMENT: We record property, plant and equipment at
original cost when placed into service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, the original cost is
charged to accumulated depreciation and cost of removal, less salvage is
recorded as a regulatory liability. For additional details, see Note 16, Asset
Retirement Obligations. An allowance for funds used during construction is
capitalized on regulated construction projects. With respect to the retirement
or disposal of non-regulated assets, the resulting gains or losses are
recognized in income.
Property, plant, and equipment at December 31, 2003 and 2002, was as
follows:
ESTIMATED
DEPRECIABLE
YEARS ENDED DECEMBER 31 LIFE IN YEARS(E) 2003 2002
------------------------------------------------- ------------------ --------- --------
IN MILLIONS
Electric:
Generation.................................... 13-75 $ 3,332 $ 3,489
Distribution.................................. 12-85 3,799 3,619
Other......................................... 5-50 388 300
Capital leases(a)............................. 81 115
Gas:
Underground storage facilities(b)............. 30-75 232 217
Transmission.................................. 15-75 342 310
Distribution.................................. 35-75 1,976 1,899
Other......................................... 5-48 300 237
Capital leases(a)............................. 25 56
Enterprises:
IPP........................................... 3-40 511 250
CMS Gas Transmission.......................... 5-40 119 120
CMS Electric and Gas.......................... 2-30 241 227
Other......................................... 4-25 24 47
Other:.......................................... 7-71 32 45
Construction work-in-progress(c)................ 388 557
Less accumulated depreciation, depletion, and
amortization(d)............................... 4,846 5,385
--------- --------
Net property, plant, and equipment(e)........... $ 6,944 $ 6,103
========= ========
F-64
(a) Capital leases presented in this table are gross amounts. Amortization of
capital leases was $38 million in 2003 and $96 million in 2002.
(b) Includes unrecoverable base natural gas in underground storage of $23
million at December 31, 2003 and $23 million at December 31, 2002, which is
not subject to depreciation.
(c) Included in construction costs at December 31, 2002 was $54 million,
relating to the capital lease of our main headquarters. We purchased the
main headquarters in November 2003.
(d) Accumulated depreciation, depletion, and amortization is comprised of $4.416
billion from our public utility plant assets as of December 31, 2003 and
$4.989 billion from public utility plant assets as of December 31, 2002 and
$430 million from other plant assets as of December 31, 2003 and $396
million from other plant assets as of December 31, 2002.
(e) Included in net property, plant and equipment are intangible assets
primarily related to software development costs, consents, leasehold
improvements, and rights of way. The estimated amortization life for
software development costs is seven years, leasehold improvements is over
the life of the lease and other intangible amortization lives range from 50
to 75 years. Intangible assets at December 31, 2003 and 2002 were as
follows:
YEARS ENDED DECEMBER 31
--------------------------
2003 2002
---------- ----------
IN MILLIONS
Intangible assets at cost
Software development ...................................................... $ 178 $ 149
Rights of way.............................................................. 89 84
Leasehold improvements..................................................... 32 35
Franchises and consents.................................................... 19 19
Other intangibles.......................................................... 101 192
---------- ----------
Intangible assets at cost.................................................... $ 419 $ 479
========== ==========
YEARS ENDED DECEMBER 31
--------------------------
2003 2002
---------- ----------
IN MILLIONS
Intangible assets accumulated amortization...................................
Software development....................................................... $ 107 $ 92
Rights of way.............................................................. 25 26
Leasehold improvements..................................................... 30 28
Franchises and consents.................................................... 8 8
Other intangibles.......................................................... 41 82
---------- ----------
Intangible assets accumulated amortization................................... $ 211 $ 236
========== ==========
YEARS ENDED DECEMBER 31
--------------------------
2003 2002
---------- ----------
IN MILLIONS
Intangible assets, net.......................................................
Software development ...................................................... $ 71 $ 57
Rights of way.............................................................. 64 58
Leasehold improvements..................................................... 2 7
Franchises and consents.................................................... 11 11
Other intangibles.......................................................... 60 110
---------- ----------
Intangible assets, net ...................................................... $ 208 $ 243
========== ==========
F-65
Pretax amortization expense related to these intangible assets for the year
ended December 31, 2003 was $21 million and for the year ended December 31, 2002
was $20 million. Intangible assets amortization is forecasted to range from $18
million to $26 million per year over the next five years.
(f) The following table illustrates the depreciable life for electric and gas
structures and improvements.
ESTIMATED ESTIMATED
DEPRECIABLE DEPRECIABLE
ELECTRIC LIFE IN YEARS GAS LIFE IN YEARS
----------------- ---------------- ------------------------------ -------------
Generation: Underground storage facilities 45
Coal 39-43 Transmission 60
Nuclear 25 Distribution 60
Hydroelectric 55-71 Other 42-48
Other 32
Distribution 50-60
Other 40-42
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the years presented.
RELATED-PARTY TRANSACTIONS: Consumers paid $64 million in 2003, $67
million in 2002, and $71 million in 2001 for electric generating capacity and
energy from affiliates of Enterprises. CMS Energy recorded interest charges on
long-term debt to related parties of $58 million in 2003. Affiliates of CMS
Energy sold, stored and transported natural gas and provided other services to
the MCV Partnership totaling $17 million in 2003, $41 million in 2002, and $35
million in 2001. We expensed purchases of capacity and energy from the MCV
Partnership totaling $455 million in 2003, $497 million in 2002, and $488
million in 2001. As a result of our deconsolidation of our affiliated Trust
Preferred Securities as of December 31, 2003, we recorded $2 million of dividend
income from related parties in 2003. For additional discussion of related-party
transactions with the MCV Partnership and the FMLP, see Note 4, Uncertainties
and Note 15, Summarized Financial Information of Significant Related Energy
Supplier. For additional discussion of related-party transactions with our
affiliated Trust Preferred Securities see Note 6, Financing and Capitalization.
Other related-party transactions are immaterial.
TRADE RECEIVABLES: We record our accounts receivable at fair value.
Accounts deemed uncollectable are charged to operating expense.
UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE: We amortize premiums,
discounts and expenses incurred in connection with the issuance of outstanding
long-term debt over the terms of the issues. For the regulated portions of our
businesses, if debt is refinanced, we amortize any unamortized premiums,
discounts and expenses over the term of the new debt.
UTILITY REGULATION: We account for the effects of regulation based on the
regulated utility accounting standard SFAS No. 71. As a result, the actions of
regulators affect when we recognize revenues, expenses, assets, and liabilities.
In 1999, we received MPSC electric restructuring orders, which, among
other things, identified the terms and timing for implementing electric
restructuring in Michigan. Consistent with these orders and EITF No. 97-4, we
discontinued the application of SFAS No. 71 for the energy supply portion of our
business because we expected to implement ROA at competitive market based rates
for our electric customers.
Since 1999, there have been significant legislative and regulatory changes
in Michigan that has resulted in:
- electric supply customers of utilities remaining on cost-based
rates, and
- utilities being provided the opportunity to recover Stranded Costs
associated with electric restructuring, from customers who choose an
alternative electric supplier.
F-66
During 2002, we re-evaluated the criteria used to determine if an entity
or a segment of an entity meets the requirements to apply regulated utility
accounting, and determined that the energy supply portion of our business could
meet the criteria if certain regulatory events occurred. In December 2002, we
received a MPSC Stranded Cost order that allowed us to re-apply regulatory
accounting standard SFAS No. 71 to the energy supply portion of our business.
Re-application of SFAS No. 71 had no effect on the prior discontinuation
accounting, but allowed us to apply regulatory accounting treatment to the
energy supply portion of our business beginning in the fourth quarter of 2002,
including regulatory accounting treatment of costs required to be recognized in
accordance with SFAS No. 143. For additional details, see Note 12, Asset
Retirement Obligations.
SFAS No. 144 imposes strict criteria for retention of regulatory-created
assets by requiring that such assets be probable of future recovery at each
balance sheet date. Management believes these assets are probable of future
recovery.
The following regulatory assets and liabilities, which include both
current and non-current amounts, are reflected in the Consolidated Balance
Sheets. We expect to recover these costs through rates over periods of up to 14
years. We recognized an OPEB transition obligation in accordance with SFAS No.
106 and established a regulatory asset for this amount that we expect to recover
in rates over the next nine years.
DECEMBER 31
------------------
2003 2002
-------- ---------
IN MILLIONS
Securitized costs (Note 4)............................. $ 648 $ 689
Postretirement benefits (Note 10)...................... 181 204
Electric Restructuring Implementation Plan (Note 4).... 91 83
Manufactured gas plant sites (Note 4).................. 67 69
Abandoned Midland project.............................. 10 11
Unamortized debt....................................... 51 14
Asset retirement obligation (Note 16).................. 49 --
Other.................................................. 8 2
-------- ---------
Total regulatory assets................................ $ 1,105 $ 1,072
======== =========
Cost of removal (Note 16).............................. $ 983 $ 907
Income taxes (Note 8).................................. 312 297
Asset retirement obligation (Note 16).................. 168 --
Other.................................................. 4 4
-------- ---------
Total regulatory liabilities........................... $ 1,467 $ 1,208
======== =========
In October 2000, we received an MPSC order authorizing us to securitize
certain regulatory assets up to $469 million, net of tax, see Note 4,
Uncertainties, "Consumers' Electric Utility Restructuring Matters --
Securitization." Accordingly, in December 2000, we established a regulatory
asset for securitized costs of $709 million, before tax, that had previously
been recorded in other regulatory asset accounts. To prepare for the financing
of the securitized assets and the subsequent retirement of debt with
Securitization proceeds, issuance fees were capitalized as a part of
Securitization costs. These issuance costs are amortized each month for up to
fourteen years. The components of the unamortized securitized costs are
illustrated below.
DECEMBER 31
---------------
2003 2002
------ ------
IN MILLIONS
Unamortized nuclear costs.......................... $ 405 $ 405
Postretirement benefits............................ 84 84
Income taxes....................................... 203 203
Uranium enrichment facility........................ 16 16
Other.............................................. 12 12
Accumulated Securitization cost amortization....... (72) (31)
------ ------
Total unamortized securitized costs................ $ 648 $ 689
====== ======
F-67
2: DISCONTINUED OPERATIONS, OTHER ASSET SALES, IMPAIRMENTS, AND RESTRUCTURING
Our continued focus on financial improvement has led to discontinuing
operations, completing many asset sales, impairing some assets, and incurring
costs to restructure our business. Gross cash proceeds received from the sale of
assets totaled $939 million in 2003 and $1.659 billion in 2002.
DISCONTINUED OPERATIONS
We have discontinued the following operations:
PRETAX AFTER-TAX
BUSINESS/PROJECT DISCONTINUED GAIN(LOSS) GAIN(LOSS) STATUS
---------------------- --------------- ---------- ---------- -------------------
IN MILLIONS
Equatorial Guinea(a).. December 2001 $ 497 $ 310 Sold January 2002
Powder River.......... March 2002 17 11 Sold May 2002
Zirconium Recovery.... June 2002 (47) (31) Abandoned
CMS Viron............. June 2002 (14) (9) Sold June 2003
Oil and Gas(b)........ September 2002 (126) (82) Sold September 2002
Panhandle(c).......... December 2002 (39) (44) Sold June 2003
Field Services........ December 2002 (5) (1) Sold July 2003
Marysville............ June 2003 2 1 Sold November 2003
Parmelia(d)........... December 2003 -- -- Held for sale
(a) In the first quarter of 2003, we settled a liability with the purchaser of
Equatorial Guinea and reversed the remaining excess reserve. This
settlement resulted in a gain of $6 million after-tax, which is included
in discontinued operations.
(b) As a result of the sale of CMS Oil and Gas, we recorded liabilities for
certain sale indemnification obligations and other matters. In September
2003, we re-evaluated our exposure to the obligations and reduced the
carrying value of these liabilities by $8 million after-tax. This
adjustment is reported in discontinued operations.
(c) The Pension Plan retained pension payment obligations for Panhandle
employees who were vested under the Pension Plan. Panhandle employees are
no longer eligible to accrue additional benefits. Because of the
significant change in the makeup of the plan, a remeasurement of the
obligation at the date of sale was required. The remeasurement resulted in
a $4 million increase in our 2003 OPEB expense, as well as an additional
charge to accumulated other comprehensive income of approximately $34
million ($22 million after-tax) as a result of the increase in the
additional minimum pension liability. Additionally, a significant number
of Panhandle employees elected to retire as of July 1, 2003 under the CMS
Energy Employee Pension Plan. As a result, we have recorded a $25 million
($16 million after-tax) settlement loss, and a $10 million ($7 million
after-tax) curtailment gain, pursuant to the provisions of SFAS No. 88,
which is reflected in discontinued operations.
(d) In December 2003, we began reporting the operations of our Parmelia
business in discontinued operations and reduced the carrying amount of our
Parmelia business to reflect fair value. The $26 million after-tax
adjustment is reported in discontinued operations. We expect the sale of
Parmelia to occur in 2004.
Due to lack of progress on the sale, we reclassified our international
energy distribution business, which includes CPEE and SENECA, from discontinued
operations to continuing operations for the years 2003, 2002, and 2001. When we
initially reported the international energy distribution business as a
discontinued operation in 2001, we applied APB Opinion No. 30, which allowed us
to record a provision for anticipated operating losses. We currently apply FASB
No. 144, which does not allow us to record a provision for future operating
losses. Therefore, in the process of reclassifying the international energy
distribution business to continuing operations and reversing such provisions, we
increased our net loss by $3 million in 2002 and decreased our net loss by $3
million in 2001. In 2003, there was an increase to net income of $75 million as
a result of reversing the previously recognized impairment loss in discontinued
operations.
At December 31, 2003, "Assets held for sale" includes Parmelia, Bluewater
Pipeline, and our investment in the American Gas Index fund. Although Bluewater
Pipeline and the American Gas Index fund are considered held for
F-68
sale, they did not meet the criteria for discontinued operations. At December
31, 2002, "Assets held for sale" includes Panhandle, CMS Viron, CMS Field
Services, Marysville, and Parmelia. The major classes of assets and liabilities
held for sale are as follows:
AS OF
DECEMBER 31
------------------
RESTATED
2003 2002
----- --------
IN MILLIONS
Assets
Cash................................... $ 7 $ 82
Accounts receivable.................... 2 133
Property, plant and equipment -- net... 2 2,003
Goodwill............................... -- 117
Other.................................. 15 344
----- --------
Total assets held for sale............... $ 26 $ 2,679
===== ========
Liabilities
Accounts payable....................... $ 2 $ 74
Long-term debt......................... -- 1,150
Minority interest...................... -- 45
Other.................................. -- 376
----- --------
Total liabilities held for sale.......... $ 2 $ 1,645
===== ========
The following amounts are reflected in the Consolidated Statements of
Income (Loss) for discontinued operations:
YEARS ENDED DECEMBER 31
----------------------------------
RESTATED RESTATED
2003 2002 2001
------- -------- --------
IN MILLIONS
Revenues............................................... $ 504 $ 891 $ 1,453
======= ======= ========
Discontinued operations:
Pretax gain (loss) from discontinued operations...... $ 115 $ (38) $ (53)
Income tax expense (benefit)......................... 46 (1) 83
------- ------- --------
Income (loss) from discontinued operations........... 69 (37) (136)
======= ======= ========
Pretax gain (loss) on disposal of discontinued
operations........................................ (42) (354) 17
Income tax expense (benefit)......................... 4 (117) 9
------- ------- --------
Gain (loss) on disposal of discontinued operations... (46) (237) 8
------- ------- --------
Income (loss) from discontinued operations............. $ 23 $ (274) $ (128)
======= ======= ========
The income (loss) from discontinued operations includes a reduction in
asset values, a provision for anticipated closing costs, and a portion of the
Parent Company's interest expense. Interest expense of $22 million for 2003, $71
million for 2002 and $86 million for 2001 has been allocated based on a ratio of
the expected proceeds for the asset to be sold divided by the Parent Company's
total capitalization of each discontinued operation times the Parent Company's
interest expense.
OTHER ASSET SALES
Our other asset sales include the following non-strategic and
under-performing assets. The impacts of these sales are included in "Gain (loss)
on asset sales, net" in the Consolidated Statements of Income (Loss).
F-69
In 2003, we sold the following assets that did not meet the definition of,
and therefore were not reported as, discontinued operations:
PRETAX AFTER-TAX
DATE SOLD BUSINESS/PROJECT GAIN (LOSS) GAIN (LOSS)
------------ ------------------------- ----------- -----------
IN MILLIONS
January CMS MST Wholesale Gas $ (6) $ (4)
March CMS MST Wholesale Power 2 1
June Guardian Pipeline (4) (3)
December CMS Land -- Arcadia 3 2
Various Other 2 1
----- -----
Total loss on asset sales $ (3) $ (3)
===== =====
In June 2003, we received three million shares of Southern Union common
stock worth $49 million from the sale of Panhandle, a discontinued operation. In
July 2003, Southern Union declared a five percent common stock dividend payable
July 31, 2003, to shareholders of record as of July 17, 2003. As a result of the
stock dividend, on September 30, 2003, we held 3.15 million shares of Southern
Union common stock worth $54 million based on the closing price of $17.00 per
share. The $2 million increase in value was recorded in dividend income. In
October 2003, we sold our 3.15 million shares of Southern Union common stock to
a private investor for $17.77 per share. The additional $5 million gain was
recorded in other income in 2003.
In 2002, we sold the following assets that did not meet the definition of,
and therefore were not reported as, discontinued operations:
PRETAX AFTER-TAX
DATE SOLD BUSINESS/PROJECT GAIN (LOSS) GAIN (LOSS)
------------ ------------------------- ----------- -----------
IN MILLIONS
January Equatorial Guinea -- methanol plant $ 19 $ 12
April Toledo Power (11) (5)
May Electric Transmission System 38 31
August National Power Supply 15 30
October Vasavi Power Plant (25) (24)
Various Other 1 --
------ ------
Total gain on asset sales $ 37 $ 44
====== ======
In 2001, we sold miscellaneous assets for a pretax loss of $2 million.
In February 2004, we sold Bluewater Pipeline, a 24.9 mile pipeline that
extends from Marysville, Michigan to Armada, Michigan to Bluewater Gas Storage,
LLC, a subsidiary of Sempra Energy Trading Corporation. We do not expect the
gain or loss on the sale to be significant.
ASSET IMPAIRMENTS
We record an asset impairment when we determine that the expected future
cash flows from an asset would be insufficient to provide for recovery of the
asset's carrying value. An asset held-in-use is evaluated for impairment by
calculating the undiscounted future cash flows expected to result from the use
of the asset and its eventual disposition. If the undiscounted future cash flows
are less than the carrying amount, we recognize an impairment loss. The
impairment loss recognized is the amount by which the carrying amount exceeds
the fair value. We estimate the fair market value of the asset utilizing the
best information available. This information includes quoted market prices,
market prices of similar assets, and discounted future cash flow analyses. The
assets written down include both domestic and foreign electric power plants, gas
processing facilities, and certain equity method and other investments. In
addition, we have written off the carrying value of projects under development
that will no longer be pursued.
F-70
The table below summarizes our asset impairments:
YEARS ENDED DECEMBER 31
----------------------------------------------------------------------
RESTATED RESTATED
-------------------- --------------------
PRETAX AFTER-TAX PRETAX AFTER-TAX PRETAX AFTER-TAX
2003 2003 2002 2002 2001 2001
------ --------- ------ --------- ------ ---------
IN MILLIONS
Asset impairments:
Consumers......................... $ -- $ -- $ -- $ -- $ 3 $ 2
Enterprises:
International Energy 72 53 4 3 95 62
Distribution(a).....................
CMS Generation
DIG(b)....................... -- -- 460 299 -- --
Michigan Power............... -- -- 62 40 -- --
Craven....................... -- -- 23 15 -- --
National Power Supply........ -- -- -- -- 89 88
El Chocon.................... -- -- -- -- 45 42
HL Power..................... -- -- -- -- 30 18
Other(c)..................... 16 11 20 13 16 11
Natural Gas Transmission....... -- -- -- -- 31 20
Marketing, Services and Trading -- -- 18 11 -- --
Other(d)....................... 7 4 15 10 14 9
----- ----- ------ ----- ------ -----
Total asset impairments............. $ 95 $ 68 $ 602 $ 391 $ 323 $ 252
===== ===== ====== ===== ====== =====
(a) In September 2003, we wrote down our investment in CMS Electric and Gas'
Venezuelan electric distribution utility and an associated equipment lease
to reflect fair value. The impairment was based on estimates of the
utility's future cash flows, incorporating certain assumptions about
Venezuela's regulatory, political, and economic environment.
(b) DIG's reduced valuation was primarily a reflection of the unfavorable
terms of its power purchase agreement.
(c) At CMS Generation, we determined that the fair value of our equity
investments was lower than its carrying amount, and that this decline in
value was other than temporary. Therefore, in accordance with APB No. 18,
we recognized an impairment charge of $16 million ($11 million, net of
tax).
(d) Includes development projects of $7 million ($4 million, net of tax) in
2003 that would no longer be pursued.
RESTRUCTURING AND OTHER COSTS
In June 2002, we announced a series of initiatives to reduce our annual
operating costs by an estimated $50 million. As such, we:
- relocated CMS Energy's corporate headquarters from Dearborn,
Michigan to a new combined CMS Energy and Consumers headquarters in
Jackson, Michigan in July 2003,
- implemented changes to our 401(k) savings program,
- implemented changes to our health care plan, and
- terminated 64 employees, including five officers. Prior to December
31, 2002, 123 employees elected severance arrangements. Of these 187
officers and employees, 65 had been terminated as of December 31,
2002. All remaining terminations were completed in 2003.
F-71
The following table shows the amount charged to expense for restructuring
costs, the payments made, and the unpaid balance of accrued costs at December
31, 2002 and December 31, 2003.
INVOLUNTARY LEASE
TERMINATION TERMINATION TOTAL
----------- ----------- -----
IN MILLIONS
Beginning accrual balance, January 1, 2002....... $ -- $ -- $ --
Expense.......................................... 22 11 33
Payments......................................... (10) (3) (13)
------ ------ ------
Ending accrual balance at December 31, 2002...... $ 12 $ 8 $ 20
------ ------ ------
Expense.......................................... 3 -- 3
Payments......................................... (12) (2) (14)
------ ------ ------
Ending accrual balance at December 31, 2003...... $ 3 $ 6 $ 9
====== ====== ======
Restructuring costs for the year ended December 31, 2003, which are
included in operating expenses, include $3 million of involuntary employee
termination benefits.
3: GOODWILL
Our goodwill balance was $25 million at December 31, 2003 and $31 million
at December 31, 2002. Our entire goodwill balance is recorded at the Enterprises
segment. The following table presents changes in the carrying amount of
goodwill:
IN MILLIONS
Beginning balance, January 1, 2002................................................ $ 811
Panhandle goodwill impairment..................................................... (601)
CMS Viron goodwill impairment..................................................... (15)
Goodwill transferred to assets held for sale...................................... (117)
Other goodwill write-downs included in asset impairment charges................... (47)
----------
Ending balance at December 31, 2002............................................... $ 31
==========
CPEE goodwill impairment and other................................................ (6)
----------
Ending balance at December 31, 2003............................................... $ 25
==========
CMS GAS TRANSMISSION: We recorded goodwill as an asset when we purchased
Panhandle and began, over time, to expense a portion of goodwill. Effective
January 1, 2002, a new accounting standard went into effect that required us to
stop expensing goodwill and to test for impairment. We tested the value of the
goodwill related to Panhandle for impairment by comparing the fair value of
goodwill, as determined by independent appraisers, to the value on our books.
The test results showed that the goodwill was impaired. We recorded a loss of
$601 million ($369 million, after-tax), that was the amount by which the value
on our books exceeded the fair value. In 2002, we also discontinued the
operations of Panhandle; therefore, the $369 million after-tax goodwill
impairment is reflected in discontinued operations. In 2003, we sold Panhandle.
CMS MST: During the third quarter of 1999, we purchased a 100 percent
interest in CMS Viron and recorded goodwill. In 2002, we performed an impairment
test, which determined our goodwill related to CMS Viron was impaired. In the
first quarter of 2002, we recorded a loss of $15 million ($10 million,
after-tax) for goodwill impairment. In 2002, we also discontinued the operations
of CMS Viron; therefore, the $10 million after-tax goodwill impairment is
reflected in discontinued operations. In 2003, we sold CMS Viron.
Additionally, the following table represents net loss for the year 2001
without goodwill amortization expense.
RESTATED
2001
--------
IN MILLIONS
Reported net loss........................... $ (459)
Add: goodwill amortization expense(a)....... 13
--------
Adjusted net loss........................... $ (446)
Adjusted basic and diluted loss per share... $ (3.41)
========
(a) Net of tax of $7 million.
F-72
4: UNCERTAINTIES
Several business trends or uncertainties may affect our financial results.
These trends or uncertainties have, or we reasonably expect could have, a
material impact on net sales, revenues, or income from continuing operations.
Such trends and uncertainties are discussed in detail below.
SEC AND OTHER INVESTIGATIONS: As a result of round-trip trading
transactions by CMS MST, CMS Energy's Board of Directors established a Special
Committee to investigate matters surrounding the transactions and retained
outside counsel to assist in the investigation. The Special Committee completed
its investigation and reported its findings to the Board of Directors in October
2002. The Special Committee concluded, based on an extensive investigation, that
the round-trip trades were undertaken to raise CMS MST's profile as an energy
marketer with the goal of enhancing its ability to promote its services to new
customers. The Special Committee found no effort to manipulate the price of CMS
Energy Common Stock or affect energy prices. The Special Committee also made
recommendations designed to prevent any reoccurrence of this practice.
Previously, CMS Energy terminated its speculative trading business and revised
its risk management policy. The Board of Directors adopted, and CMS Energy has
implemented the recommendations of the Special Committee.
CMS Energy is cooperating with other investigations concerning round-trip
trading, including an investigation by the SEC regarding round-trip trades and
CMS Energy's financial statements, accounting policies and controls, and an
investigation by the DOJ. CMS Energy is unable to predict the outcome of these
matters, and what effect, if any, these investigations will have on its
business.
SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of
securities class action complaints were filed against CMS Energy, Consumers, and
certain officers and directors of CMS Energy and its affiliates. The complaints
were filed as purported class actions in the United States District Court for
the Eastern District of Michigan, by shareholders who allege that they purchased
CMS Energy's securities during a purported class period. The cases were
consolidated into a single lawsuit and an amended and consolidated class action
complaint was filed on May 1, 2003. The consolidated complaint contains a
purported class period beginning on May 1, 2000 and running through March 31,
2003. It generally seeks unspecified damages based on allegations that the
defendants violated United States securities laws and regulations by making
allegedly false and misleading statements about CMS Energy's business and
financial condition, particularly with respect to revenues and expenses recorded
in connection with round-trip trading by CMS MST. CMS Energy, Consumers, and
their affiliates will defend themselves vigorously but cannot predict the
outcome of this litigation.
DEMAND FOR ACTIONS AGAINST OFFICERS AND DIRECTORS: In May 2002, the Board
of Directors of CMS Energy received a demand, on behalf of a shareholder of CMS
Energy Common Stock, that it commence civil actions (i) to remedy alleged
breaches of fiduciary duties by certain CMS Energy officers and directors in
connection with round-trip trading by CMS MST, and (ii) to recover damages
sustained by CMS Energy as a result of alleged insider trades alleged to have
been made by certain current and former officers of CMS Energy and its
subsidiaries. In December 2002, two new directors were appointed to the Board.
The Board formed a special litigation committee in January 2003 to determine
whether it is in the best interest of CMS Energy to bring the action demanded by
the shareholder. The disinterested members of the Board appointed the two new
directors to serve on the special litigation committee.
In December 2003, during the continuing review by the special litigation
committee, CMS Energy was served with a derivative complaint filed on behalf of
the shareholder in the Circuit Court of Jackson County, Michigan in furtherance
of his demands. The date for CMS Energy and other defendants to answer or
otherwise respond to the complaint was extended to June 1, 2004, subject to such
further extensions as may be mutually agreed upon by the parties and authorized
by the Court. CMS Energy cannot predict the outcome of this matter.
ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS
MST, and certain named and unnamed officers and directors, in two lawsuits
brought as purported class actions on behalf of participants and beneficiaries
of the CMS Employees' Savings and Incentive Plan (the "PLAN"). The two cases,
filed in July 2002 in United States District Court for the Eastern District of
Michigan, were consolidated by the trial judge and an amended consolidated
complaint was filed. Plaintiffs allege breaches of fiduciary duties under ERISA
and seek
F-73
restitution on behalf of the Plan with respect to a decline in value of the
shares of CMS Energy Common Stock held in the Plan. Plaintiffs also seek other
equitable relief and legal fees. CMS Energy and Consumers will defend themselves
vigorously but cannot predict the outcome of this litigation.
GAS INDEX PRICE REPORTING INVESTIGATION: CMS Energy has notified
appropriate regulatory and governmental agencies that some employees at CMS MST
and CMS Field Services appeared to have provided inaccurate information
regarding natural gas trades to various energy industry publications which
compile and report index prices. CMS Energy is cooperating with an investigation
by the DOJ regarding this matter. In November 2003, CMS MST and CMS Field
Services (now Cantera Gas Company) entered into a settlement with the CFTC
pursuant to which they paid a $16 million civil monetary penalty in connection
with the inaccurate reporting of natural gas trading data to publications that
compile and publish price indices. The settlement resolves all matters
investigated by the CFTC involving CMS Energy, including round-trip trading. CMS
Energy neither admits nor denies the CFTC's findings in the settlement order.
CMS Energy is unable to predict the outcome of the DOJ investigation and what
effect, if any, this investigation will have on its business.
GAS INDEX PRICE REPORTING LITIGATION: In August 2003, Cornerstone Propane
Partners, L.P. ("CORNERSTONE") filed a putative class action complaint in the
United States District Court for the Southern District of New York against CMS
Energy and dozens of other energy companies. The court ordered the Cornerstone
complaint to be consolidated with similar complaints filed by Dominick Viola and
Roberto Calle Gracey. The plaintiffs filed a consolidated complaint on January
20, 2004. The consolidated complaint alleges that false natural gas price
reporting by the defendants manipulated the prices of NYMEX natural gas futures
and options. The complaint contains two counts under the Commodity Exchange Act,
one for manipulation and one for aiding and abetting violations. CMS Energy is
no longer a defendant, however, CMS MST and CMS Field Services are named as
defendants. (CMS Energy sold CMS Field Services to Cantera Natural Gas, Inc. but
is required to indemnify Cantera Natural Gas, Inc. with respect to this action.)
In a similar but unrelated matter, Texas-Ohio Energy, Inc. filed a
putative class action lawsuit in the United States District Court for the
Eastern District of California against a number of energy companies engaged in
the sale of natural gas in the United States. CMS Energy is named as a
defendant. The complaint alleges defendants entered into a price-fixing
conspiracy by engaging in activities to manipulate the price of natural gas in
California. The complaint contains counts alleging violations of the Sherman
Act, Cartwright Act (a California Statute), and the California Business and
Profession Code relating to unlawful, unfair and deceptive business practices.
The plaintiff in the Texas-Ohio case has agreed to extend the time for all
defendants to answer or otherwise respond until after the multi district court
litigation ("MDL") panel decides whether to take the case. There is currently
pending in the Nevada federal district court a MDL matter involving seven
complaints originally filed in various state courts in California. These
complaints make allegations similar to those in the Texas-Ohio case regarding
price reporting, although none contain a Sherman Act claim. Some of the
defendants in the MDL matter who are also defendants in the Texas-Ohio case are
trying to have the Texas-Ohio case transferred to the MDL proceeding.
Benscheidt v. AEP Energy Services, Inc., et al., a new class action
complaint containing allegations similar to those made in the Texas-Ohio case,
albeit limited to California state law claims, was filed in California state
court in February 2004. CMS Energy and CMS MST are named as defendants.
Defendants are likely to seek to remove this action from the California federal
district court and have it transferred to the MDL proceeding in Nevada.
CMS Energy and the other CMS defendants will defend themselves vigorously,
but cannot predict the outcome of these matters.
CONSUMERS' UNCERTAINTIES
Several business trends or uncertainties may affect Consumers' financial
results and condition. These trends or uncertainties have, or we expect could
have, a material impact on revenues or income from continuing electric and gas
operations. Such trends and uncertainties include:
Environmental
- increased capital expenditures and operating expenses for Clean Air
Act compliance, and
F-74
- potential environmental liabilities arising from various
environmental laws and regulations, including potential liability or
expenses relating to the Michigan Natural Resources and
Environmental Protection Acts, Superfund, and at former manufactured
gas plant facilities.
Restructuring
- response of the MPSC and Michigan legislature to electric industry
restructuring issues,
- ability to meet peak electric demand requirements at a reasonable
cost, without market disruption,
- ability to recover any of our net Stranded Costs under the
regulatory policies being followed by the MPSC,
- recovery of electric restructuring implementation costs,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer, instead of an electric
transmission owner-operator.
Regulatory
- effects of conclusions about the causes of the August 14, 2003
blackout, including exposure to liability, increased regulatory
requirements, and new legislation,
- effects of potential performance standards payments,
- successful implementation of initiatives to reduce exposure to
purchased power price increases,
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel,
- potential adverse appliance service plan ruling or related
legislation,
- inadequate regulatory response to applications for requested rate
increases, and
- response to increases in gas costs, including adverse regulatory
response and reduced gas use by customers.
Other
- pending litigation regarding PURPA qualifying facilities, and
- pending litigation and government investigations.
CONSUMERS' ELECTRIC UTILITY CONTINGENCIES
ELECTRIC ENVIRONMENTAL MATTERS: Our operations are subject to
environmental laws and regulations. Costs to operate our facilities in
compliance with these laws and regulations generally have been recovered in
customer rates.
Clean Air: In 1998, the EPA issued regulations requiring the state of
Michigan to further limit nitrogen oxide emissions at our coal-fired electric
plants. The Michigan Department of Environmental Quality finalized its rules to
comply with the EPA regulations in December 2002. It submitted these rules to
the EPA for approval in the first quarter of 2003. The EPA has yet to approve
the Michigan rules. If the EPA does not approve the Michigan rules, similar
federal regulations will take effect.
The EPA and the state regulations require us to make significant capital
expenditures estimated to be $771 million. As of December 31, 2003, we have
incurred $446 million in capital expenditures to comply with the EPA regulations
and anticipate that the remaining $325 million of capital expenditures will be
incurred between 2004 and
F-75
2009. These expenditures include installing catalytic reduction technology on
some of our coal-fired electric plants. Based on the Customer Choice Act,
beginning January 2004, an annual return of and on these types of capital
expenditures, to the extent they are above depreciation levels, is expected to
be recoverable from customers, subject to a MPSC prudency hearing.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants.
In addition to modifying the coal-fired electric plants, we expect to
purchase nitrogen oxide emissions credits for years 2004 through 2008. The cost
of these credits is estimated to average $8 million per year and is accounted
for as inventory. The credit inventory is expensed as the coal-fired electric
plants generate electricity. The price for nitrogen oxide emissions credits is
volatile and could change substantially.
Future clean air regulations requiring emission controls for sulfur
dioxide, nitrogen oxides, mercury, and nickel may require additional capital
expenditures. Total expenditures will depend upon the final makeup of the new
regulations.
Water: The EPA has proposed changes to the rules that govern generating
plant cooling water intake systems. The proposed rules will require significant
reduction in fish killed by operating equipment. The proposed rules are
scheduled to become final in the first quarter of 2004 and some of our
facilities would be required to comply by 2006. We are studying the proposed
rules to determine the most cost-effective solutions for compliance.
Cleanup and Solid Waste: Under the Michigan Natural Resources and
Environmental Protection Act, we expect that we will ultimately incur
investigation and remedial action costs at a number of sites. We believe that
these costs will be recoverable in rates under current ratemaking policies.
We are a potentially responsible party at several contaminated sites
administered under Superfund. Superfund liability is joint and several, meaning
that many other creditworthy parties with substantial assets are potentially
responsible with respect to the individual sites. Based on past experience, we
estimate that our share of the total liability for the known Superfund sites
will be between $1 million and $9 million. As of December 31, 2003, we have
recorded a liability for the minimum amount of our estimated Superfund
liability.
In October 1998, during routine maintenance activities, we identified PCB
as a component in certain paint, grout, and sealant materials at the Ludington
Pumped Storage facility. We removed and replaced part of the PCB material. We
have proposed a plan to deal with the remaining materials and are awaiting a
response from the EPA.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities
selling power to us filed a lawsuit in Ingham County Circuit Court. The lawsuit
alleges that we incorrectly calculated the energy charge payments made pursuant
to power purchase agreements with qualifying facilities. More specifically, the
lawsuit alleges that we should be basing the energy charge calculation on the
cost of more expensive eastern coal, rather than on the cost of the coal
actually burned by us for use in our coal-fired generating plants. We believe we
have been performing the calculation in the manner prescribed by the power
purchase agreements, and have filed a request with the MPSC (as a supplement to
the PSCR plan) that asks the MPSC to review this issue and to confirm that our
method of performing the calculation is correct. We filed a motion to dismiss
the lawsuit in the Ingham County Circuit Court due to the pending request at the
MPSC in regard to the PSCR plan case. In February 2004, the judge ruled on the
motion and deferred to the primary jurisdiction of the MPSC. This ruling
effectively suspends the lawsuit until the MPSC rules. Although only eight
qualifying facilities have raised the issue, the same energy charge methodology
is used in the PPA with the MCV Partnership and in approximately 20 additional
power purchase agreements with us, representing a total of 1,670 MW of electric
capacity. We cannot predict the outcome of this matter.
F-76
CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS
ELECTRIC RESTRUCTURING LEGISLATION: In June 2000, the Michigan legislature
passed electric utility restructuring legislation known as the Customer Choice
Act. This act:
- allows all customers to choose their electric generation supplier
effective January 1, 2002,
- provides a one-time five percent residential electric rate
reduction,
- froze all electric rates through December 31, 2003, and established
a rate cap for residential customers through at least December 31,
2005, and a rate cap for small commercial and industrial customers
through at least December 31, 2004,
- allows deferred recovery of an annual return of and on capital
expenditures in excess of depreciation levels incurred during and
before the rate freeze-cap period,
- allows for the use of Securitization bonds to refinance qualified
costs,
- allows recovery of net Stranded Costs and implementation costs
incurred as a result of the passage of the act,
- requires Michigan utilities to join a FERC-approved RTO or sell
their interest in transmission facilities to an independent
transmission owner,
- requires Consumers, Detroit Edison, and AEP to jointly expand their
available transmission capability by at least 2,000 MW, and
- establishes a market power supply test that, if not met, may require
transferring control of generation resources in excess of that
required to serve retail sales requirements.
The following summarizes our status under the last three provisions of the
Customer Choice Act. First, we chose to sell our interest in our transmission
facilities to an independent transmission owner in order to comply with the
Customer Choice Act; for additional details regarding the sale of the
transmission facility, see "Transmission Sale" within this section. Second, in
July 2002, the MPSC issued an order approving our plan to achieve the increased
transmission capacity required under the Customer Choice Act. The MPSC found
that once the planned projects were completed and verification was submitted, a
utility was in technical compliance. We have completed the transmission capacity
projects identified in the plan and have submitted verification of this fact to
the MPSC. We believe we are in full compliance. Lastly, in September 2003, the
MPSC issued an order finding that we are in compliance with the market power
supply test set forth in the Customer Choice Act.
ELECTRIC ROA PLAN: In 1998, we submitted a plan for electric ROA to the
MPSC. In March 1999, the MPSC issued orders generally supporting the plan. The
Customer Choice Act states that the MPSC orders issued before June 2000 are in
compliance with this act and enforceable by the MPSC. Those MPSC orders:
- allow electric customers to choose their supplier,
- authorize recovery of net Stranded Costs from ROA customers and
implementation costs from all customer classes, and
- confirm any voluntary commitments of electric utilities.
The MPSC approved revised tariffs that establish the rates, terms, and
conditions under which retail customers are permitted to choose an electric
supplier. These revised tariffs allow ROA customers, upon as little as 30 days
notice to us, to return to our generation service at current tariff rates. If
any class of customers' (residential, commercial, or industrial) ROA load
reaches ten percent of our total load for that class of customers, then
returning ROA customers for that class must give 60 days notice to return to our
generation service at current tariff rates. However, we may not have capacity
available to serve returning ROA customers that is sufficient or reasonably
F-77
priced. As a result, we may be forced to purchase electricity on the spot market
at higher prices than we can recover from our customers during the rate cap
periods.
We cannot predict the total amount of electric supply load that may be
lost to competitor suppliers. As of March 2004, alternative electric suppliers
are providing 735 MW of load. This amount represents nine percent of the total
distribution load and an increase of 42 percent compared to March 2003.
We cannot predict whether the Stranded Cost recovery method adopted by the
MPSC will be applied in a manner that will fully offset any associated margin
loss from ROA. In February 2004, the MPSC issued an order on Detroit Edison's
request for rate relief for costs associated with customers leaving under
electric customer choice. The MPSC order allows Detroit Edison to charge a
transition surcharge of approximately 0.4 cent per kWh to ROA customers and
eliminates securitization offsets of 0.7 cents per kWh for primary service
customers and 0.9 cents per kWh for secondary service customers. We are seeking
similar recovery of Stranded Costs due to ROA customers leaving our system and
are encouraged by this ruling.
ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric
restructuring proceedings. They are:
- Securitization,
- Stranded Costs,
- implementation costs, and
- transmission.
Securitization: The Customer Choice Act allows for the use of
Securitization bonds to refinance certain qualified costs. Since Securitization
involves issuing bonds secured by a revenue stream from rates collected directly
from customers to service the bonds, Securitization bonds typically have a
higher credit rating than conventional utility corporate financing. In 2000 and
2001, the MPSC issued orders authorizing us to issue Securitization bonds. We
issued our first Securitization bonds in late 2001. Securitization resulted in:
- lower interest costs, and
- longer amortization periods for the securitized assets.
We will recover the repayment of principal, interest, and other expenses
relating to the bond issuance through a Securitization charge and a tax charge
that began in December 2001. These charges are subject to an annual true up
until one year prior to the last scheduled bond maturity date, and no more than
quarterly thereafter. The December 2003 true up modified the total
Securitization and related tax charges from 1.746 mills per kWh to 1.718 mills
per kWh. There will be no impact on customer bills from Securitization for most
of our electric customers until the Customer Choice Act cap period expires, and
an electric rate case is processed. Securitization charge collections, $50
million for the twelve months ended December 31, 2003, and $52 million for the
twelve months ended December 31, 2002, are remitted to a trustee. Securitization
charge collections are restricted to the repayment of the principal and interest
on the Securitization bonds and payment of the ongoing expenses of Consumers
Funding. Consumers Funding is legally separate from Consumers. The assets and
income of Consumers Funding, including the securitized property, are not
available to creditors of Consumers or CMS Energy.
In March 2003, we filed an application with the MPSC seeking approval to
issue additional Securitization bonds. In June 2003, the MPSC issued a financing
order authorizing the issuance of Securitization bonds in the amount of $554
million. This amount relates to Clean Air Act expenditures and associated return
on those expenditures through December 31, 2002; ROA implementation costs, and
previously authorized return on those expenditures through December 31, 2000;
and other up front qualified costs related to issuance of the Securitization
bonds. The MPSC rejected the portion of the application related to pension
costs. The MPSC based its decision on the reasoning that a rebounding economy
and stock market could potentially reverse recent Pension Plan losses. Also, the
MPSC rejected Palisades expenditures previously not securitized as eligible
securitized costs; therefore, these costs will be
F-78
included in a future electric rate case proceeding with the MPSC and as a
component of the 2002 net Stranded Cost calculation. In July 2003, we filed for
rehearing and clarification on a number of features in the financing order.
In December 2003, the MPSC issued its order on rehearing, which rejected
our requests for clarification and modification to the dividend payment
restriction, failed to rule directly on the accounting clarifications requested,
and remanded the proceeding to the ALJ for additional proceedings to address
rate design. We filed testimony regarding the remanded proceeding in February
2004. The financing order will become effective after acceptance by us and
resolution of any appeals.
Stranded Costs: The Customer Choice Act allows electric utilities to
recover their net Stranded Costs, without defining the term. The Act directs the
MPSC to establish a method of calculating net Stranded Costs and of conducting
related true-up adjustments. In December 2001, the MPSC Staff recommended a
methodology, which calculated net Stranded Costs as the shortfall between:
- the revenue required to cover the costs associated with fixed
generation assets and capacity payments associated with purchase
power agreements, and
- the revenues received from customers under existing rates available
to cover the revenue requirement.
We are authorized by the MPSC to use deferred accounting to recognize the
future recovery of costs determined to be stranded. According to the MPSC, net
Stranded Costs are to be recovered from ROA customers through a Stranded Cost
transition charge. However, the MPSC has not yet allowed such a transition
charge and we have not recorded regulatory assets to recognize the future
recovery of such costs.
In 2002 and 2001, the MPSC issued orders finding that we experienced zero
net Stranded Costs from 1999 to 2001. The MPSC also declined to resolve numerous
issues regarding the net Stranded Cost methodology in a way that would allow a
reliable prediction of the level of Stranded Costs for future years. We are
currently in the process of appealing these orders with the Michigan Court of
Appeals and the Michigan Supreme Court.
In March 2003, we filed an application with the MPSC seeking approval of
net Stranded Costs incurred in 2002, and for approval of a net Stranded Cost
recovery charge. Our net Stranded Costs incurred in 2002 are estimated to be $38
million with the issuance of Securitization bonds that include Clean Air Act
investments, or $85 million without the issuance of Securitization bonds that
include Clean Air Act investments. The MPSC scheduled hearings for our 2002
Stranded Cost application to take place during the second quarter of 2004.
Once a final financing order on Securitization is reached, we will know
the amount of our request for net Stranded Cost recovery for 2002. We cannot
predict how the MPSC will rule on our request for the recoverability of Stranded
Costs.
Implementation Costs: Since 1997, we have incurred significant electric
utility restructuring implementation costs. The Customer Choice Act allows
electric utilities to recover their implementation costs. The following table
outlines the applications filed by us with the MPSC and the status of recovery
for these costs.
YEAR FILED YEAR INCURRED REQUESTED PENDING ALLOWED DISALLOWED
-------------- ------------- --------- ------- ------- ----------
IN MILLIONS
1999.......... 1997 & 1998 $ 20 $ -- $ 15 $ 5
2000.......... 1999 30 -- 25 5
2001.......... 2000 25 -- 20 5
2002.......... 2001 8 -- 8 --
2003.......... 2002 2 2 Pending Pending
The MPSC disallowed certain costs, determining that these amounts did not
represent costs incremental to costs already reflected in electric rates. In the
order received for the year 2001, the MPSC also reserved the right to reevaluate
the implementation costs depending upon the progress and success of the ROA
program, and ruled that due to the rate freeze imposed by the Customer Choice
Act, it was premature to establish a cost recovery method for the allowable
implementation costs. In addition to the amounts shown above, we incurred and
deferred as a
F-79
regulatory asset, as of December 31, 2003, $2 million of additional
implementation costs and $19 million for the cost of money associated with total
implementation costs. We believe the implementation costs and associated cost of
money are fully recoverable in accordance with the Customer Choice Act. Cash
recovery from customers is expected to begin after the rate cap period expires.
The rate cap expired for large commercial and industrial customers on December
31, 2003. We have asked to include implementation costs through December 31,
2000 in the pending Securitization case. If approved, the sale of Securitization
bonds will allow for the recovery of a significant portion of these costs. We
cannot predict the amount the MPSC will approve as allowable costs.
Also, we are pursuing authorization at the FERC for MISO to reimburse us
for $8 million in certain electric utility restructuring implementation costs
related to our former participation in the development of the Alliance RTO, a
portion of which has been expensed. In May 2003, the FERC issued an order
denying MISO's request for authorization to reimburse us. In June 2003, we filed
a joint petition with MISO for rehearing with the FERC, which the FERC denied in
September 2003. We appealed the FERC ruling at the United States Court of
Appeals for the District of Columbia and are pursuing other potential means of
recovery at the FERC. In conjunction with our appeal of the September order
denying recovery, MISO agreed to file a request with the FERC seeking authority
to reimburse METC. As part of the contract for the sale of our former
transmission system, should the FERC approve the new MISO filing, METC is
contractually obligated to flow-through to us the full amount of any Alliance
RTO start-up costs that it is authorized to recover by FERC. We cannot predict
the outcome of the appeal process, the MISO request, or the ultimate amount, if
any, FERC will allow us to collect for implementation costs.
Transmission Rates: Our application of JOATT transmission rates to
customers during past periods is under FERC review. The rates included in these
tariffs were applied to certain transmission transactions affecting both Detroit
Edison's and our transmission systems between 1997 and 2002. We believe our
reserve is sufficient to satisfy our refund obligation to any of our former
transmission customers under our former JOATT.
TRANSMISSION SALE: In May 2002, we sold our electric transmission system
for $290 million to MTH, a non-affiliated limited partnership whose general
partner is a subsidiary of Trans-Elect, Inc. The pretax gain was $31 million
($26 million, net of tax). We are currently in arbitration with MTH regarding
property tax items used in establishing the selling price of our electric
transmission system. We cannot predict whether the remaining open items will
impact materially the recorded gain on the sale.
As a result of the sale, after-tax earnings have decreased due to a loss
of revenue from wholesale and ROA customers who will buy services directly from
MTH.
METC has completed the capital program to expand the transmission system's
capability to import electricity into Michigan, as required by the Customer
Choice Act. We will continue to maintain the system until May 1, 2007 under a
contract with METC.
Under an agreement with MTH, transmission rates charged to us are fixed by
contract at current levels through December 31, 2005, and are subject to FERC
ratemaking thereafter. However, we are subject to certain additional MISO
surcharges, which are estimated to be $15 million in 2004.
CONSUMERS' ELECTRIC UTILITY RATE MATTERS
AUGUST 14, 2003 BLACKOUT: On August 14, 2003, the electric transmission
grid serving parts of the Midwest and the Northeast experienced a significant
disturbance that impacted electric service to millions of homes and businesses.
Approximately 100,000 of our 1.7 million electric customers were without power
for approximately 24 hours as a result of the disturbance. We incurred $1
million of immediate expense as a result of the blackout. We continue to
cooperate with investigations of the blackout by several federal and state
agencies. We cannot predict the outcome of these investigations.
In November 2003, the MPSC released its report on the blackout. The MPSC
report found no evidence to suggest that the events in Michigan or actions taken
by the Michigan utilities or transmission operators were factors contributing to
the cause of the blackout. Also in November 2003, the United States and Canadian
power system outage task force preliminarily reported that the primary cause of
the blackout was due to transmission line contact with trees in areas outside of
Consumers' operating territory. In December 2003, the MPSC issued an order
F-80
requiring Michigan investor-owned utilities to file reports by April 1, 2004, on
the status of the transmission and distribution lines used to serve their
customers, including details on vegetation trimming practices in calendar year
2003. Consumers intends to comply with the MPSC's request.
In February 2004, the Board of Trustees of NERC approved recommendations
to improve electric transmission reliability. The key recommendations are as
follows:
- strengthen the NERC compliance enforcement program,
- evaluate vegetation management procedures, and
- improve technology to prevent or mitigate future blackouts.
These recommendations require transmission operators, which Consumers is
not, to submit annual reports on vegetation management beginning March 2005 and
improve technology over various milestones throughout 2004. These
recommendations could result in increased transmission costs payable by
transmission customers in the future. The financial impacts of these
recommendations are not currently quantifiable.
PERFORMANCE STANDARDS: Electric distribution performance standards
developed by the MPSC were in proposal status during 2002 and 2003. The
performance standards were placed into Michigan law in January 2004 and became
effective on February 9, 2004. They relate to restoration after an outage,
safety, and customer relations. During 2002 and 2003, Consumers monitored and
reported to the MPSC its performance relative to the performance standards.
Year-end results for both 2002 and 2003 resulted in compliance with the
acceptable level of performance as established by the approved standards.
Financial incentives and penalties are contained within the performance
standards. An incentive is possible if all of the established performance
standards have been exceeded for a calendar year. However, the value of such
incentive cannot be determined at this point as the performance standards do not
contain an approved incentive mechanism. Financial penalties in the form of
customer credits are also possible. These customer credits are based on duration
and repetition of outages. We cannot predict the likely effects of the financial
incentive or penalties, if any, on us.
POWER SUPPLY COSTS: We were required to provide backup service to ROA
customers on a best efforts basis. In October 2003, we provided notice to the
MPSC that we would terminate the provision of backup service in accordance with
the Customer Choice Act, effective January 1, 2004.
To reduce the risk of high electric prices during peak demand periods and
to achieve our reserve margin target, we employ a strategy of purchasing
electric call option and capacity and energy contracts for the physical delivery
of electricity primarily in the summer months and to a lesser degree in the
winter months. As of December 31, 2003, we purchased capacity and energy
contracts partially covering the estimated reserve margin requirements for 2004
through 2007. As a result, we have recognized an asset of $20 million for
unexpired capacity and energy contracts. Currently, we have a reserve margin of
5 percent, or supply resources equal to 105 percent of projected summer peak
load for summer 2004. We are in the process of securing the additional capacity
needed to meet our summer 2004 reserve margin target of 11 percent (111 percent
of projected summer peak load). The total premium costs of electricity call
option and capacity and energy contracts for 2003 were approximately $10
million.
As a result of meeting the transmission capability expansion requirements
and the market power test, as discussed in this note, we have met the
requirements under the Customer Choice Act to return to the PSCR process. The
PSCR process provides for the reconciliation of actual power supply costs with
power supply revenues. This process assures recovery of all reasonable and
prudent power supply costs actually incurred by us. In September 2003, we
submitted a PSCR filing to the MPSC that reinstates the PSCR process for
customers whose rates are no longer frozen or capped as of January 1, 2004. The
proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers, and subject to the
overall rate cap, from other customers. We estimate the recovery of increased
power supply costs from large commercial and industrial customers to be
approximately $30 million in 2004. As allowed under current regulation, we
self-implemented the proposed PSCR charge on January 1, 2004. The revenues
received from the PSCR charge are also
F-81
subject to subsequent reconciliation at the end of the year after actual costs
have been reviewed for reasonableness and prudence. We cannot predict the
outcome of this filing.
OTHER CONSUMERS' ELECTRIC UTILITY UNCERTAINTIES
THE MIDLAND COGENERATION VENTURE: The MCV Partnership, which leases and
operates the MCV Facility, contracted to sell electricity to Consumers for a
35-year period beginning in 1990 and to supply electricity and steam to Dow. We
hold, through two wholly owned subsidiaries, the following assets related to the
MCV Partnership and MCV Facility:
- CMS Midland owns a 49 percent general partnership interest in the
MCV Partnership, and
- CMS Holdings holds, through FMLP, a 35 percent lessor interest in
the MCV Facility.
Our consolidated retained earnings include undistributed earnings from the
MCV Partnership, which at December 31, 2003 are $245 million and at December 31,
2002 are $226 million.
SUMMARIZED STATEMENTS OF INCOME FOR CMS MIDLAND AND CMS HOLDINGS
YEARS ENDED
DECEMBER 31
------------------
2003 2002 2001
----- ------ -----
IN MILLIONS
Earnings from equity method investees............................. $ 42 $ 52 $ 38
Operating expenses, taxes and other............................... 22 18 13
----- ------ -----
Income before cumulative effect of accounting change.............. $ 20 $ 34 $ 25
Cumulative effect of change in method of accounting for
derivatives, net of $10 million tax expense in 2002 (Note 15)... -- 18 --
----- ------ -----
Net income........................................................ $ 20 $ 52 $ 25
===== ====== =====
Power Supply Purchases from the MCV Partnership: Our annual obligation to
purchase capacity from the MCV Partnership is 1,240 MW through the term of the
PPA ending in 2025. The PPA requires us to pay, based on the MCV Facility's
availability, a levelized average capacity charge of 3.77 cents per kWh and a
fixed energy charge. We also pay a variable energy charge based on our average
cost of coal consumed for all kWh delivered. Effective January 1999, we reached
a settlement agreement with the MCV Partnership that capped payments made on the
basis of availability that may be billed by the MCV Partnership at a maximum
98.5 percent availability level.
Since January 1993, the MPSC has permitted us to recover capacity charges
averaging 3.62 cents per kWh for 915 MW, plus fixed and variable energy charges.
Since January 1996, the MPSC has also permitted us to recover capacity charges
for the remaining 325 MW of contract capacity with an initial average charge of
2.86 cents per kWh increasing periodically to an eventual 3.62 cents per kWh by
2004 and thereafter. However, due to the frozen retail rates required by the
Customer Choice Act, the capacity charge for the 325 MW was frozen at 3.17 cents
per kWh until December 31, 2003. Recovery of both the 915 MW and 325 MW portions
of the PPA are subject to certain limitations discussed below.
In 1992, we recognized a loss and established a liability for the present
value of the estimated future underrecoveries of power supply costs under the
PPA based on MPSC cost-recovery orders. The remaining liability associated with
the loss totaled $27 million at December 31, 2003, $53 million at December 31,
2002, and $77 million at December 31, 2001. We expect the PPA liability to be
depleted in late 2004.
We estimate that 51 percent of the actual cash underrecoveries for 2004
will be charged to the PPA liability, with the remaining portion charged to
operating expense as a result of our 49 percent ownership in the MCV
Partnership. We will expense all cash underrecoveries directly to income once
the PPA liability is depleted. If the MCV Facility's generating availability
remains at the maximum 98.5 percent level, our cash underrecoveries associated
with the PPA could be as follows:
F-82
2004 2005 2006 2007
---- ---- ---- ----
IN MILLIONS
Estimated cash underrecoveries at 98.5%....... $ 56 $ 56 $ 55 $ 39
Amount to be charged to operating expense..... 29 56 55 39
Amount to be charged to PPA liability......... 27 -- -- --
Beginning January 1, 2004, the rate freeze for large industrial customers
was no longer in effect and we returned to the PSCR process. Under the PSCR
process, we will recover from our customers the capacity and fixed energy
charges based on availability, up to an availability cap of 88.7 percent as
established in previous MPSC orders.
Effects on Our Ownership Interest in the MCV Partnership and MCV Facility:
As a result of returning to the PSCR process, we returned to dispatching the MCV
Facility on a fixed load basis, as permitted by the MPSC, in order to maximize
recovery of our capacity payments. This fixed load dispatch increases the MCV
Facility's output and electricity production costs, such as natural gas. As the
spread between the MCV Facility's variable electricity production costs and its
energy payment revenue widens, the MCV's Partnership's financial performance and
our equity interest in the MCV Partnership may be affected negatively.
Under the PPA, variable energy payments to the MCV Partnership are based
on the cost of coal burned at our coal plants and operation and maintenance
expenses. However, the MCV Partnership's costs of producing electricity are tied
to the cost of natural gas. Because natural gas prices have increased
substantially in recent years, while the price the MCV Partnership can charge us
for energy has not, the MCV Partnership's financial performance has been
impacted negatively.
Until September 2007, the PPA and settlement require us to pay capacity
and fixed energy charges based on the MCV Facility's actual availability up to
the 98.5 percent cap. After September 2007, we expect to exercise the regulatory
out provision in the PPA, limiting our capacity and fixed energy payments to the
MCV Partnership to the amount collected from our customers. The MPSC's future
actions on the capacity and fixed energy payments recoverable from customers
subsequent to September 2007 may affect negatively the earnings of the MCV
Partnership and the value of our equity interest in the MCV Partnership.
In February 2004, we filed a resource conservation plan with the MPSC that
is intended to help conserve natural gas and thereby improve our equity
investment in the MCV Partnership. This plan seeks approval to:
- dispatch the MCV Facility on an economic basis depending on natural
gas market prices without increased costs to electric customers,
- give Consumers a priority right to buy excess natural gas as a
result of the reduced dispatch of the MCV Facility, and
- fund $5 million annually for renewable energy sources such as wind
power projects.
The resource conservation plan will reduce the MCV Facility's annual
natural gas consumption by an estimated 30 to 40 billion cubic feet. This
decrease in the quantity of high-priced natural gas consumed by the MCV Facility
will benefit Consumers' ownership interest in the MCV Partnership. The amount of
PPA capacity and fixed energy payments recovered from retail electric customers
would remain capped at 88.7 percent. Therefore, customers will not be charged
for any increased power supply costs, if they occur. Consumers and the MCV
Partnership have reached an agreement that the MCV Partnership will reimburse
Consumers for any incremental power costs incurred to replace the reduction in
power dispatched from the MCV Facility. We requested that the MPSC provide
interim approval while it conducts a full review of the plan. The MPSC has
scheduled a prehearing conference with respect to the MCV resource conservation
plan for April 2004. We cannot predict if or when the MPSC will approve our
request.
The two most significant variables in the analysis of the MCV
Partnership's future financial performance are the forward price of natural gas
for the next 22 years and the MPSC's decision in 2007 or beyond on our recovery
of capacity payments. Natural gas prices have been historically volatile.
Presently, there is no consensus in the
F-83
marketplace on the price or range of prices of natural gas in the short term or
beyond the next five years. Therefore, we cannot predict the impact of these
issues on our future earnings, cash flows, or on the value of our equity
interest in the MCV Partnership.
NUCLEAR MATTERS: Big Rock: Significant progress continues to be made in
the decommissioning of Big Rock. We submitted the License Termination Plan to
the NRC staff for review in April 2003. System dismantlement and building
demolition are on schedule to return the 560-acre site to a natural setting for
unrestricted use in early 2006. The NRC and Michigan Department of Environmental
Quality continue to find that all decommissioning activities at Big Rock are
being performed in accordance with applicable regulatory and license
requirements.
Seven transportable dry casks have been loaded with spent nuclear fuel and
an eighth cask has been loaded with high-level radioactive waste material. These
dry casks will remain onsite until the DOE moves the material to a national
spent nuclear fuel repository.
Palisades: In July 2003, the NRC completed its mid-cycle plant performance
assessment of Palisades. The mid-cycle assessment for Palisades covered the
period from January 1, 2003 through the end of July 2003. The NRC determined
that Palisades was operated in a manner that preserved public health and safety
and fully met all cornerstone objectives. Based on the plant's performance, only
regularly scheduled inspections are planned through September 2004.
The amount of spent nuclear fuel exceeds Palisades' temporary onsite
storage pool capacity. We are using dry casks for temporary onsite storage. As
of December 31, 2003, we have loaded 18 dry casks with spent nuclear fuel and we
will need to load additional dry casks by the fall of 2004 in order to continue
operation. Palisades currently has three empty dry casks onsite, with storage
pad capacity for up to seven additional loaded dry casks. We anticipate that
transportable dry casks, along with more storage pad capacity, will be available
by fall 2004.
DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that
the DOE was to begin accepting deliveries of spent nuclear fuel for disposal by
January 1998. Subsequent U.S. Court of Appeals litigation, in which we and other
utilities participated, has not been successful in producing more specific
relief for the DOE's failure to accept the spent nuclear fuel.
There are two court decisions that support the right of utilities to
pursue damage claims in the United States Court of Claims against the DOE for
failure to take delivery of spent nuclear fuel. A number of utilities have
initiated litigation in the United States Court of Claims; we filed our
complaint in December 2002. If our litigation against the DOE is successful, we
anticipate future recoveries from the DOE. The recoveries will be used to pay
the cost of spent nuclear fuel storage until the DOE takes possession as
required by law. We can make no assurance that the litigation against the DOE
will be successful.
In July 2002, Congress approved and the President signed a bill
designating the site at Yucca Mountain, Nevada, for the development of a
repository for the disposal of high-level radioactive waste and spent nuclear
fuel. The next step will be for the DOE to submit an application to the NRC for
a license to begin construction of the repository. The application and review
process is estimated to take several years.
Spent nuclear fuel complaint: In March 2003, the Michigan Environmental
Council, the Public Interest Research Group in Michigan, and the Michigan
Consumer Federation filed a complaint with the MPSC, which was served on us by
the MPSC in April 2003. The complaint asks the MPSC to initiate a generic
investigation and contested case to review all facts and issues concerning costs
associated with spent nuclear fuel storage and disposal. The complaint seeks a
variety of relief with respect to Consumers, Detroit Edison, Indiana & Michigan
Electric Company, Wisconsin Electric Power Company, and Wisconsin Public Service
Corporation. The complaint states that amounts collected from customers for
spent nuclear storage and disposal should be placed in an independent trust. The
complaint also asks the MPSC to take additional actions. In May 2003, Consumers
and other named utilities each filed motions to dismiss the complaint. We are
unable to predict the outcome of this matter.
Insurance: We maintain nuclear insurance coverage on our nuclear plants.
At Palisades, we maintain nuclear property insurance from NEIL, totaling $2.750
billion and insurance that would partially cover the cost of replacement power
during certain prolonged accidental outages. Because NEIL is a mutual insurance
company, we
F-84
could be subject to assessments of up to $26 million in any policy year if
insured losses in excess of NEIL's maximum policyholders surplus occur at our,
or any other member's, nuclear facility. NEIL's policies include coverage for
acts of terrorism.
At Palisades, we maintain nuclear liability insurance for third-party
bodily injury and off-site property damage resulting from a nuclear hazard for
up to approximately $10.862 billion, the maximum insurance liability limits
established by the Price-Anderson Act. The United States Congress enacted the
Price-Anderson Act to provide financial liability protection for those parties
who may be liable for a nuclear accident or incident. Part of the Price-Anderson
Act's financial protection is a mandatory industry-wide program where owners of
nuclear generating facilities could be assessed if a nuclear incident occurs at
any nuclear generating facility. The maximum assessment against us could be $101
million per occurrence, limited to maximum annual installment payments of $10
million.
We also maintain insurance under a program that covers tort claims for
bodily injury to nuclear workers caused by nuclear hazards. The policy contains
a $300 million nuclear industry aggregate limit. Under a previous insurance
program providing coverage for claims brought by nuclear workers, we remain
responsible for a maximum assessment of up to $6 million.
Big Rock remains insured for nuclear liability by a combination of
insurance and a NRC indemnity totaling $544 million and a nuclear property
insurance policy from NEIL.
Insurance policy terms, limits, and conditions are subject to change
during the year as we renew our policies.
COMMITMENTS FOR FUTURE PURCHASES: We enter into a number of unconditional
purchase obligations that represent normal business operating contracts. These
contracts are used to assure an adequate supply of goods and services necessary
for the operation of our business and to minimize exposure to market price
fluctuations. We believe that these future costs are prudent and reasonably
assured of recovery in future rates.
Coal Supply and Transportation: We have entered into coal supply contracts
with various suppliers for our coal-fired generating stations. Under the terms
of these agreements, we are obligated to take physical delivery of the coal and
make payment based upon the contract terms. Our coal supply contracts expire
from 2004 to 2005, and total an estimated $177 million. Our coal transportation
contracts expire from 2004 to 2007, and total an estimated $139 million.
Long-term coal supply contracts account for approximately 60 to 90 percent of
our annual coal requirements. In 2003, coal purchases totaled $265 million of
which $207 million (78 percent of the tonnage requirement) was under long-term
contract. We supplement our long-term contracts with spot-market purchases.
Power Supply, Capacity, and Transmission: As of December 31, 2003, we had
future unrecognized commitments to purchase power transmission services under
fixed price forward contracts for 2004 and 2005 totaling $8 million. We also had
commitments to purchase capacity and energy under long-term power purchase
agreements with various generating plants including the MCV Facility. These
contracts require monthly capacity payments based on the plants' availability or
deliverability. These payments for 2004 through 2030 total an estimated $14.483
billion, undiscounted, which includes $11.381 billion related to the MCV
Facility. These payments exclude the obligations that Consumers has with the
Genesee, Grayling, and Filer City generating plants because these entities are
consolidated for CMS Energy under FASB Interpretation No. 46. This amount may
vary depending upon plant availability and fuel costs. If a plant was not
available to deliver electricity to us, then we would not be obligated to make
the capacity payment until the plant could deliver.
CONSUMERS' GAS UTILITY CONTINGENCIES
GAS ENVIRONMENTAL MATTERS: We expect to have investigation and remedial
costs at a number of sites under the Michigan Natural Resources and
Environmental Protection Act, a Michigan statute that covers environmental
activities including remediation. These sites include 23 former manufactured gas
plant facilities. We operated the facilities on these sites for some part of
their operating lives. For some of these sites, we have no current ownership or
may own only a portion of the original site. We have completed initial
investigations at the 23 sites. We will continue to implement remediation plans
for sites where we have received MDEQ remediation plan approval. We will also
work toward resolving environmental issues at sites as studies are completed.
F-85
We have estimated our costs for investigation and remedial action at all
23 sites using the Gas Research Institute-Manufactured Gas Plant Probabilistic
Cost Model. We expect our remaining costs to be between $37 million and $90
million. The range reflects multiple alternatives with various assumptions for
resolving the environmental issues at each site. The estimates are based on
discounted 2003 costs using a discount rate of three percent. The discount rate
represents a ten-year average of U.S. Treasury bond rates reduced for increases
in the consumer price index. We expect to fund most of these costs through
insurance proceeds and through MPSC approved rates charged to our customers. As
of December 31, 2003, we have recorded a liability of $44 million, net of $38
million of expenditures incurred to date, and a regulatory asset of $67 million.
Any significant change in assumptions, such as an increase in the number of
sites, different remediation techniques, nature and extent of contamination, and
legal and regulatory requirements, could affect our estimate of remedial action
costs.
In its November 2002 gas distribution rate order, the MPSC authorized us
to continue to recover approximately $1 million of manufactured gas plant
facilities environmental clean-up costs annually. This amount will continue to
be offset by $2 million to reflect amounts recovered from all other sources. We
defer and amortize, over a period of 10 years, manufactured gas plant facilities
environmental clean-up costs above the amount currently included in rates.
Additional amortization of the expense in our rates cannot begin until after a
prudency review in a gas rate case.
CONSUMERS' GAS UTILITY RATE MATTERS
GAS COST RECOVERY: The MPSC is required by law to allow us to charge
customers for our actual cost of purchased natural gas. The GCR process is
designed to allow us to recover all of our gas costs; however, the MPSC reviews
these costs for prudency in an annual reconciliation proceeding. In June 2003,
we filed a reconciliation of GCR costs and revenues for the 12-months ended
March 2003. We proposed to recover from our customers approximately $6 million
of under-recovered gas costs using a roll-in methodology. The roll-in
methodology incorporates the GCR under-recovery in the next GCR plan year. The
approach was approved by the MPSC in a November 2002 order.
In January 2004, intervenors filed their positions in our 2003 GCR case.
Their positions were that not all of our gas purchasing decisions were prudent
during April 2002 through March 2003 and they proposed disallowances. In
February 2004, the parties in the case reached a tentative settlement agreement
that would result in a GCR disallowance of $11 million for the GCR period.
Interest on the disallowed amount from April 1, 2003 through February 2004, at
the Consumers' authorized rate of return, adds $1 million to the cost of the
settlement. We believe this settlement agreement will be executed by the parties
in the case in the near future and approved by the MPSC. A reserve was recorded
in December 2003.
In July 2003, the MPSC approved a settlement agreement authorizing us to
increase our gas cost recovery for the remainder of the current GCR plan year
(August 2003 through March 2004) and to apply a quarterly ceiling price
adjustment, based on a formula that tracks changes in NYMEX natural gas prices.
The terms of the settlement allow a GCR ceiling price of $6.11 per mcf. Our GCR
is $5.36 per mcf for March 2004 bills.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC
for a $156 million annual increase in our gas delivery and transportation rates
that included a 13.5 percent return on equity. In September 2003, we filed an
update to our gas rate case that lowered the requested revenue increase from
$156 million to $139 million and reduced the return on common equity from 13.5
percent to 12.75 percent. The MPSC authorized an interim gas rate increase of
$19 million annually. The interim increase is under bond and subject to refund
if the final rate relief is a lesser amount. The interim increase order includes
a $34 million reduction in book depreciation expense and related income taxes
effective only during the period that we receive the interim relief. The MPSC
order allowed us to increase our rates beginning December 19, 2003. As part of
the interim order, Consumers agreed to restrict its dividend payments to CMS
Energy, to a maximum of $190 million annually during the period that Consumers
receives the interim relief. On March 5, 2004, the ALJ issued a Proposal for
Decision recommending that the MPSC not rely upon the projected test year data
included in our filing and supported by the MPSC Staff and further recommended
that the application be dismissed. The MPSC is not bound by these
recommendations and will consider the issues anew after receipt of exceptions
and replies to the exception filed by the parties in response to the Proposal
for Decision.
F-86
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our
gas utility plant depreciation case originally filed in June 2001. This case is
independent of the 2003 gas rate case. The original filing was based on December
2000 plant balances and historical data. The December 2003 filing updates the
gas depreciation case to include December 2002 plant balances. The proposed
depreciation rates, if approved, will result in an annual increase of $12
million in depreciation expense.
OTHER CONSUMERS' GAS UTILITY UNCERTAINTIES
COMMITMENTS FOR GAS SUPPLIES: We enter into contracts to purchase gas and
gas transportation from various suppliers for our natural gas business. These
contracts have expiration dates that range from 2004 to 2007. Our 2003 gas
purchases totaled 248 bcf at a cost of $1.379 billion. At the end of 2003, we
estimate our gas purchases for 2004 to be 235 bcf, of which 22 percent is
covered by existing fixed price contracts and 37 percent is covered by indexed
price contracts that are subject to price variations. The remaining 2004 gas
purchases will be made at market prices at the time of purchase.
OTHER CONSUMERS' UNCERTAINTIES
In addition to the matters disclosed in this note, we are parties to
certain lawsuits and administrative proceedings before various courts and
governmental agencies arising from the ordinary course of business. These
lawsuits and proceedings may involve personal injury, property damage,
contractual matters, environmental issues, federal and state taxes, rates,
licensing, and other matters.
We have accrued estimated losses for certain contingencies discussed in
this note. Resolution of these contingencies is not expected to have a material
adverse impact on our financial position, liquidity, or results of operations.
OTHER UNCERTAINTIES
INTEGRUM LAWSUIT: Integrum filed a complaint in Wayne County, Michigan
Circuit Court in July 2003 against CMS Energy, Enterprises and APT. Integrum
alleges several causes of action against APT, CMS Energy, and Enterprises in
connection with an offer by Integrum to purchase the CMS Pipeline Assets. In
addition to seeking unspecified money damages, Integrum is seeking an order
enjoining CMS Energy and Enterprises from selling and APT from purchasing the
CMS Pipeline Assets and an order of specific performance mandating that CMS
Energy, Enterprises, and APT complete the sale of the CMS Pipeline Assets to APT
and Integrum. A certain officer and director of Integrum is a former officer and
director of CMS Energy, Consumers, and their subsidiaries. The individual was
not employed by CMS Energy, Consumers or their subsidiaries when Integrum made
the offer to purchase the CMS Pipeline Assets. CMS Energy believes that
Integrum's claims are without merit. CMS Energy will defend itself vigorously
but cannot predict the outcome of this lawsuit.
CMS GENERATION-OXFORD TIRE RECYCLING: In an administrative order, the
California Regional Water Control Board of the state of California named CMS
Generation as a potentially responsible party for the clean up of the waste from
the fire that occurred in September 1999 at the Filbin Tire Pile, which the
State claims was owned by Oxford Tire Recycling of North Carolina, Inc. CMS
Generation reached a settlement with the state, which the court approved,
pursuant to which CMS Generation paid the state $5.5 million, $1.6 million of
which it had paid the state prior to the settlement. CMS Generation continues to
negotiate to have the insurance company pay a portion of the settlement amount,
as well as a portion of its attorney fees.
At the request of the DOJ in San Francisco, CMS Energy and other parties
contacted by the DOJ in San Francisco entered into separate Tolling Agreements
with the DOJ in San Francisco in September 2002. The Tolling Agreement stops the
running of any statute of limitations during the ninety-day period between
September 13, 2002 and (through several extensions of the tolling period) March
30, 2004, to facilitate settlement discussions between all the parties in
connection with federal claims arising from the fire at the Filbin Tire Pile. On
September 23, 2002, CMS Energy received a written demand from the U.S. Coast
Guard for reimbursement of approximately $3.5 million in costs incurred by the
U.S. Coast Guard in fighting the fire. It is CMS Energy's understanding that
these costs, together with any accrued interest, are the sole basis of any
federal claims. CMS Energy has reached an agreement in principle with the U.S.
Coast Guard to settle this matter for $475,000.
F-87
DEARBORN INDUSTRIAL GENERATION: In October 2001, Duke/Fluor Daniel (DFD)
presented DIG with a change order to their construction contract and filed an
action in Michigan state court claiming damages in the amount of $110 million,
plus interest and costs, which DFD states represents the cumulative amount owed
by DIG for delays DFD believes DIG caused and for prior change orders that DIG
previously rejected. DFD also filed a construction lien for the $110 million.
DIG, in addition to drawing down on three letters of credit totaling $30 million
that it obtained from DFD, has filed an arbitration claim against DFD asserting
in excess of an additional $75 million in claims against DFD. The judge in the
Michigan state court case entered an order staying DFD's prosecution of its
claims in the court case and permitting the arbitration to proceed. DFD has
appealed the decision by the judge in the Michigan state court case to stay the
litigation. DIG will continue to defend itself vigorously and pursue its claims.
DIG cannot predict the outcome of this matter.
DIG CUSTOMER DISPUTES: As a result of the continued delays in the DIG
project becoming fully operational, DIG's customers, Ford Motor Company, and
Rouge Industries, asserted claims that the continued delays relieve them of
certain contractual obligations, totaling $43 million. In addition, Ford and/or
Rouge asserted several other commercial claims against DIG relating to operation
of the DIG plant. In February 2003, Rouge filed an Arbitration Demand against
DIG and CMS MST Michigan L.L.C. with the American Arbitration Association. Rouge
was seeking a total of approximately $27 million, plus additional accrued
damages at the time of any award, plus interest. More specifically, Rouge was
seeking at least $20 million under a Blast Furnace Gas Delivery Agreement in
connection with DIG's purported failure to declare a Blast Furnace Gas Delivery
Date within a reasonable time period, plus approximately $7 million for assorted
damage claims under several legal theories. As part of this arbitration, DIG
filed claims against Rouge and Ford, and Ford filed claims for unspecified
amounts against DIG. In October 2003, Rouge filed bankruptcy under Chapter 11 of
the United States Bankruptcy Code and as a result, the arbitration was subject
to the automatic stay imposed by the Bankruptcy Code. OAO Severstal, which has
acquired substantially all of Rouge's assets, has indicated it will continue
operations at the Rouge site and will honor the contractual obligations to pay
for the steam and electricity DIG and CMS MST Michigan L.L.C. provide. In
January 2004, DIG and CMS MST Michigan L.L.C. entered into a settlement
agreement with Ford and Rouge to resolve all outstanding claims between the
parties, including the arbitration claims and DIG and CMS MST Michigan L.L.C.'s
claims in the Rouge bankruptcy. The settlement was approved by the bankruptcy
court. Under the settlement, Ford paid DIG $12 million cash and Rouge and Ford
paid DIG and CMS MST Michigan L.L.C. a total of $3.8 million owed by Rouge for
steam and electricity supplied to Rouge prior to the filing of the bankruptcy
petition.
DIG NOISE ABATEMENT LAWSUIT: In February 2003, DIG was served with a
three-count first amended complaint filed in Wayne County Circuit Court in the
matter of Ahmed, et al v. Dearborn Industrial Generation, LLC. The complaint
seeks damages "in excess of $25,000" and injunctive relief based upon
allegations of excessive noise and vibration created by operation of the power
plant. The first amended complaint was filed on behalf of six named plaintiffs,
all alleged to be adjacent or nearby resident or property owners. The damages
alleged are injury to persons and property of the landowners. Certification of a
class of "potentially thousands" who have been similarly affected is requested.
DIG intends to defend this action aggressively but cannot predict the outcome of
this matter.
MCV EXPANSION, LLC: Under an agreement entered into with General Electric
Company ("GE") in October 2002, MCV Expansion, LLC has a remaining contingent
obligation to GE in the amount of $2.2 million that may become payable in the
fourth quarter of 2004. The agreement provides that this contingent obligation
is subject to a pro rata reduction under a formula based upon certain purchase
orders being entered into with GE by June 30, 2003. MCV Expansion, LLC
anticipates but cannot assure that purchase orders will be executed with GE
sufficient to eliminate contingent obligations of $2.2 million.
FORMER CMS OIL AND GAS OPERATIONS: A Michigan trial judge granted Star
Energy, Inc. and White Pine Enterprises, LLC a declaratory judgment in an action
filed in 1999 that claimed Terra Energy Ltd., a former CMS Oil and Gas
subsidiary, violated an oil and gas lease and other arrangements by failing to
drill wells it had committed to drill. A jury then awarded the plaintiffs a $7.6
million award. Terra appealed this matter to the Michigan Court of Appeals. The
Michigan Court of Appeals reversed the trial court judgment with respect to the
appropriate measure of damages and remanded the case for a new trial on damages.
The trial judge reinstated the judgment against Terra and awarded Terra title to
the minerals. CMS Energy will appeal this judgment.
F-88
ARGENTINA ECONOMIC SITUATION: In January 2002, the Republic of Argentina
enacted the Public Emergency and Foreign Exchange System Reform Act. This law
repealed the fixed exchange rate of one U.S. dollar to one Argentine peso,
converted all dollar-denominated utility tariffs and energy contract obligations
into pesos at the same one-to-one exchange rate, and directed the President of
Argentina to renegotiate such tariffs.
Effective April 30, 2002, we adopted the Argentine peso as the functional
currency for our Argentine investments. We had previously used the U.S. dollar
as the functional currency for these investments. As a result, on April 30,
2002, we translated the assets and liabilities of our Argentine entities into
U.S. dollars, in accordance with SFAS No. 52, using an exchange rate of 3.45
pesos per U.S. dollar, and recorded an initial charge to the Foreign Currency
Translation component of Common Stockholders' Equity of approximately $400
million.
While we cannot predict future peso-to-U.S. dollar exchange rates, we do
expect that these non-cash charges reduce substantially the risk of further
material balance sheet impacts when combined with anticipated proceeds from
international arbitration currently in progress, political risk insurance, and
the eventual sale of these assets. At December 31, 2003, the net foreign
currency loss due to the unfavorable exchange rate of the Argentine peso
recorded in the Foreign Currency Translation component of Common Stockholders'
Equity using an exchange rate of 2.94 pesos per U.S. dollar was $264 million.
This amount also reflects the effect of recording U.S. income taxes with respect
to temporary differences between the book and tax basis of foreign investments,
including the foreign currency translation associated with our Argentine
investments, that were determined to no longer be essentially permanent in
duration.
OTHER: Certain CMS Gas Transmission and CMS Generation affiliates in
Argentina received notice from various Argentine provinces claiming stamp taxes
and associated penalties and interest arising from various gas transportation
transactions. Although these claims total approximately $24 million, we believe
the claims are without merit and will continue to contest them vigorously.
CMS Generation does not currently expect to incur significant capital
costs at its power facilities for compliance with current U.S. environmental
regulatory standards.
In addition to the matters disclosed in this Note, Consumers and certain
other subsidiaries of CMS Energy are parties to certain lawsuits and
administrative proceedings before various courts and governmental agencies
arising from the ordinary course of business. These lawsuits and proceedings may
involve personal injury, property damage, contractual matters, environmental
issues, federal and state taxes, rates, licensing, and other matters.
We have accrued estimated losses for certain contingencies discussed in
this Note. Resolution of these contingencies is not expected to have a material
adverse impact on our financial position, liquidity, or results of operations.
F-89
5: FINANCINGS AND CAPITALIZATION
CMS Energy's Long-term debt as of December 31 follows:
INTEREST RATE (%) MATURITY 2003 2002
----------------- -------- ---- ----
IN MILLIONS
CMS ENERGY CORPORATION
Senior notes................................ 6.750 2004 $ -- $ 287
7.625 2004 176 176
9.875 2007 468 468
8.900 2008 260 260
7.500 2009 409 409
7.750 2010 300 --
8.500 2011 300 300
8.375 2013 -- 150
3.375(a) 2023 150 --
--------- ---------
2,063 2,050
--------- ---------
General term notes:
Series D.................................. 6.938(b)(c) 2004-2008 65 94
Series E.................................. 7.788(b)(c) 2004-2009 139 227
Series F.................................. 7.487(b)(c) 2004-2016 292 298
--------- ---------
496 619
--------- ---------
Extendible tenor rate adjusted securities... 7.000 2005 180 180
Revolving credit facilities and other....... 7 320
--------- ---------
Total -- CMS Energy Corporation........ 2,746 3,169
--------- ---------
CONSUMERS ENERGY COMPANY
First mortgage bonds........................ 4.250 2008 250 --
4.800 2009 200 --
4.000 2010 250 --
5.375 2013 375 --
6.000 2014 200 --
7.375 2023 208 208
--------- ---------
1,483 208
--------- ---------
Senior notes................................ 6.000 2005 300 300
6.250 2006 332 332
6.375 2008 159 159
6.200 2008 -- 250
6.875 2018 180 180
6.500(d) 2018 141 141
6.500(e) 2028 142 142
--------- ---------
1,254 1,504
--------- ---------
Securitization bonds........................ 5.097(c) 2005-2015 426 453
Long-term bank debt......................... Variable 2006-2009 200 328
Nuclear fuel disposal liability............. (f) 139 138
Pollution control revenue bonds............. Various 2010-2018 126 126
Other....................................... 4 8
--------- ---------
Total -- Consumers Energy Company...... 3,632 2,765
--------- ---------
OTHER SUBSIDIARIES 191 84
--------- ---------
Total principal amount outstanding............ 6,569 6,018
Current amounts............................. (509) (633)
Net unamortized discount.................... (40) (28)
--------- ---------
Total consolidated long-term debt............. $ 6,020 $ 5,357
========= =========
(a) These notes are putable to CMS Energy by the note holders at par on July
15, 2008, July 15, 2013 and July 15, 2018, and are convertible at the
holder's option into CMS Energy Common Stock at $10.671 per share under
certain circumstances, none of which currently are probable to occur. CMS
Energy intends to file a registration
F-90
statement with the SEC by October 16, 2004, relating to the resale of the
notes and the convertibility into common stock.
(b) $29 million Series D, $112 million Series E, and $104 million Series F
have been called and redeemed through February 15, 2004.
(c) Represents the weighted average interest rate at December 31, 2003.
(d) 2018 maturity is subject to successful remarketing by Consumers after June
15, 2005.
(e) Callable at par.
(f) Maturity date uncertain.
LONG-TERM DEBT-RELATED PARTIES:
Long-term debt-related parties as of December 31, 2003 follows:
DEBENTURE AND RELATED PARTY INTEREST RATE MATURITY 2003
------------------------------------------------------------------------- ----------------- ------------ ------
IN MILLIONS
Convertible subordinated debentures, CMS Energy Trust I.................. 7.75% 2027 $ 178
Subordinated deferrable interest notes, Consumers Power
Company Financing I.................................................... 8.36% 2015 73
Subordinated deferrable interest notes, Consumers Energy
Company Financing II................................................... 8.20% 2027 124
Subordinated debentures, Consumers Energy Company Financing III.......... 9.25% 2029 180
Subordinated debentures, Consumers Energy Company Financing IV........... 9.00% 2031 129
------
Total amount outstanding................................................. $ 684
======
DEBT ISSUANCES: The following is a summary of long-term debt issuances
during 2003:
PRINCIPAL USE OF
FACILITY TYPE (IN MILLIONS) ISSUE RATE ISSUE DATE MATURITY DATE PROCEEDS COLLATERAL
----------------------- ------------- ---------- ---------- ------------- -------- ----------
CMS ENERGY
Senior notes(a)....... $ 150 3.375% July 2003 July 2023 (c) Unsecured
Senior notes(b)....... 300 7.750% July 2003 August 2010 (c) Unsecured
CONSUMERS ENERGY
Term loan............. 140 LIBOR + March 2003 March 2009 GCP FMB(h)
475 bps
Term loan............. 150 LIBOR + March 2003 March 2006 GCP FMB(h)
450 bps (paid off)(f)
FMB(i)................ 375 5.375% April 2003 April 2013 (d) --
FMB(i)................ 250 4.250% April 2003 April 2008 (d) --
FMB(i)................ 250 4.000% May 2003 May 2010 (e) --
FMB(i)................ 200 4.800% August 2003 February 2009 (f) --
FMB(i)................ 200 6.000% August 2003 February 2014 (f) --
Term loan............. 60 LIBOR + November 2003 November 2006 (g) FMB(h)
135 bps
-------
Total.......... $ 2,075
=======
(bps -- basis points), (GCP -- General corporate purposes)
(a) These notes are putable to CMS Energy by the note holders at par on July
15, 2008, July 15, 2013 and July 15, 2018, and are convertible at the
holder's option into CMS Energy Common Stock at $10.671 per share under
certain circumstances, none of which currently are probable to occur. CMS
Energy intends to file a registration statement with the SEC by October
16, 2004, relating to the resale of the notes and the convertibility into
common stock.
F-91
(b) CMS Energy intends to file a registration statement with the SEC by March
14, 2004, to permit note holders to exchange their securities for ones
that will be registered under the Securities Act of 1933.
(c) CMS Energy used the net proceeds to retire revolving debt and redeem a
portion of a 6.75 percent Senior note due January 2004.
(d) Consumers used the net proceeds to fund the maturity of a $250 million
bond, to fund a $32 million option call payment, and for general corporate
purposes.
(e) Consumers used the net proceeds to prepay a portion of a term loan that
was due to mature in July 2004.
(f) Consumers used the net proceeds to pay off a $150 million term loan, to
pay off $50 million balance on a term loan that was due to mature in July
2004, and for general corporate purposes.
(g) Consumers used the net proceeds to purchase its headquarters building and
pay off the capital lease.
(h) Refer to "Regulatory Authorization for Financings" below for details about
Consumers' FERC debt authorization.
(i) Consumers filed a registration statement with the SEC in December 2003 to
permit holders of these FMBs to exchange their bonds for FMBs that are
registered under the Securities Act of 1933. The exchange offer was
completed on February 13, 2004.
DEBT MATURITIES: The aggregate annual maturities for long-term debt for
the next five years are:
PAYMENTS DUE DECEMBER 31
------------------------------------
2004 2005 2006 2007 2008
------- ------- ------- ------- ------
IN MILLIONS
Long-term debt...... $ 509 $ 696 $ 490 $ 516 $ 987
DEBT COVENANT RESTRICTIONS: The indenture pursuant to our GTNs contains
certain provisions that can trigger a limitation on our consolidated
indebtedness. The limitation can be activated when our consolidated leverage
ratio, as defined in the indenture (essentially the ratio of consolidated debt
to consolidated capital), exceeds 0.75 to 1.0. At June 30 and September 30,
2003, our consolidated leverage ratio was 0.76 to 1.0. As a result, we were
subject to certain debt limitations. At December 31, 2003, the ratio was 0.72 to
1, and we were no longer subject to the debt limitations.
The indenture under which Senior notes are issued and certain other debt
agreements contain provisions requiring us to maintain interest coverage ratios,
and debt to earnings ratios. We were in compliance with these ratios, as
defined, at December 31, 2003.
CMS ENERGY CREDIT FACILITY: CMS Energy has a $185 million revolving credit
facility with banks. This facility matures on May 21, 2005. This facility
provides letter of credit support for Enterprises' subsidiary activities,
principally credit support for project debt. Enterprises provides funds to cash
collateralize the letters of credit issued through this facility. As of December
31, 2003, approximately $165 million of letters of credit were issued under this
facility and the cash used to collateralize the letters of credit is included on
the Consolidated Balance Sheet as Restricted cash.
REGULATORY AUTHORIZATION FOR FINANCINGS: At December 31, 2003, Consumers
had remaining FERC authorization to issue or guarantee up to $500 million of
short-term securities and up to $700 million of short-term first mortgage bonds
as collateral for such short-term securities.
At December 31, 2003, Consumers had remaining FERC authorization to issue
up to $740 million of long-term securities for refinancing or refunding
purposes, $560 million of long-term securities for general corporate purposes,
and $2 billion of long-term first mortgage bonds to be issued solely as
collateral for other long-term securities.
F-92
With the granting of authorization, FERC waived its competitive
bid/negotiated placement requirements applicable to the long-term securities
authorization. The authorizations expire on June 30, 2004.
SHORT-TERM FINANCINGS: CMS Energy has a $190 million revolving credit
facility with banks. The facility is secured by our investment in Enterprises
and Consumers. The interest rate of the facility is LIBOR plus 325 basis points.
This facility expires in November 2004. At December 31, 2003, all of the $190
million is available.
Consumers has a $400 million revolving credit facility with banks. The
facility is secured with first mortgage bonds. The interest rate of the facility
is LIBOR plus 175 basis points. This facility expires in March 2004 with two
annual extensions at Consumers' option, which would extend the maturity to March
2006. At December 31, 2003, $10 million of letters of credit are issued and
outstanding under this facility and $390 million is available for general
corporate purposes, working capital, and letters of credit.
At December 31, 2002, Consumers had $457 million of bank notes outstanding
at a weighted average interest rate of 4.50 percent.
FIRST MORTGAGE BONDS: Consumers secures its first mortgage bonds by a
mortgage and lien on substantially all of its property. Its ability to issue and
sell securities is restricted by certain provisions in the first mortgage bond
indenture, its articles of incorporation, and the need for regulatory approvals
under federal law.
POLLUTION CONTROL REVENUE BONDS: In January 2004, Consumers amended the
PCRB indentures to add an auction rate interest mode and switched to that mode
for the two floating rate bonds. Under the auction rate mode, the bonds'
interest rate will be reset every 35 days. While in the auction rate mode, no
letter of credit liquidity facility is required and investors do not have a put
right.
PREFERRED STOCK ISSUANCE: In December 2003, CMS Energy issued 5 million
shares of 4.50 percent cumulative convertible preferred stock. Each share has a
liquidation value of $50.00 and is convertible into CMS Energy common stock at
the option of the holder under certain circumstances. The initial conversion
price is $9.893 per share, which translates into 5.0541 shares of common stock
for each share of preferred stock converted. The annual dividend of $2.25 per
share is payable quarterly, in cash, in arrears commencing March 1, 2004. We
used the net proceeds of $242 million to retire other long-term debt in January
2004 and February 2004. We have agreed to file a shelf registration with the SEC
by November 5, 2004, covering resales of the preferred stock and of common stock
issuable upon conversion of the preferred stock.
SALE OF SUBSIDIARY INTEREST: In December 2003, we sold, in a private
placement, a non-voting preferred interest in an indirect subsidiary of CMS
Enterprises that owns certain gas pipeline and power generation assets. CMS
Energy received $30 million for the preferred interest, of which $19 million has
been recorded as an addition to other paid-in capital (deferred gain) and $11
million has been recorded as a preferred stock issuance.
WARRANTS: We granted warrants to purchase 204,000 shares of our common
stock to a third party and expensed $1 million in 2003. The warrants which are
fully vested are exercisable for seven years at an exercise price of $8.25 per
share.
CAPITALIZATION: The authorized capital stock of CMS Energy consists of 250
million shares of CMS Energy Common Stock and 10 million shares of CMS Energy
Preferred Stock, $.01 par value.
PREFERRED STOCK OF SUBSIDIARY: The follow table describes Consumers'
Preferred Stock outstanding:
OPTIONAL NUMBER OF SHARES
REDEMPTION ----------------
DECEMBER 31 SERIES PRICE 2003 2002 2003 2002
------------------------------------ ------ ---------- ---- ---- ---- ----
IN MILLIONS
PREFERRED STOCK
Cumulative, $100 par value,
authorized 7,500,000 shares,
with no mandatory redemption...... $ 4.16 $ 103.25 68,451 68,451 $ 7 $ 7
4.50 110.00 373,148 373,148 37 37
---- ----
TOTAL PREFERRED STOCK................. $ 44 $ 44
==== ====
F-93
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARIES: CMS Energy and Consumers each formed various statutory wholly
owned business trusts for the sole purpose of issuing preferred securities and
lending the gross proceeds to the parent companies. The sole assets of the
trusts are debentures of the parent company with terms similar to those of the
preferred security. Summarized information for company-obligated mandatorily
redeemable preferred securities is as follows:
AMOUNT
OUTSTANDING EARLIEST
TRUST AND SECURITIES ----------------------- OPTIONAL
DECEMBER 31 RATE 2003 2002 MATURITY REDEMPTION(B)
------------------------------------------- ------ ----------- ----------- ------------ ---------------
IN MILLIONS
CMS Energy Trust I(c)......................... 7.75% $ -- (a) $ 173 2027 2001
CMS Energy Trust III.......................... 7.25% -- (d) 220 2004 2003
Consumers Power Company Financing I, Trust
Originated Preferred Securities............. 8.36% -- (a) 70 2015 2000
Consumers Energy Company Financing II, Trust
Originated Preferred Securities............. 8.20% -- (a) 120 2027 2002
Consumers Energy Company Financing III, Trust
Originated Preferred Securities............. 9.25% -- (a) 175 2029 2004
Consumers Energy Company Financing IV, Trust
Preferred Securities........................ 9.00% -- (a) 125 2031 2006
---- ------
Total amount outstanding...................... $ -- $ 883
==== ======
--------
(a) We determined that we do not hold the controlling financial interest in
our trust preferred security structures. Accordingly, those entities have
been deconsolidated as of December 31, 2003. Company obligated Trust
Preferred Securities totaling $663 million that were previously included
in mezzanine equity, have been eliminated due to deconsolidation and are
reflected in Long-term debt -- related parties. For additional details,
see "Long-Term Debt -- Related Parties" within this Note and Note 17,
Implementation of New Accounting Standards.
(b) The trusts must redeem the securities at a liquidation value of $25 per
share ($50 per share for QUIPS (c)), which is equivalent to the carrying
cost, plus accrued but unpaid distributions when the securities are paid
at maturity or upon any earlier redemption. Prior to an early redemption
date, the securities could be redeemed at market value.
(c) Represents 3,450,000 shares of Quarterly Income Preferred Securities
(QUIPS) that are convertible into 1.2255 shares of CMS Energy Common Stock
(equivalent to a conversion price of $40.80). Conversion is unlikely as of
December 31, 2003, based on the market price of CMS Energy's Common Stock
of $8.52. If conversion were to occur in the future, the securities would
be converted into 4,227,975 shares of CMS Energy Common Stock. Effective
July 2001, we can revoke the conversion rights if certain conditions are
met.
(d) In August 2003, 8,800,000 units of outstanding 7.25 percent Premium Equity
Participating Security Units (CMS Energy Trust III) were converted to
16,643,440 newly issued shares of CMS Energy Common Stock.
Each trust receives payments on the debenture it holds. Those receipts are
used to make cash distributions on the preferred securities the trust has
issued.
The securities allow CMS Energy and Consumers the right to defer interest
payment on the debentures, and, as a consequence, the trusts would defer
dividend payments on the preferred securities. Should the parent companies
exercise this right, they cannot declare or pay dividends on, or redeem,
purchase or acquire, any of their capital stock during the deferral period until
all deferred dividends are paid in full.
In the event of default, holders of the preferred securities would be
entitled to exercise and enforce the trusts' creditor rights against CMS Energy
and Consumers, which may include acceleration of the principal amount due on the
debentures. The parent companies have issued certain guarantees with respect to
payments on the preferred securities. These guarantees, when taken together with
each parent company's obligations under the debentures,
F-94
related indenture and trust documents, provide full and unconditional guarantees
for the trust's obligations under the preferred securities.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we currently sell certain accounts receivable to a wholly owned,
consolidated, bankruptcy remote special purpose entity. In turn, the special
purpose entity may sell an undivided interest in up to $325 million of the
receivables. The amounts sold were $297 million at December 31, 2003 and $325
million at December 31, 2002. The Consolidated Balance Sheets exclude these
amounts from accounts receivable. We continue to service the receivables sold.
The purchaser of the receivables has no recourse against our other assets for
failure of a debtor to pay when due and the purchaser has no right to any
receivables not sold. No gain or loss has been recorded on the receivables sold
and we retain no interest in the receivables sold.
Certain cash flows received from and paid to us under our accounts
receivable sales program are shown below:
YEARS ENDED
DECEMBER 31
--------------------
2003 2002
--------- ---------
IN MILLIONS
Proceeds from sales (remittance of collections) under the
program................................................... $ (28) $ (9)
Collections reinvested under the program.................... 4,361 4,080
DIVIDEND RESTRICTIONS: Under the provisions of its articles of
incorporation, at December 31, 2003, Consumers had $373 million of unrestricted
retained earnings available to pay common dividends. However, covenants in
Consumers' debt facilities cap common stock dividend payments at $300 million in
a calendar year. Through December 31, 2003, we received the following common
stock dividend payments from Consumers:
IN MILLIONS
January................................................ $ 78
May.................................................... 31
June................................................... 53
November............................................... 56
------
Total common stock dividends paid to CMS Energy........ $ 218
======
As of December 18, 2003, Consumers is also under an annual dividend cap of
$190 million imposed by the MPSC during the current interim gas rate relief
period. Because all of the $218 million of common stock dividends to CMS Energy
were paid prior to December 18, 2003, Consumers was not out of compliance with
this new restriction for 2003. In February 2004, Consumers paid a $78 million
common stock dividend.
For additional details on the potential cap on common dividends payable
included in the MPSC Securitization order, see Note 4, Uncertainties,
"Consumers' Electric Utility Rate Matters -- Securitization." Also, for
additional details on the cap on common dividends payable during the current
interim gas rate relief period, see Note 4, Uncertainties, "Consumers' Gas
Utility Rate Matters -- 2003 Gas Rate Case."
FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE
REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF
OTHERS: This interpretation became effective January 2003. It describes the
disclosure to be made by a guarantor about its obligations under certain
guarantees that it has issued. At the beginning of a guarantee, it requires a
guarantor to recognize a liability for the fair value of the obligation
undertaken in issuing the guarantee. The initial recognition and measurement
provision of this interpretation does not apply to some guarantee contracts,
such as warranties, derivatives, or guarantees between either parent and
subsidiaries or corporations under common control, although disclosure of these
guarantees is required. For contracts that are within the recognition and
measurement provision of this interpretation, the provisions were to be applied
to guarantees issued or modified after December 31, 2002.
F-95
The following table describe our guarantees at December 31, 2003:
ISSUE EXPIRATION MAXIMUM CARRYING RECOURSE
GUARANTEE DESCRIPTION DATE DATE OBLIGATION AMOUNT(b) PROVISION(c)
-------------------------------------------- ------- ---------- ---------- --------- ------------
IN MILLIONS
Indemnifications from asset sales and other
agreements(a)............................. Various Various $ 1,955 $ 3 $ --
Letters of credit........................... Various Various 254 -- --
Surety bonds and other indemnifications..... Various Various 28 -- --
Other guarantees............................ Various Various 239 -- --
Nuclear insurance retrospective premiums.... Various Various 133 -- --
------------
(a) The majority of this amount arises from routine provisions in stock and
asset sales agreements under which we indemnify the purchaser for losses
resulting from events such as failure of title to the assets or stock sold
by us to the purchaser. Included in this amount is a $739 million
indemnification obligation related to the sale of CMS Oil and Gas
facilities in Equatorial Guinea which expired January 3, 2004, and for
which no loss occurred. We believe the likelihood of a loss for any
remaining indemnifications to be remote.
(b) The carrying amount represents the fair market value of guarantees and
indemnities on our balance sheet that are entered into subsequent to
January 1, 2003. In addition, $25 million has been recorded prior to 2003
in accordance with SFAS No. 5.
(c) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.
The following table provides additional information regarding our
guarantees at December 31, 2003:
EVENTS THAT WOULD
GUARANTEE DESCRIPTION HOW GUARANTEE AROSE REQUIRE PERFORMANCE
------------------------------- ------------------------------- ------------------------------
Indemnifications from asset Stock and asset sales Findings of misrepresentation,
sales and other agreements agreements breach of warranties, and
other specific events or
circumstances
Standby letters of credit Normal operations of coal Noncompliance with
power plants environmental regulations
Self-insurance requirement Nonperformance
Surety bonds Normal operating activity, Nonperformance
permits and license
Other guarantees Normal operating activity Nonperformance or non-
payment by a subsidiary
under the related contract
Nuclear insurance Normal operations of nuclear Call by NEIL and Price
retrospective premiums plants Anderson Act for nuclear
incident
We have entered into typical tax indemnity agreements in connection with a
variety of transactions including transactions for the sale of subsidiaries and
assets, equipment leasing, and financing agreements. These indemnity agreements
generally are not limited in amount and, while a maximum amount of exposure
cannot be identified, the amount and probability of liability is considered
remote.
F-96
We have guaranteed payment of obligations through letters of credit,
indemnities, surety bonds, and other guarantees of unconsolidated affiliates and
related parties of $521 million as of December 31, 2003. We monitor and approve
these obligations and believe it is unlikely that we would be required to
perform or otherwise incur any material losses associated with the above
obligations. The off-balance sheet commitments expire as follows:
COMMITMENT EXPIRATION
---------------------------------------------------------
DECEMBER 31 TOTAL 2004 2005 2006 2007 2008 BEYOND
------------------------------- -------- ------ ------ ------ ------ ------ --------
IN MILLIONS
COMMERCIAL COMMITMENTS
Off-balance sheet:
Guarantees........................... $ 239 $ 20 $ 36 $ 4 $ -- $ -- $ 179
Indemnities.......................... 28 8 -- -- -- -- 20
Letters of Credit(a)................. 254 215 10 5 5 5 14
------ ------ ----- ---- ---- ---- ------
Total........................... $ 521 $ 243 $ 46 $ 9 $ 5 $ 5 $ 213
====== ====== ===== ==== ==== ==== ======
(a) At December 31, 2003, we had $175 million of cash collateralized letters
of credit and the cash used to collateralize the letters of credit is
included in Restricted cash on the Consolidated Balance Sheets.
6: EARNINGS PER SHARE AND DIVIDENDS
The following table presents the basic and diluted earnings per share
computations.
YEARS ENDED DECEMBER 31
` ------------------------------------
RESTATED RESTATED
2003 2002 2001
-------- -------- --------
IN MILLIONS,
EXCEPT PER SHARE AMOUNTS
LOSS ATTRIBUTABLE TO COMMON STOCK:
Loss from Continuing Operations - Basic........................ $ (43) $ (394) $ (327)
Add conversion of Trust Preferred
Securities (net of tax)................................ -- (a) -- (a) -- (a)
-------- -------- --------
Loss from Continuing Operations - Diluted...................... $ (43) $ (394) $ (327)
======== ======== ========
AVERAGE COMMON SHARES OUTSTANDING APPLICABLE TO
BASIC AND DILUTED EPS
CMS Energy:
Average Shares - Basic....................................... 150.4 139.0 130.7
Add conversion of Trust Preferred Securities................. -- (a) -- (a) -- (a)
Stock Options and Warrants................................... -- (b) -- -- (b)
-------- -------- --------
Average Shares - Diluted..................................... 150.4 139.0 130.7
======== ======== ========
LOSS PER AVERAGE COMMON SHARE
Basic $ (0.30) $ (2.84) $ (2.50)
Diluted $ (0.30) $ (2.84) $ (2.50)
(a) Due to antidilution, the computation of diluted earnings per share
excluded the conversion of Trust Preferred Securities.
(b) Due to antidilution, the computation of diluted earnings per share
excluded shares of outstanding stock options and warrants of 0.3 million
for the year ended 2003 and 0.2 million for the year ended 2001.
F-97
In January 2003, the Board of Directors suspended the payment of common
stock dividends. However, in 2002, we paid the following dividends per share:
CMS ENERGY COMMON STOCK
DIVIDENDS PER SHARE PAYOUT
--------------------------
February.... $ 0.365
April....... $ 0.365
August...... $ 0.180
November.... $ 0.180
7: FINANCIAL AND DERIVATIVE INSTRUMENTS
FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term
investments, and current liabilities approximate their fair values because of
their short-term nature. We estimate the fair values of long-term investments
based on quoted market prices or, in the absence of specific market prices, on
quoted market prices of similar investments or other valuation techniques. The
carrying amount of all long-term financial instruments, except as shown below,
approximate fair value. For additional details, see Note 1, Corporate Structure
and Accounting Policies.
DECEMBER 31
--------------------------------------------------------------------
2003 2002
------------------------------- ---------------------------------
FAIR UNREALIZED FAIR UNREALIZED
COST VALUE GAIN (LOSS) COST VALUE GAIN
-------- ------- ----------- -------- -------- ----------
IN MILLIONS
Long-term debt(a)........................ $ 6,020 $ 6,225 $ (205) $ 5,357 $ 5,027 $ 330
Long-term debt-related parties(b)........ 684 648 36 -- -- --
Trust Preferred Securities(b)............ -- -- -- 883 704 179
Available for sale securities:
Nuclear decommissioning(c)............... 442 575 133 458 536 78
SERP..................................... 54 66 12 54 57 3
(a) Settlement of long-term debt is generally not expected until maturity.
(b) We determined that we do not hold the controlling financial interest in
our trust preferred security structures. Accordingly, those entities have
been deconsolidated as of December 31, 2003. Company obligated Trust
Preferred Securities totaling $663 million that were previously included
in mezzanine equity, have been eliminated due to deconsolidation and are
reflected in Long-term debt -- related parties on the Consolidated Balance
Sheets. For additional details, refer to Note 5, Financings and
Capitalization, "Long-Term Debt -- Related Parties" and Note 17,
Implementation of New Accounting Standards. In addition, company obligated
Trust Preferred Securities totaling $220 million have been converted to
Common Stock as of August 2003.
(c) On January 1, 2003, we adopted SFAS No. 143 and began classifying our
unrealized gains and losses on nuclear decommissioning investments as
regulatory liabilities. We previously classified the unrealized gains and
losses on these investments in accumulated depreciation.
DERIVATIVE INSTRUMENTS: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, currency exchange
rates, and equity security prices. We manage these risks using established
policies and procedures, under the direction of both an executive oversight
committee consisting of senior management representatives and a risk committee
consisting of business-unit managers. We may use various contracts to manage
these risks including swaps, options, and forward contracts.
We intend that any gains or losses on these contracts will be offset by an
opposite movement in the value of the item at risk. We enter into all risk
management contracts for purposes other than trading. These contracts contain
credit risk if the counterparties, including financial institutions and energy
marketers, fail to perform under the agreements. We minimize such risk by
performing financial credit reviews using, among other things, publicly
available credit ratings of such counterparties.
F-98
Contracts used to manage interest rate, foreign currency, and commodity
price risk may be considered derivative instruments that are subject to
derivative and hedge accounting pursuant to SFAS No. 133. If a contract is
accounted for as a derivative instrument, it is recorded in the financial
statements as an asset or a liability, at the fair value of the contract. The
recorded fair value of the contract is then adjusted quarterly to reflect any
change in the market value of the contract, a practice known as marking the
contract to market. The accounting for changes in the fair value of a derivative
(that is, gains or losses) is reported either in earnings or accumulated other
comprehensive income depending on whether the derivative qualifies for special
hedge accounting treatment.
For derivative instruments to qualify for hedge accounting under SFAS No.
133, the hedging relationship must be formally documented at inception and be
highly effective in achieving offsetting cash flows or offsetting changes in
fair value attributable to the risk being hedged. If hedging a forecasted
transaction, the forecasted transaction must be probable. If a derivative
instrument, used as a cash flow hedge, is terminated early because it is
probable that a forecasted transaction will not occur, any gain or loss as of
such date is immediately recognized in earnings. If a derivative instrument,
used as a cash flow hedge, is terminated early for other economic reasons, any
gain or loss as of the termination date is deferred and recorded when the
forecasted transaction affects earnings. We use a combination of quoted market
prices and mathematical valuation models to determine fair value of those
contracts requiring derivative accounting. The ineffective portion, if any, of
all hedges is recognized in earnings.
The majority of our contracts are not subject to derivative accounting
because they qualify for the normal purchases and sales exception of SFAS No.
133 or are not derivatives because there is not an active market for the
commodity. Derivative accounting is required for certain contracts used to limit
our exposure to electricity and gas commodity price risk and interest rate risk.
The following table reflects the fair value of all contracts requiring
derivative accounting:
DECEMBER 31
---------------------------------------------------------------
2003 2002
-------------------------------- ------------------------------
FAIR UNREALIZED FAIR UNREALIZED
DERIVATIVE INSTRUMENTS COST VALUE GAIN (LOSS) COST VALUE GAIN (LOSS)
--------------------------------------------- ------ -------- -------------- ------ -------- -------------
IN MILLIONS
Other than trading
Electric-related contracts................. $ -- $ -- $ -- $ 8 $ 1 $ (7)
Gas contracts.............................. 3 2 (1) -- 1 1
Interest rate risk contracts............... -- (3) (3) -- (28) (28)
Derivative contracts associated with equity
investments in:
Shuweihat.................................. -- (27) (27) -- (30) (30)
Taweelah................................... -- (26) (26) -- (33) (33)
MCV Partnership............................ -- 15 15 -- 13 13
Jorf Lasfar................................ -- (11) (11) -- (11) (11)
Other...................................... -- 1 1 -- (2) (2)
Trading
Electric-related contracts................. (2) -- 2 -- 43 43
Gas contracts.............................. -- 15 15 -- 38 38
The fair value of other than trading derivative contracts is included in
either Other Assets or Other Liabilities on the Consolidated Balance Sheets. The
fair value of trading derivative contracts is included in either Price Risk
Management Assets or Price Risk Management Liabilities on the Consolidated
Balance Sheets. The fair value of derivative contracts associated with our
equity investment in the MCV Partnership is included in Investments -- Midland
Cogeneration Venture Limited Partnership on the Consolidated Balance Sheets.
Effective April 1, 2002, the MCV Partnership changed its accounting for
derivatives. For additional details see Note 15, Summarized Financial
Information of Significant Related Energy Supplier. The fair value of derivative
contracts associated with other equity investments is included in Enterprises
Investments on the Consolidated Balance Sheets.
Cumulative Effect of Change in Accounting Principle: On January 1, 2001,
upon initial adoption of the derivatives standard, we recorded a $10 million,
net of tax, cumulative effect adjustment as an increase in accumulated other
comprehensive income. This adjustment relates to the difference between the fair
value and
F-99
recorded book value of contracts related to gas call options, gas fuel for
generation swap contracts, and interest rate swap contracts that qualified for
hedge accounting prior to the initial adoption of SFAS No. 133 and our
proportionate share of the effects of adopting SFAS No. 133 related to our
equity investments in the MCV Partnership and Taweelah. Based on the initial
transition adjustment of $21 million, net of tax, recorded in accumulated other
comprehensive income at January 1, 2001, Consumers reclassified to earnings $12
million as a reduction to the cost of gas, $1 million as a reduction to the cost
of power supply, $2 million as an increase in interest expense, and $8 million
as an increase in other revenues for the twelve months ended December 31, 2001.
CMS Energy recorded $12 million as an increase in interest expense during 2001,
which includes the $2 million of additional interest expense at Consumers. The
difference between the initial transition adjustment and the amounts
reclassified to earnings represents an unrealized loss in the fair value of the
derivative instruments since January 1, 2001, resulting in a decrease of
accumulated other comprehensive income. We also recorded a $7 million, net of
tax, cumulative effect adjustment as an increase to earnings. This adjustment
relates to our proportionate share of the difference between the fair value and
the recorded book value of interest rate swaps at Taweelah, and financial gas
and supply contracts that were required to be accounted for as derivatives as of
January 1, 2001.
In June and December 2001, the FASB issued guidance that resolved the
accounting for certain utility industry contracts. As a result, we recorded a $3
million, net of tax, cumulative effect adjustment as an unrealized loss,
decreasing accumulated other comprehensive income, and on December 31, 2001,
recorded an $11 million, net of tax, cumulative effect adjustment as a decrease
to earnings. These adjustments relate to the difference between the fair value
and the recorded book value of certain electric call option contracts.
Effective, January 1, 2003, EITF Issue No. 98-10 was rescinded by EITF
Issue No. 02-03 and as a result, only energy contracts that meet the definition
of a derivative in SFAS No. 133 can be carried at fair value. The impact of this
change was recognized as a cumulative effect of a change in accounting principle
loss of $23 million, net of tax. For additional details regarding this loss see
Note 17, Implementation of New Accounting Standards.
ELECTRIC CONTRACTS: Our electric utility business uses purchased electric
call option contracts to meet, in part, our regulatory obligation to serve. This
obligation requires us to provide a physical supply of electricity to customers,
to manage electric costs and to ensure a reliable source of capacity during peak
demand periods.
Certain of our electric capacity and energy contracts are not accounted
for as derivatives due to the lack of an active energy market in the state of
Michigan, as defined by SFAS No. 133, and the transportation costs that would be
incurred to deliver the power under the contracts to the closest active energy
market at the Cinergy hub in Ohio. If a market develops in the future, we may be
required to account for these contracts as derivatives. The mark-to-market
impact on earnings related to these contracts, particularly related to the PPA,
could be material to the financial statements.
Our electric business also uses gas option and swap contracts to protect
against price risk due to the fluctuations in the market price of gas used as
fuel for generation of electricity. These contracts are financial contracts that
are used to offset increases in the price of potential gas purchases. These
contracts do not qualify for hedge accounting. Therefore, we record any change
in the fair value of these contracts directly in earnings as part of power
supply costs.
For the year ended December 31, 2003, the unrealized gain in accumulated
other comprehensive income related to our proportionate share of the effects of
derivative accounting related to our equity investment in the MCV Partnership is
$10 million, net of tax. We expect to reclassify this gain, if this value
remains, as an increase to earnings from equity method investees during the next
12 months.
GAS CONTRACTS: Our gas utility business uses fixed price gas supply
contracts, fixed price weather-based gas supply call options, fixed price gas
supply call and put options, and other types of contracts, to meet our
regulatory obligation to provide gas to our customers at a reasonable and
prudent cost. Unrealized gains and losses associated with these options are
reported directly in earnings as part of other income, and then directly offset
in earnings and recorded on the balance sheet as a regulatory asset or
liability.
ENERGY TRADING ACTIVITIES: Through December 31, 2002, CMS MST's wholesale
power and gas trading activities were accounted for under the mark-to-market
method of accounting. Under mark-to-market accounting,
F-100
energy-trading contracts are reflected at fair market value, net of reserves,
with unrealized gains and losses recorded as an asset or liability in the
Consolidated Balance Sheets. These assets and liabilities are affected by the
timing of settlements related to these contracts, current-period changes from
newly originated transactions and the impact of price movements. Changes in fair
value are recognized as revenues in the Consolidated Statements of Income in the
period in which the changes occur. The market prices we use to value our energy
trading contracts reflect our consideration of, among other things, closing
exchange and over-the-counter quotations. In certain contracts, long-term
commitments may extend beyond the period in which market quotations for such
contracts are available. Mathematical models are developed to determine various
inputs into the fair value calculation including price and other variables that
may be required to calculate fair value. Realized cash returns on these
commitments may vary, either positively or negatively, from the results
estimated through application of the mathematical model. We believe that our
mathematical models use state-of-the-art technology, pertinent industry data,
and prudent discounting in order to forecast certain elongated pricing curves.
Market prices are adjusted to reflect the impact of liquidating our position in
an orderly manner over a reasonable period of time under present market
conditions.
In connection with the market valuation of our energy trading contracts,
we maintain reserves for credit risks based on the financial condition of
counterparties. We also maintain credit policies that management believes
minimize overall credit risk with regard to our counterparties. Determination of
our counterparties' credit quality is based upon a number of factors, including
credit ratings, disclosed financial condition, and collateral requirements.
Where contractual terms permit, we employ standard agreements that allow for
netting of positive and negative exposures associated with a single
counterparty. Based on these policies, our current exposures, and our credit
reserves, we do not anticipate a material adverse effect on our financial
position or results of operations as a result of counterparty nonperformance.
INTEREST RATE RISK CONTRACTS: We use interest rate swaps to hedge the risk
associated with forecasted interest payments on variable-rate debt. Most of our
interest rate swaps are designated as cash flow hedges. As such, we record any
change in the fair value of these contracts in accumulated other comprehensive
income unless the swaps are sold. For interest rate swaps that did not qualify
for hedge accounting treatment, we record any change in the fair value of these
contracts in earnings.
As of December 31, 2003, we have recorded an unrealized loss of $1
million, net of tax, in accumulated other comprehensive income related to
interest rate risk contracts accounted for as cash flow hedges. We expect to
reclassify $1 million of this amount as a decrease to earnings during the next
12 months primarily to offset the variable-rate interest expense on hedged debt.
We have entered into floating-to-fixed interest rate swap agreements to
reduce the impact of interest rate fluctuations. The difference between the
amounts paid and received under the swaps is accrued and recorded as an
adjustment to interest expense over the term of the agreement. We were able to
apply the shortcut method to all interest rate swaps that qualified for hedge
accounting treatment; therefore, there was no ineffectiveness associated with
these hedges.
The following table reflects the outstanding floating-to-fixed interest
rates swaps at year end:
FLOATING TO FIXED NOTIONAL MATURITY FAIR
INTEREST RATE SWAPS AMOUNT DATE VALUE
--------------------------- -------- -------- -----
IN MILLIONS
December 31, 2003.......... $ 28 2005-2006 $ (3)
December 31, 2002.......... 493 2003-2007 (28)
Notional amounts reflect the volume of transactions but do not represent
the amount exchanged by the parties to the financial instruments. Accordingly,
notional amounts do not necessarily reflect our exposure to credit or market
risks. The weighted average interest rate associated with outstanding swaps was
approximately 7.4 percent at December 31, 2003 and 4.0 percent at December 31,
2002.
Certain equity method investees have issued interest rate swaps and
similar instruments to hedge the risk associated with variable-rate debt. These
instruments are not included in this analysis, but can have an impact on
financial results. The accounting for these instruments depends on whether they
qualify for cash flow hedge
F-101
accounting treatment. The interest rate derivatives held by Taweelah and certain
interest rate swaps held by Shuweihat do not qualify as cash flow hedges, and
therefore, we record our proportionate share of the change in the fair value of
these contracts in Earnings from Equity Method Investees. The remainder of these
instruments do qualify as cash flow hedges, and we record our proportionate
share of the change in the fair value of these contracts in accumulated other
comprehensive income. See discussion of these instruments in Note 18,
Restatement and Reclassification.
FOREIGN EXCHANGE DERIVATIVES: We may use forward exchange and option
contracts to hedge certain receivables, payables, long-term debt, and equity
value relating to foreign investments. The purpose of our foreign currency
hedging activities is to protect the company from the risk associated with
adverse changes in currency exchange rates that could affect cash flow
materially. These contracts would not subject us to risk from exchange rate
movements because gains and losses on such contracts offset losses and gains,
respectively, on assets and liabilities being hedged.
There were no outstanding foreign exchange contracts at December 31, 2003.
The notional amount of the outstanding foreign exchange contracts at December
31, 2002 was $1 million Canadian. The estimated fair value of the foreign
exchange and option contracts at December 31, 2002 was zero.
As of December 31, 2003, Taweelah, one of our equity method investees,
held a foreign exchange contract that hedged the foreign currency risk
associated with payments to be made under an operating and maintenance service
agreement. This contract did not qualify as a cash flow hedge, and therefore, we
record our proportionate share of the change in the fair value of the contract
in Earnings from Equity Method Investees.
8: INCOME TAXES
CMS Energy and its subsidiaries file a consolidated federal income tax
return. Income taxes generally are allocated based on each company's separate
taxable income. We practice deferred tax accounting for temporary differences in
accordance with SFAS No. 109, Accounting for Income Taxes.
U.S. income taxes are not recorded on the undistributed earnings of
foreign subsidiaries that have been or are intended to be reinvested
indefinitely. Upon distribution, those earnings may be subject to both U.S.
income taxes (adjusted for foreign tax credits or deductions) and withholding
taxes payable to various foreign countries. We annually determine the amount of
undistributed foreign earnings that we expect will remain invested indefinitely
in foreign subsidiaries. Cumulative undistributed earnings of foreign
subsidiaries for which income taxes have not been provided totaled approximately
$106 million at December 31, 2003. It is impractical to estimate the amount of
unrecognized deferred income taxes or withholding taxes on these undistributed
earnings. Also, at December 31, 2003 and 2002, we recorded U.S. income taxes
with respect to temporary differences between the book and tax bases of foreign
investments that were determined to be no longer essentially permanent in
duration.
The Job Creation and Worker Assistance Act of 2002 provided corporate
taxpayers a 5-year carryback of tax losses incurred in 2001 and 2002. As a
result of this legislation, we carried back consolidated 2001 and 2002 tax
losses to tax years 1996 through 1999 to obtain refunds totaling $250 million.
The tax loss carryback, however, resulted in a reduction in AMT credit
carryforwards that previously had been recorded as deferred tax assets in the
amount of $47 million. This non-cash reduction in AMT credit carryforwards was
reflected in our tax provision in 2002.
We use ITC to reduce current income taxes payable, and amortize ITC over
the life of the related property. AMT paid generally becomes a tax credit that
we can carry forward indefinitely to reduce regular tax liabilities in future
periods when regular taxes paid exceed the tax calculated for AMT. At December
31, 2003, we had AMT credit carryforwards in the amount of $214 million that do
not expire, tax loss carryforwards in the amount of $1.151 billion that expire
from 2021 through 2023. In addition, we had capital loss carryforwards in the
amount of $29 million that expire in 2007, and general business credit
carryforwards in the amount of $42 million that primarily expire in 2005, for
which valuation allowances have been provided.
During the fourth quarter of 2000, we wrote down the value of our
investment in Loy Yang by $329 million ($268 million after-tax). We have now
concluded the tax benefit associated with the write-down should have been
F-102
reduced by $38 million. Accordingly, retained earnings as of January 1, 2001
have been reduced by this amount. For additional details, see Note 18,
Restatement and Reclassification.
The significant components of income tax expense (benefit) on continuing
operations consisted of:
YEARS ENDED DECEMBER 31
------------------------------------
RESTATED RESTATED
2003 2002 2001
------ ------- --------
IN MILLIONS
Current income taxes:
Federal.................... $ (17) $ (171) $ (209)
State and local............ 1 (8) 6
Foreign.................... 17 28 8
------ ------- --------
$ 1 $ (151) $ (195)
Deferred income taxes
Federal.................... $ 54 $ 107 $ 97
State...................... 4 7 3
Foreign.................... 5 2 8
------ ------- --------
$ 63 $ 116 $ 108
Deferred ITC, net............ (6) (6) (7)
------ ------- --------
Tax expense (benefit)........ $ 58 $ (41) $ (94)
====== ======= ========
The principal components of deferred tax assets (liabilities) recognized
in the consolidated balance sheet are as follows:
DECEMBER 31
------------------------
RESTATED
2003 2002
---------- ----------
IN MILLIONS
Property.......................................... $ (842) $ (814)
Securitization costs.............................. (186) (192)
Prepaid pension................................... (136) --
Unconsolidated investments........................ (254) 55
Postretirement benefits........................... (70) (72)
Gas inventories................................... (100) (74)
Employee benefit obligations...................... 130 265
Tax credit carryforwards.......................... 255 247
Tax loss carryforwards............................ 413 190
Valuation allowances.............................. (54) (4)
Regulatory liabilities............................ 120 115
Other, net........................................ 82 (169)
---------- ----------
Net deferred tax liabilities.................... $ (642) $ (453)
========== ==========
Deferred tax liabilities.......................... $ (1,581) $ (1,339)
Deferred tax assets, net of valuation reserves.... 939 886
---------- ----------
Net deferred tax liabilities.................... $ (642) $ (453)
========== ==========
F-103
The actual income tax expense (benefit) on continuing operations differs
from the amount computed by applying the statutory federal tax rate of 35
percent to income before income taxes as follows:
YEARS ENDED DECEMBER 31
---------------------------------
RESTATED RESTATED
2003 2002 2001
------- ------- -------
IN MILLIONS
Income (loss) from continuing operations before income taxes
and minority interests
Domestic........................................................ $ (73) $ (527) $ (320)
Foreign......................................................... 88 94 (108)
------- ------- -------
Total...................................................... 15 (433) (428)
Statutory federal income tax rate................................. x 35% x 35% x 35%
------- ------- -------
Expected income tax expense (benefit)............................. 5 (152) (150)
Increase (decrease) in taxes from:
Property differences............................................ 18 18 23
Income tax effect of foreign investments........................ (18) 47 52
Tax credits..................................................... (6) 51 (8)
State and local income taxes, net of federal benefit............ -- (7) 3
Tax return accrual adjustments.................................. (1) (7) (4)
Minority interests.............................................. -- (5) (9)
Valuation allowance provision (reversal)........................ 50 -- (1)
Other, net...................................................... 10 14 --
------- ------- -------
Recorded income tax expense (benefit)(a).......................... $ 58 $ (41) $ (94)
------- ------- -------
Effective tax rate(b)............................................. (b) 9.5% 22.0%
======= ======= =======
(a) The increased income tax expense for 2003 is primarily attributable to the
valuation reserve provisions for the possible loss of general business
credit, capital loss, and charitable contributions carryforwards.
(b) Because of the small size of the net income in 2003, the effective tax
rate is not meaningful. Changes in the effective tax rate in 2002 from
2001 resulted principally from the reduction in AMT credit carryforwards
and the recording of U.S. taxes on undistributed earnings and basis
differences of foreign subsidiaries.
9: EXECUTIVE INCENTIVE COMPENSATION
We provide a Performance Incentive Stock Plan to key management employees
based on their contributions to the successful management of the Company. The
Plan includes the following type of awards for common stock:
- restricted shares of common stock,
- stock options, and
- stock appreciation rights.
Restricted shares of common stock are outstanding shares with full voting
and dividend rights. These awards vest over five years at the rate of 25 percent
per year after two years. Some restricted shares are subject to achievement of
specified levels of total shareholder return and are subject to forfeiture if
employment terminates before vesting. Restricted shares vest fully if control of
CMS Energy changes, as defined by the plan.
Stock options give the holder the right to purchase common stock at a
given price over an extended period of time. Stock appreciation rights give the
holder the right to receive common stock appreciation, which is defined as the
excess of the market price of the stock at the date of exercise over the grant
date price. Our stock options and stock appreciation rights are valued at market
price when granted. All options and rights may be exercised upon grant and they
expire up to ten years and one month from the date of grant.
F-104
Our Performance Incentive Stock Plan was amended in January 1999. It uses
the following formula to grant awards:
- Up to five percent of our common stock outstanding at January 1 each
year less:
- the number of shares of restricted common stock awarded, and
- common stock subject to options granted under the plan during
the immediately preceding four calendar years.
- the number of shares of restricted common stock awarded under this
plan cannot exceed 20 percent of the aggregate number of shares
reserved for awards, and
- forfeiture of shares previously awarded will increase the number of
shares available to be awarded under the plan.
Awards of up to 2,240,247 shares of CMS Energy Common Stock may be issued
as of December 31, 2003.
The following table summarizes the restricted stock and stock options
granted to our key employees under the Performance Incentive Stock Plan:
RESTRICTED
STOCK OPTIONS
---------- ---------------------------------
NUMBER OF NUMBER OF WEIGHTED AVERAGE
SHARES SHARES EXERCISE PRICE
---------- ---------- ----------------
CMS ENERGY COMMON STOCK
Outstanding at January 1, 2001........... 786,427 3,058,186 $ 31.47
Granted................................ 266,500 1,036,000 $ 30.21
Exercised or Issued.................... (82,765) (150,174) $ 19.11
Forfeited or Expired................... (182,177) (31,832) $ 35.10
---------- ---------- --------
Outstanding at December 31, 2001......... 787,985 3,912,180 $ 31.58
Granted................................ 512,726 1,492,200 $ 15.64
Exercised or Issued.................... (116,562) (39,600) $ 17.07
Forfeited or Expired................... (225,823) (243,160) $ 28.91
---------- ---------- --------
Outstanding at December 31, 2002......... 958,326 5,121,620 $ 27.18
Granted................................ 600,000 1,593,000 $ 6.35
Exercised or Issued.................... (80,425) (8,000) $ 8.12
Forfeited or Expired................... (213,873) (885,044) $ 28.66
---------- ---------- --------
Outstanding at December 31, 2003......... 1,264,028 5,821,576 $ 21.27
========== ========== ========
At December 31, 2003, 186,522 of the 1,264,028 shares of restricted common
stock outstanding are subject to performance objectives. Compensation expense
included in income for restricted stock was $2 million for 2003, less than $1
million in 2002, and $1 million in 2001.
The following table summarizes our stock options outstanding at December
31, 2003:
NUMBER OF
SHARES WEIGHTED AVERAGE WEIGHTED AVERAGE
OUTSTANDING REMAINING LIFE EXERCISE PRICE
----------- -------------- --------------
RANGE OF EXERCISE PRICES
CMS ENERGY COMMON STOCK:
$6.35 -- $8.12......................... 2,144,500 9.45 years $ 6.81
$17.00 -- $22.20....................... 1,268,450 6.83 years $ 20.13
$22.69 -- $31.04....................... 1,150,122 5.78 years $ 29.74
$34.80 -- $44.06....................... 1,258,504 4.92 years $ 39.32
--------- ---------- --------
$6.35 -- $44.06........................ 5,821,576 7.17 years $ 21.27
The number of stock options exercisable was 5,795,145 at December 31,
2003, 5,007,329 at December 31, 2002 and 3,760,883 at December 31, 2001.
In December 2002, we adopted the fair value based method of accounting for
stock-based employee compensation, under SFAS No. 123, as amended by SFAS No.
148. We elected to adopt the prospective method
F-105
recognition provisions of this Statement, which applies the recognition
provisions to all awards granted, modified, or settled after the beginning of
the fiscal year that the recognition provisions are first applied.
The following table summarizes the weighted average fair value of stock
options granted:
OPTIONS GRANT DATE 2003 2002(A) 2001
-------------------------- ------- ------------- ------
Fair value at grant date..... $ 2.96 $3.84, $1.44 $ 6.43
(a) For 2002, there were two stock option grants.
The stock options fair value is estimated using the Black-Scholes model, a
mathematical formula used to value options traded on securities exchanges. The
following assumptions were used in the Black-Scholes model:
YEARS ENDED DECEMBER 31 2003 2002(A) 2001
--------------------------------------------------- -------- ----------------------- -----------
CMS ENERGY COMMON STOCK OPTIONS
Risk-free interest rate........................... 3.02% 3.95%, 3.16% 4.77%
Expected stock price volatility................... 55.46% 32.44%, 40.81% 30.59%
Expected dividend rate............................ -- $ 0.365, $ 0.1825 $ 0.365
Expected option life (years)...................... 4.2 4.2 4.2 4.2
(a) For 2002, there were two stock option grants.
We recorded $5 million as stock-based employee compensation cost for 2003
and $4 million for 2002. All stock options vest at date of grant. If stock-based
compensation costs had been determined under SFAS No. 123 for the year ended
December 31, 2001, consolidated net loss and pro forma net loss would have been
as follows:
YEARS ENDED DECEMBER 31
--------------------------------
RESTATED 2001
--------------------------------
NET LOSS BASIC DILUTED
-------- -------- -------
IN MILLIONS,
EXCEPT PER SHARE AMOUNTS
Net loss, as reported................................................. $ (459) $ (3.51) $ (3.51)
Add: Stock-based employee compensation expense included in
reported net loss, net of related taxes.......................... -- -- --
Deduct: Total stock-based employee compensation expense determined
under fair value based method for all awards, net of related taxes (4) (0.03) (0.03)
------- -------- --------
Pro forma net loss.................................................. $ (463) $ (3.54) $ (3.54)
======= ======== ========
10: RETIREMENT BENEFITS
We provide retirement benefits to our employees under a number of
different plans, including:
- non-contributory, defined benefit Pension Plan,
- a cash balance pension plan for certain employees hired after June
30, 2003,
- benefits to certain management employees under SERP,
- health care and life insurance benefits under OPEB,
- benefits to a select group of management under EISP, and
- a defined contribution 401(k) plan.
Pension Plan: The Pension Plan includes funds for all of our employees,
and the employees of our subsidiaries, including Panhandle. The Pension Plan's
assets are not distinguishable by company.
F-106
In June 2003, we sold Panhandle to Southern Union Panhandle Corp. No
portion of the Pension Plan assets were transferred with the sale and Panhandle
employees are no longer eligible to accrue additional benefits. The Pension Plan
retained pension payment obligations for Panhandle employees that were vested
under the Pension Plan.
The sale of Panhandle resulted in a significant change in the makeup of
the Pension Plan. A remeasurement of the obligation was required at the date of
sale. The remeasurement further resulted in the following:
- an increase in OPEB expense of $4 million for 2003, and
- an additional charge to accumulated other comprehensive income of
$34 million ($22 million after-tax) as a result of the increase in
the additional minimum pension liability. Due to large
contributions, the additional minimum pension liability was
eliminated as of December 31, 2003.
Additionally, a significant number of Panhandle employees elected to
retire as of July 1, 2003 under the CMS Energy Employee Pension Plan. As a
result, we have recorded a $25 million ($16 million after-tax) settlement loss,
and a $10 million ($7 million after-tax) curtailment gain, pursuant to the
provisions of SFAS No. 88, which is reflected in discontinued operations.
In 2003, a substantial number of non-Panhandle retiring employees also
elected a lump sum payment instead of receiving pension benefits as an annuity
over time. Lump sum payments constitute a settlement under SFAS No. 88. A
settlement loss must be recognized when the cost of all settlements paid during
the year exceeds the sum of the service and interest costs for that year. We
recorded settlement loss of $59 million ($39 million after-tax) in December
2003.
SERP: SERP benefits are paid from a trust established in 1988. SERP is not
a qualified plan under the Internal Revenue Code; SERP trust earnings are
taxable and trust assets are included in consolidated assets. Trust assets were
$66 million at December 31, 2003, and $57 million at December 31, 2002. The
assets are classified as other non-current assets. The Accumulated Benefit
Obligation for SERP was $62 million at December 31, 2003 and $54 million at
December 31, 2002.
OPEB: Retiree health care costs at December 31, 2003 are based on the
assumption that costs would increase 8.5 percent in 2003. The rate of increase
is expected to be 7.5 percent for 2004. The rate of increase is expected to slow
to an estimated 5.5 percent by 2010 and thereafter.
The health care cost trend rate assumption significantly affects the
estimated costs recorded. A one-percentage point change in the assumed health
care cost trend assumption would have the following effects:
ONE PERCENTAGE ONE PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
IN MILLIONS
Effect on total service and interest cost component... $ 15 $ (12)
Effect on postretirement benefit obligation........... $ 149 $ (129)
We adopted SFAS No. 106, effective as of the beginning of 1992. Consumers
recorded a liability of $466 million for the accumulated transition obligation
and a corresponding regulatory asset for anticipated recovery in utility rates
(see Note 1, Corporate Structure and Accounting Policies, "Utility Regulation.")
The MPSC authorized recovery of the electric utility portion of these costs in
1994 over 18 years and the gas utility portion in 1996 over 16 years.
EISP: We implemented an EISP in 2002 to provide flexibility in separation
of employment by officers, a select group of management, or other highly
compensated employees. Terms of the plan may include payment of a lump sum,
payment of monthly benefits for life, payment of premium for continuation of
health care, or any other legally permissible term deemed to be in our best
interest to offer. EISP expense was $1 million in 2003 and $2 million in 2002.
As of December 31, 2003, the Accumulated Benefit Obligation of the EISP was $3
million.
The measurement date for all plans is December 31.
F-107
Assumptions: The following table recaps the weighted-average assumptions
used in our retirement benefits plans to determine benefit obligations and net
periodic benefit cost:
YEARS ENDED DECEMBER 31
--------------------------------------------------
PENSION & SERP OPEB
------------------------- ------------------------
2003 2002 2001 2003 2002 2001
-------- ------- -------- -------- -------- ------
Discount rate............................ 6.25% 6.75% 7.25% 6.25% 6.75% 7.25%
Expected long-term rate of return on plan
assets(a).............................. 8.75% 8.75% 9.75%
Union.................................. 8.75% 8.75% 9.75%
Non-Union.............................. 6.00% 6.00% 6.00%
Rate of compensation increase:
Pension................................ 3.25% 3.50% 5.25%
SERP................................... 5.50% 5.50% 5.50%
(a) We determine our long-term rate of return by considering historical market
returns, the current and future economic environment, the capital market
principles of risk and return, and the expertise of individuals and firms
with financial market knowledge. We use the asset allocation of the
portfolio to forecast the future expected total return of the portfolio.
The goal is to determine a long-term rate of return that can be
incorporated into the planning of future cash flow requirements in
conjunction with the change in the liability. The use of forecasted
returns for various classes of assets used to construct an expected return
model is reviewed periodically for reasonability and appropriateness.
Costs: The following table recaps the costs incurred in our retirement
benefits plans:
YEARS ENDED DECEMBER 31
---------------------------------------------------
PENSION & SERP OPEB
-------------------------- -----------------------
2003 2002 2001 2003 2002 2001
------- ------- ------- ------- ------- ------
IN MILLIONS
Service cost........................................ $ 40 $ 44 $ 39 $ 21 $ 20 $ 16
Interest expense.................................... 79 89 88 66 69 62
Expected return on plan assets...................... (81) (103) (98) (42) (43) (41)
Plan amendments..................................... -- 4 -- -- -- --
Curtailment credit.................................. (2) -- -- (8) -- --
Settlement charge................................... 84 -- -- -- -- --
Amortization of:
Net transition (asset)............................ -- -- (5) -- -- --
Prior service cost................................ 7 8 8 (7) (1) (1)
Other............................................. 9 (1) (1) 19 10 1
------ ------- ----- ----- ----- -----
Net periodic pension and postretirement benefit cost $ 136 $ 41 $ 31 $ 49 $ 55 $ 37
====== ======= ===== ===== ===== =====
Plan Assets: The following table recaps the categories of plan assets in
our retirement benefits plans:
YEARS ENDED DECEMBER 31
--------------------------------
PENSION OPEB
---------------- ---------------
2003 2002 2003 2002
-------- ------- -------- ------
Asset Category:
Fixed Income........................... 52% 32%(b) 51% 55%
Equity Securities...................... 44% 60% 48% 44%
CMS Energy Common Stock(a).......... 4% 8% 1% 1%
(a) At December 31, 2003, there were 4,970,000 shares of CMS Energy Common
Stock in the Pension Plan assets with a fair value of $42 million, and
414,000 shares in the OPEB plan assets with a fair value of $4 million. At
December 31, 2002, there were 5,099,000 shares of CMS Energy Common Stock
in the Pension Plan assets with a fair value of $48 million, and 284,000
shares in the OPEB plan assets with a fair value of $3 million.
F-108
(b) At February 29, 2004, the Pension Plan assets were 66 percent equity, 34
percent fixed income. We plan to contribute $72 million to our OPEB plan
in 2004. We estimate a contribution of $26 million to our Pension Plan in
2004.
We have established a target asset allocation for our Pension Plan assets
of 65 percent equity and 35 percent fixed income investments to maximize the
long-term return on plan assets, while maintaining a prudent level of risk. The
level of acceptable risk is a function of the liabilities of the plan. Equity
investments are diversified mostly across the Standard & Poor's 500 Index, with
a lesser allocation to the Standard & Poor's Mid Cap and Small Cap Indexes and a
Foreign Equity Index Fund. Fixed income investments are diversified across
investment grade instruments of both government and corporate issuers. Annual
liability measurements, quarterly portfolio reviews, and periodic
asset/liability studies are used to evaluate the need for adjustments to the
portfolio allocation.
We have established union and non-union VEBA trusts to fund our future
retiree health and life insurance benefits. These trusts are funded through the
rate making process for Consumers, and through direct contributions from the
non-utility subsidiaries. The equity portions of the union and non-union health
care VEBA trusts are invested in an Standard & Poor's 500 Index fund. The fixed
income portion of the union health care VEBA trust is invested in domestic
investment grade taxable instruments. The fixed income portion of the non-union
health care VEBA trust is invested in a diversified mix of domestic tax-exempt
securities. The investment selections of each VEBA are influenced by the tax
consequences, as well as the objective of generating asset returns that will
meet the medical and life insurance costs of retirees.
Reconciliations: The following table reconciles the funding of our
retirement benefit plans with our retirement benefit plans' liability:
YEARS ENDED DECEMBER 31
------------------------------------------------------
PENSION PLAN SERP OPEB
------------------- ----------------- ----------------
2003 2002 2003 2002 2003 2002
-------- -------- -------- -------- -------- ------
IN MILLIONS
Benefit obligation January 1...................... $ 1,256 $ 1,195 $ 81 $ 73 $ 982 $ 956
Service cost...................................... 38 40 2 4 21 20
Interest cost..................................... 74 84 5 5 66 69
Plan amendment.................................... (19) 3 -- -- (47) (64)
Actuarial loss (gain)............................. 55 72 (10) 1 91 41
Business combinations............................. -- -- -- -- (42) --
Benefits paid..................................... (215) (138) (2) (2) (42) (40)
-------- -------- ------ ------ -------- ------
Benefit obligation December 31(a)................. 1,189 1,256 76 81 1,029 982
-------- -------- ------ ------ -------- ------
Plan assets at fair value at January 1............ 607 845 -- -- 508 508
Actual return on plan assets...................... 115 (164) -- -- 75 (43)
Company contribution.............................. 560 64 2 2 76 83
Actual benefits paid.............................. (215) (138) (2) (2) (41) (40)
-------- -------- ------ ------ -------- ------
Plan assets at fair value at December 31.......... 1,067 607 -- -- 618 508
-------- -------- ------ ------ -------- ------
Benefit obligation in excess of plan assets....... (122) (649) (76) (81) (411) (474)
Unrecognized net loss from experience different
than assumed.................................... 501 573 3 13 313 313
Unrecognized prior service cost (benefit)......... 29 60 1 1 (112) (77)
Panhandle adjustment............................ -- (7) -- -- -- --
-------- -------- ------ ------ -------- ------
Net Balance Sheet Asset (Liability)............. 408 (23) (72) (67) (210) (238)
Additional minimum liability adjustment(b)...... -- (426) -- -- -- --
-------- -------- ------ ------ -------- ------
Total Net Balance Sheet Asset (Liability)..... $ 408 $ (449) $ (72) $ (67) $ (210) $ (238)
======== ======== ====== ====== ======== ======
F-109
(a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003
was signed into law in December 2003. This Act establishes a prescription
drug benefit under Medicare (Medicare Part D), and a federal subsidy to
sponsors of retiree health care benefit plans that provide a benefit that
is actuarially equivalent to Medicare Part D. Accounting guidance for the
subsidy is not yet available, therefore, we have decided to defer
recognizing the effects of the Act in our 2003 financial statements, as
permitted by FASB Staff Position No. 106-1. When accounting guidance is
issued, our retiree health benefit obligation may be adjusted.
(b) The Pension Plan's Accumulated Benefit Obligation of $1.055 billion
exceeded the value of the Pension Plan assets and net balance sheet
liability at December 31, 2002. As a result, we recorded an additional
minimum liability, including an intangible asset of $53 million, and $373
million of accumulated other comprehensive income. In August 2003, we made
our planned contribution of $210 million to the Pension Plan. In December
2003, we made an additional contribution of $350 million to the Pension
Plan that eliminated the additional minimum liability. The Accumulated
Benefit Obligation for the pension plan was $1.019 billion at December 31,
2003.
Defined Contribution 401(k) Plan: Our matching contributions to the 401(k)
plan are invested in CMS Energy Common Stock. Amounts charged to expense for
this plan were $12 million in 2002, and $26 million in 2001. Effective September
1, 2002, our match for the 401(k) plan was suspended.
11: LEASES
We lease various assets including vehicles, railcars, construction
equipment, an airplane, computer equipment, and buildings. We have both
full-service and net leases. A net lease requires us to pay for taxes,
maintenance, operating costs, and insurance. Most of our leases contain options
at the end of the initial lease term to:
- purchase the asset at the then fair value of the asset, or
- renew the lease at the then fair rental value.
Minimum annual rental commitments under our non-cancelable leases at
December 31, 2003 were:
CAPITAL LEASES OPERATING LEASES
-------------- ----------------
IN MILLIONS
2004............................................. $ 13 $ 12
2005............................................. 12 10
2006............................................. 12 10
2007............................................. 11 9
2008............................................. 9 7
2009 and thereafter.............................. 21 30
----- -----
Total minimum lease payments..................... 78 $ 78
=====
Less imputed interest............................ 10
-----
Present value of net minimum lease payments...... 68
Less current portion............................. 10
-----
Non-current portion.............................. $ 58
=====
Consumers is authorized by the MPSC to record both capital and operating
lease payments as operating expense and recover the total cost from our
customers. Operating lease charges were $14 million in 2003, $13 million in
2002, and $15 million in 2001.
Capital lease expenses were $17 million in 2003, $20 million, in 2002 and
$26 million in 2001. Included in the $26 million for 2001 is $7 million of
nuclear fuel lease expense. In November 2001, our nuclear fuel capital leasing
arrangement expired. At termination of the lease, we paid the lessor $48
million, which was the lessor's remaining investment at that time.
F-110
In April 2001, we entered into a lease agreement for the construction of
an office building to be used as the main headquarters for CMS Energy and
Consumers in Jackson, Michigan. In November 2003, we exercised our purchase
option under the lease agreement and bought the office building with proceeds
from a $60 million term loan.
12: JOINTLY OWNED REGULATED UTILITY FACILITIES
We are required to provide only our share of financing for the jointly
owned utility facilities. The direct expenses of the jointly owned plants are
included in operating expenses. Operation, maintenance, and other expenses of
these jointly owned utility facilities are shared in proportion to each
participant's undivided ownership interest. The following table indicates the
extent of our investment in jointly owned regulated utility facilities:
DECEMBER 31
-------------------------------------------------
NET ACCUMULATED CONSTRUCTION
INVESTMENT DEPRECIATION WORK IN PROGRESS
----------- ------------- ----------------
2003 2002 2003 2002 2003 2002
---- ---- ---- ---- ---- ----
IN MILLIONS
Campbell Unit 3 -- 93.3 percent....... $ 299 $ 298 $ 328 $ 313 $ 113 $ 111
Ludington -- 51 percent............... 84 83 87 85 (1) 2
Distribution -- various............... 74 77 32 31 5 4
13: EQUITY METHOD INVESTMENTS
Where ownership is more than 20 percent but less than a majority, we
account for certain investments in other companies, partnerships and joint
ventures by the equity method of accounting in accordance with APB Opinion No.
18. The most significant of these investments is our 50 percent interest in Jorf
Lasfar, and our 49 percent interest in the MCV Partnership (Note 15). Our
investment in Jorf Lasfar is $256 million at December 31, 2003 and $240 million
at December 31, 2002. Net income from these investments included undistributed
earnings of $41 million in 2003 and $39 million in 2002 and distributions in
excess of earnings of $68 million in 2001. Summarized financial information of
the MCV Partnership is disclosed separately in Note 15, Summarized Financial
Information of Significant Related Energy Supplier. Listed below is the
summarized income and balance sheet information for these investments.
INCOME STATEMENT DATA
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
2003
---------------------------------------------------------------------
JORF SCP ALL
LASFAR FMLP TAWEELAH INVESTMENTS OTHERS TOTAL
------ ---- -------- ----------- ------ -----
IN MILLIONS
Operating revenue............ $ 369 $ 79 $ 99 $ 74 $ 1,135 $ 1,756
Operating expenses........... 191 4 38 18 1,006 1,257
----- ----- ----- ---- ------- -------
Operating income............. 178 75 61 56 129 499
Other expense, net........... 58 43 18 25 35 179
----- ----- ----- ---- ------- -------
Net income (loss)............ $ 120 $ 32 $ 43 $ 31 $ 94 $ 320
===== ===== ===== ==== ======= =======
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
2002
---------------------------------------------------------------------
JORF SCP ALL
LASFAR FMLP TAWEELAH INVESTMENTS OTHERS TOTAL
------ ---- -------- ----------- ------ -----
IN MILLIONS
Operating revenue........... $ 364 $ 91 $ 101 $ 43 $ 3,376 $ 3,975
Operating expenses.......... 176 4 33 13 3,209 3,435
----- ----- ----- ---- ------- -------
Operating income............ 188 87 68 30 167 540
Other expense, net.......... 56 49 86 16 206 413
----- ----- ----- ---- ------- -------
Net income (loss)........... $ 132 $ 38 $ (18) $ 14 $ (39) $ 127
===== ===== ===== ==== ======= =======
F-111
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------
2001
--------------------------------------------------------------------
JORF SCP ALL
LASFAR FMLP TAWEELAH INVESTMENTS OTHERS TOTAL
------ ---- -------- ----------- ------ -----
IN MILLIONS
Operating revenue........... $ 357 $ 99 $ 44 $ 39 $ 3,814 $ 4,353
Operating expenses.......... 151 6 17 12 3,459 3,645
----- ----- ----- ---- ------- -------
Operating income............ 206 93 27 27 355 708
Other expense, net.......... 45 63 42 16 237 403
----- ----- ----- ---- ------- -------
Net income.................. $ 161 $ 30 $ (15) $ 11 $ 118 $ 305
===== ===== ===== ==== ======= =======
BALANCE SHEET DATA
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
2003
---------------------------------------------------------------------
JORF SCP ALL
LASFAR FMLP TAWEELAH INVESTMENTS OTHERS TOTAL
------ ---- -------- ----------- ------ -----
IN MILLIONS
Assets
Current assets........................... $ 277 $ -- $ 93 $ 60 $ 434 $ 864
Property, plant and equipment, net....... 10 -- 638 383 2,475 3,506
Other assets............................. 1,152 893 10 -- 1,159 3,214
------- ------ ----- ------ ------- -------
$ 1,439 $ 893 $ 741 $ 443 $ 4,068 $ 7,584
======= ====== ===== ====== ======= =======
Liabilities
Current liabilities...................... $ 314 $ 21 $ 81 $ 19 $ 425 $ 860
Long-term debt and other non-current
liabilities........................... 612 411 509 225 3,121 4,878
Equity..................................... 513 461 151 199 522 1,846
------- ------ ----- ------ ------- -------
$ 1,439 $ 893 $ 741 $ 443 $ 4,068 $ 7,584
======= ====== ===== ====== ======= =======
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
2002
---------------------------------------------------------------------
JORF SCP ALL
LASFAR FMLP TAWEELAH INVESTMENTS OTHERS TOTAL
------ ---- -------- ----------- ------ -----
Assets
Current assets........................... $ 225 $ -- $ 91 $ 36 $ 676 $ 1,028
Property, plant and equipment, net....... 7 -- 656 291 2,695 3,649
Other assets............................. 1,118 998 10 -- 1,076 3,202
------- ------ ----- ------ ------- -------
$ 1,350 $ 998 $ 757 $ 327 $ 4,447 $ 7,879
======= ====== ===== ====== ======= =======
Liabilities
Current liabilities...................... $ 249 $ 22 $ 95 $ 18 $ 692 $ 1,076
Long-term debt and other non-current
liabilities........................... 622 428 530 172 2,896 4,648
Equity..................................... 479 548 132 137 859 2,155
------- ------ ----- ------ ------- -------
$ 1,350 $ 998 $ 757 $ 327 $ 4,447 $ 7,879
======= ====== ===== ====== ======= =======
14: REPORTABLE SEGMENTS
Our reportable segments consist of business units organized and managed by
their products and services. We evaluate performance based upon the net income
of each segment. We operate principally in three reportable segments: electric
utility, gas utility, and enterprises.
The electric utility segment consists of the generation and distribution
of electricity in the state of Michigan through its subsidiary, Consumers. The
gas utility segment consists of regulated activities like transportation,
storage, and distribution of natural gas in the state of Michigan through its
subsidiary, Consumers. The enterprises segment consists of:
F-112
- investing in, acquiring, developing, constructing, managing, and
operating non-utility power generation plants and natural gas
facilities in the United States and abroad, and
- providing gas, oil, and electric marketing services to energy users.
The tables below show financial information by reportable segment. The
"Other" net income segment includes corporate interest and other, discontinued
operations, and the cumulative effect of accounting changes. We restated 2002
and 2001 information due to the management reorganization and the change in our
business strategy in 2003 from five to three operating segments.
REPORTABLE SEGMENTS
YEARS ENDED DECEMBER 31
----------------------------------
RESTATED RESTATED
2003 2002 2001
--------- -------- --------
IN MILLIONS
Revenues
Electric utility............................... $ 2,583 $ 2,644 $ 2,630
Gas utility.................................... 1,845 1,519 1,338
Enterprises.................................... 1,085 4,508 4,034
Other.......................................... -- 2 4
--------- -------- --------
$ 5,513 $ 8,673 $ 8,006
========= ======== ========
Earnings from Equity Method Investees
Enterprises.................................... $ 164 $ 92 $ 172
--------- -------- --------
$ 164 $ 92 $ 172
========= ======== ========
Depreciation, Depletion, and Amortization
Electric utility............................... $ 247 $ 228 $ 219
Gas utility.................................... 128 118 118
Enterprises.................................... 52 64 70
Other.......................................... 1 2 1
--------- -------- --------
$ 428 $ 412 $ 408
========= ======== ========
Income Taxes
Electric utility............................... $ 90 $ 138 $ 69
Gas utility.................................... 35 33 25
Enterprises.................................... 14 (155) (83)
Other.......................................... (81) (57) (105)
--------- -------- --------
$ 58 $ (41) $ (94)
========= ======== ========
Net Income (Loss)
Electric utility............................... $ 167 $ 264 $ 120
Gas utility.................................... 38 46 21
Enterprises.................................... 8 (419) (272)
Other.......................................... (257) (541) (328)
--------- -------- --------
$ (44) $ (650) $ (459)
========= ======== ========
Investments in Equity Method Investees
Enterprises.................................... $ 1,366 $ 1,367 $ 1,912
Other.......................................... 24 2 36
--------- -------- --------
$ 1,390 $ 1,369 $ 1,948
========= ======== ========
F-113
YEARS ENDED DECEMBER 31
------------------------------------
RESTATED RESTATED
2003 2002 2001
--------- ---------- ----------
IN MILLIONS
Identifiable Assets
Electric utility(a)........... $ 6,831 $ 6,058 $ 5,784
Gas utility(a)................ 2,983 2,586 2,734
Enterprises................... 3,670 5,724 8,891
Other......................... 354 413 224
--------- ---------- ----------
$ 13,838 $ 14,781 $ 17,633
========= ========== ==========
Capital Expenditures(b)
Electric utility.............. $ 310 $ 437 $ 623
Gas utility................... 135 181 145
Enterprises................... 49 235 427
Other......................... -- 8 263
--------- ---------- ----------
$ 494 $ 861 $ 1,458
========= ========== ==========
GEOGRAPHIC AREAS(C)
RESTATED RESTATED
2003 2002 2001
---------- ---------- ----------
IN MILLIONS
United States
Operating Revenue.............. $ 5,222 $ 8,361 $ 7,639
Operating Income (Loss)........ 511 (36) 189
Identifiable Assets............ 12,372 13,355 14,770
International
Operating Revenue.............. $ 291 $ 312 $ 367
Operating Income (Loss)........ 84 111 (38)
Identifiable Assets............ 1,466 1,426 2,863
(a) Amounts includes a portion of Consumers' assets for both the Electric and
Gas utility units.
(b) Amounts include electric restructuring implementation plan, capital leases
for nuclear fuel, purchase of nuclear fuel and other assets and electric
DSM costs. Amounts also include a portion of Consumers' capital
expenditures for plant and equipment that both the electric and gas
utility units use.
(c) Revenues are based on the country location of customers.
15: SUMMARIZED FINANCIAL INFORMATION OF SIGNIFICANT RELATED ENERGY SUPPLIER
Under the PPA with the MCV Partnership discussed in Note 4, Uncertainties,
our 2003 obligation to purchase electric capacity from the MCV Partnership
provided 15 percent of our owned and contracted electric generating capacity.
Summarized financial information of the MCV Partnership follows:
STATEMENTS OF INCOME
YEARS ENDED
DECEMBER 31
------------------------
2003 2002 2001
------- ------- -------
IN MILLIONS
Operating revenue(a)......................................... $ 584 $ 597 $ 611
Operating expenses........................................... 416 409 453
------- ------- -------
Operating income............................................. 168 188 158
Other expense, net........................................... 108 114 110
------- ------- -------
Income before cumulative effect of accounting change......... 60 74 48
Cumulative effect of change in method of accounting for
derivative options contracts(b)............................ -- 58 --
------- ------- -------
Net Income................................................... $ 60 $ 132 $ 48
======= ======= =======
F-114
BALANCE SHEETS
DECEMBER 31
-------------------
2003 2002
-------- ---------
IN MILLIONS
ASSETS
Current assets(c)............. $ 389 $ 358
Plant, net.................... 1,494 1,550
Other assets.................. 187 190
--------- ---------
$ 2,070 $ 2,098
========= =========
LIABILITIES AND EQUITY
Current liabilities........... $ 250 $ 209
Non-current
liabilities(d).............. 1,021 1,155
Partners' equity(e)........... 799 734
--------- ---------
$ 2,070 $ 2,098
========= =========
------------
(a) Revenue from Consumers totaled $514 million in 2003, $557 million in 2002,
and $550 million in 2001.
(b) On April 1, 2002, the MCV Partnership implemented a new accounting
standard for derivatives. As a result, the MCV Partnership began
accounting for several natural gas contracts containing an option
component at fair value. The MCV Partnership recorded a $58 million
cumulative effect adjustment for the change in accounting principle as an
increase to earnings. CMS Midland's 49 percent ownership share was $28
million ($18 million after-tax), which is reflected as a change in
accounting principle on our Consolidated Statements of Income (Loss).
(c) Receivables from Consumers totaled $40 million for December 31, 2003 and
$44 million for December 31, 2002.
(d) FMLP is the sole beneficiary of a trust that is the lessor in a long-term
direct finance lease with the MCV Partnership. CMS Holdings holds a 46.4
percent ownership interest in FMLP. The MCV Partnership's lease
obligations, assets, and operating revenues secure FMLP's debt. The
following table summarizes obligation and payment information regarding
the direct finance lease.
DECEMBER 31
--------------
2003 2002
---- ----
IN MILLIONS
Balance Sheet:
MCV Partnership: Lease obligation $ 894 $ 975
FMLP: Non-recourse debt 431 449
Lease payment to service non-recourse debt (including
interest) 158 370
CMS Holdings: Share of interest portion of lease payment 37 34
Share of principle portion of lease payment 36 65
YEARS ENDED
DECEMBER 31
-----------------
2003 2002 2001
---- ---- ----
IN MILLIONS
Income Statement:
FMLP: Earnings $ 32 $ 38 $ 30
(e) CMS Midland's recorded investment in the MCV Partnership includes
capitalized interest, which we are expensing over the life of our
investment in the MCV Partnership. The financing agreements prohibit the
MCV Partnership from distributing any cash to its owners until it meets
certain financial test requirements. We do not anticipate receiving a cash
distribution in the near future.
16: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS: This standard
became effective January 2003. It requires companies to record the fair value of
the cost to remove assets at the end of their useful life, if there is a legal
obligation to do so. We have legal obligations to remove some of our assets,
including our nuclear plants, at the end of their useful lives.
F-115
Before adopting this standard, we classified the removal cost of assets
included in the scope of SFAS No. 143 as part of the reserve for accumulated
depreciation. For these assets, the removal cost of $448 million that was
classified as part of the reserve at December 31, 2002, was reclassified in
January 2003, in part, as:
- $364 million ARO liability,
- $134 million regulatory liability,
- $42 million regulatory asset, and
- $7 million net increase to property, plant, and equipment as
prescribed by SFAS No. 143.
We are reflecting a regulatory asset and liability as required by SFAS No.
71 for regulated entities instead of a cumulative effect of a change in
accounting principle. Accretion of $1 million related to the Big Rock and
Palisades' profit component included in the estimated cost of removal was
expensed for 2003.
The fair value of ARO liabilities has been calculated using an expected
present value technique. This technique reflects assumptions, such as costs,
inflation, and profit margin that third parties would consider to assume the
settlement of the obligation. Fair value, to the extent possible, should include
a market risk premium for unforeseeable circumstances. No market risk premium
was included in our ARO fair value estimate since a reasonable estimate could
not be made. If a five percent market risk premium were assumed, our ARO
liability would be $381 million.
If a reasonable estimate of fair value cannot be made in the period the
asset retirement obligation is incurred, such as assets with indeterminate
lives, the liability is to be recognized when a reasonable estimate of fair
value can be made. Generally, transmission and distribution assets have
indeterminate lives. Retirement cash flows cannot be determined. There is a low
probability of a retirement date, so no liability has been recorded for these
assets. No liability has been recorded for assets that have insignificant
cumulative disposal costs, such as substation batteries. The measurement of the
ARO liabilities for Palisades and Big Rock are based on decommissioning studies
that are based largely on third-party cost estimates.
In addition, in 2003, we recorded an ARO liability for certain pipelines
and non-utility generating plants and a $1 million, net of tax, cumulative
effect of change in accounting for accretion and depreciation expense for ARO
liabilities incurred prior to 2003. The pro forma effect on results of
operations would not have been material for the year ended December 31, 2002.
The following tables describe our assets that have legal obligations to be
removed at the end of their useful life.
IN SERVICE TRUST
ARO DESCRIPTION DATE LONG LIVED ASSETS FUND
-------------------------------------- ---------- ------------------------------------ -----------
IN MILLIONS
December 31, 2003
Palisades-decommission plant site... 1972 Palisades nuclear plant $ 487
Big Rock-decommission plant site.... 1962 Big Rock nuclear plant 88
JHCampbell intake/discharge water
line............................. 1980 Plant intake/discharge water line --
Closure of coal ash disposal areas.. Various Generating plants coal ash areas --
Closure of wells at gas storage
fields........................... Various Gas storage fields --
Indoor gas services equipment
relocations...................... Various Gas meters located inside structures --
Closure of gas pipelines............ Various Gas transmission pipelines --
Dismantle natural gas-fired power
plant............................ 1997 Gas fueled power plant --
F-116
PRO FORMA ARO LIABILITY CASH ARO
ARO LIABILITY ----------------------------- FLOW LIABILITY
ARO DESCRIPTION 1/1/02 1/1/03 INCURRED SETTLED ACCRETION REVISIONS 12/31/03
----------------------------- ------------- ------ -------- ----------- --------- --------- ---------
IN MILLIONS
December 31, 2003
Palisades-decommission..... $ 232 $ 249 $ -- $ -- $ 19 $ -- $ 268
Big Rock-decommission...... 94 61 -- (39) 13 -- 35
JHCampbell intake line..... -- -- -- -- -- -- --
Coal ash disposal areas.... 46 51 -- (4) 5 -- 52
Wells at gas storage
fields.................. 2 2 -- -- -- -- 2
Indoor gas services
relocations............. 1 1 -- -- -- -- 1
Closure of gas
pipelines(a)............ 7 8 -- (8) -- -- --
Dismantle natural
gas-fired power plant... 1 1 -- -- -- -- 1
----- ----- ---- ----- ----- ---- -----
Total................. $ 383 $ 373 $ -- $ (51) $ 37 $ -- $ 359
===== ===== ==== ===== ===== ==== =====
------------
(a) ARO Liability was settled in 2003 as a result of the sales of Panhandle
and CMS Field Services.
Reclassification of Non-Legal Cost of Removal: Beginning in December 2003,
the SEC requires the quantification and reclassification of the estimated cost
of removal obligations arising from other than legal obligations. These
obligations have been accrued through depreciation charges. We estimate that we
had $983 million in 2003 and $907 million in 2002 of previously accrued asset
removal costs related to our regulated operations, for other than legal
obligations. These obligations, which were previously classified as a component
of accumulated depreciation, were reclassified as regulatory liabilities in the
accompanying consolidated balance sheets.
17: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
SFAS NO. 149, AMENDMENT OF STATEMENT 133 ON DERIVATIVE INSTRUMENTS AND
HEDGING ACTIVITIES: Amends and clarifies financial accounting and reporting for
derivative instruments, including certain derivative instruments embedded in
other contracts and for hedging activities under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. This statement is effective for
contracts entered into or modified after June 30, 2003. Implementation of this
statement has not impacted our Consolidated Financial Statements.
SFAS NO. 150, ACCOUNTING FOR CERTAIN FINANCIAL INSTRUMENTS WITH
CHARACTERISTICS OF BOTH LIABILITIES AND EQUITY: Establishes standards for how we
classify and measure certain financial instruments with characteristics of both
liabilities and equity. The statement requires us to classify financial
instruments within its scope as liabilities rather than mezzanine equity, the
area between liabilities and equity. SFAS No. 150 became effective July 1, 2003.
We have five Trust Preferred Securities outstanding as of December 31,
2003 that are issued by our affiliated trusts. Each trust holds a subordinated
debenture from the parent company. The terms of the debentures are identical to
those of the trust-preferred securities, except that the debenture has an
explicit maturity date. The trust documents, in turn, require that the trust be
liquidated upon the repayment of the debenture. The preferred securities are
redeemable upon the liquidation of the subsidiary; therefore, are considered
equity in the financial statements of the subsidiary.
At their October 29, 2003 Board meeting, the FASB deferred the
implementation of the portion of SFAS No. 150 relating to mandatorily redeemable
noncontrolling interests in subsidiaries when the noncontrolling interests are
classified as equity in the financial statements of the subsidiary. Our Trust
Preferred Securities are included in the deferral action.
Upon adoption of FASB Interpretation No. 46, we determined that our trusts
that issue Trust Preferred Securities should be deconsolidated and reported as
long-term debt -- related parties. Refer to further discussion under FASB
Interpretation No. 46, Consolidation of Variable Interest Entities.
F-117
EITF ISSUE NO. 02-03, RECOGNITION AND REPORTING OF GAINS AND LOSSES ON
ENERGY TRADING CONTRACTS UNDER EITF ISSUES NO. 98-10 AND 00-17: At the October
25, 2002 meeting, the EITF reached a consensus to rescind EITF Issue No. 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. As a result, only energy contracts that meet the definition of a
derivative in SFAS No. 133 will be carried at fair value. Energy trading
contracts that do not meet the definition of a derivative must be accounted for
as executory contracts. We recognized a cumulative effect of change in
accounting principle loss of $23 million, net of tax, for the year ended
December 31, 2003.
EITF ISSUE NO. 01-08, DETERMINING WHETHER AN ARRANGEMENT CONTAINS A LEASE:
In May 2003, the EITF reached consensus in EITF Issue No. 01-08 requiring both
parties to a transaction, such as power purchase agreements, to determine
whether a service contract or similar arrangement is or includes a lease within
the scope of SFAS No. 13, Accounting for Leases. The consensus is to be applied
prospectively to arrangements agreed to, modified, or acquired in business
combinations in fiscal periods beginning July 1, 2003.
Prospective accounting under EITF Issue No. 01-08, could affect the timing
and classification of revenue and expense recognition. Certain product sales and
service revenue and expenses may be required to be reported as rental or leasing
income and/or expenses. Transactions deemed to be capital lease arrangements
would be included on our balance sheet. The adoption of EITF Issue No. 01-08 has
not impacted our results of operations, cash flows, or financial position.
EITF ISSUE NO. 03-04, ACCOUNTING FOR CASH BALANCE PENSION PLANS: In May
2003, the EITF reached consensus in EITF Issue No. 03-04 to specifically address
the accounting for certain cash balance pension plans. EITF Issue No. 03-04
concluded that certain cash balance plans be accounted for as defined benefit
plans under SFAS No. 87, Employers' Accounting for Pensions. The EITF
requirements must be applied as of our next plan measurement date after
issuance, which is December 31, 2003. In 2003, we started a cash balance pension
plan that covers employees hired after June 30, 2003. We do account for this
plan as a defined benefit plan under SFAS No. 87 and comply with EITF Issue No.
03-04. For further information, see Note 10, Retirement Benefits.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES:
FASB issued this interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest to consolidate the entity.
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46.
For entities that have not previously adopted FASB Interpretation No. 46,
Revised FASB Interpretation No. 46 provides an implementation deferral, until
the first quarter of 2004. Revised FASB Interpretation No. 46 is effective for
the first quarter of 2004 for all entities other than special purpose entities.
Special-purpose entities must apply either FASB Interpretation No. 46 or Revised
FASB Interpretation No. 46 for the first reporting period that ends after
December 15, 2003.
As of December 31, 2003, we have completed our analysis for and have
adopted Revised FASB Interpretation No. 46 for all entities other than the MCV
Partnership and FMLP. We continue to evaluate and gather information regarding
those entities. We will adopt the provisions of Revised FASB Interpretation No.
46 for the MCV Partnership and FMLP in the first quarter of 2004.
If our completed analysis shows we have the controlling financial interest
in the MCV Partnership and FMLP, we would consolidate their assets, liabilities,
and activities, including $700 million of non-recourse debt, into our financial
statements. Financial covenants under our financing agreements could be impacted
negatively after such a consolidation. As a result, it may become necessary to
seek amendments to the relevant financing agreements to modify the terms of
certain of these covenants to remove the effect of this consolidation, or to
refinance the relevant debt. As of December 31, 2003, our investment in the MCV
Partnership was $419 million and our investment in the FMLP was $224 million.
F-118
We determined that we have the controlling financial interest in three
entities that are determined to be variable interest entities. We have
50-percent partnership interest in T.E.S Filer City Station Limited Partnership,
Grayling Generating Station Limited Partnership, and Genesee Power Station
Limited Partnership. Additionally, we have operating and management contracts
and are the primary purchaser of power from each partnership through long-term
power purchase agreements. Collectively, these interests provide us with the
controlling financial interest as defined by the Interpretation. Therefore, we
have consolidated these partnerships into our consolidated financial statements
for the first time as of December 31, 2003. At December 31, 2003, total assets
consolidated for these entities are $227 million and total liabilities are $164
million, including $128 million of non-recourse debt. At December 31, 2003, CMS
Energy has outstanding letters of credit and guarantees of $5 million relating
to these entities. At December 31, 2003, minority interest recorded for these
entities totaled $36 million.
We also determined that we do not hold the controlling financial interest
in our trust preferred security structures. Accordingly, those entities have
been deconsolidated as of December 31, 2003. Company obligated Trust Preferred
Securities totaling $663 million that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we have reflected $684 million of long-term debt -- related
parties and have reflected an investment in related parties of $21 million.
We are not required to, and have not, restated prior periods for the
impact of this accounting change.
Additionally, we have non-controlling interests in four other variable
interest entities. FASB Interpretation No. 46 requires us to disclose certain
information about these entities. The chart below details our involvement in
these entities at December 31, 2003:
INVESTMENT OPERATING
NAME INVOLVEMENT BALANCE AGREEMENT WITH
(OWNERSHIP INTEREST) NATURE OF THE ENTITY COUNTRY DATE (IN MILLIONS) CMS ENERGY
-------------------- -------------------- -------------------- ----------- ------------- ---------------
Loy Yang Power (49%) Power Generator Australia 1997 $ -- Yes
Taweelah (40%) Power Generator United Arab Emirates 1999 $ 83 Yes
Jubail (25%) Generator-- Saudi Arabia 2001 $ -- Yes
Under Construction
Shuweihat (20%) Generator-- United Arab Emirates 2001 $ (24)(a) Yes
Under Construction
-----
Total $ 59
=====
TOTAL
NAME GENERATING
(OWNERSHIP INTEREST) CAPACITY
-------------------- ----------
Loy Yang Power (49%) 2,000 MW
Taweelah (40%) 777 MW
Jubail (25%) 250 MW
Shuweihat (20%) 1,500 MW
-----
Total 4,527 MW
=====
(a) At December 31, 2003, we recorded a negative investment in Shuweihat. The
balance is comprised of our investment of $3 million reduced by our
proportionate share of the negative fair value of derivative instruments
of $27 million. We are required to record the negative investment due to
our future commitment to make an equity investment in Shuweihat.
Our maximum exposure to loss through our interests in these variable
interest entities is limited to our investment balance of $59 million, Loy Yang
currency translation losses of $110 million, net of tax, and letters of credit,
guarantees, and indemnities relating to Taweelah and Shuweihat totaling $146
million. Included in the $146 million is a letter of credit relating to our
required initial investment in Shuweihat of $70 million. We plan to contribute
our initial investment when the project becomes commercially operational in
2004.
STATEMENT OF POSITION, ACCOUNTING FOR CERTAIN COSTS AND ACTIVITIES RELATED
TO PROPERTY, PLANT, AND EQUIPMENT: At its September 9, 2003 meeting, the
Accounting Standards Executive Committee, of the American Institute of Certified
Public Accountants voted to approve the Statement of Position, Accounting for
Certain Costs and Activities Related to Property, Plant, and Equipment. The
Statement of Position is expected to be presented for FASB clearance in 2004 and
F-119
would be applicable for fiscal years beginning after December 15, 2004. An asset
classified as property, plant, and equipment asset often comprises multiple
parts and costs. A component accounting policy determines the level at which
those parts are recorded. Capitalization of certain costs related to property,
plant, and equipment are included in the total cost. The Statement of Position
could impact our component and capitalization accounting for property, plant,
and equipment. We continue to evaluate the impact, if any, this Statement of
Position will have upon adoption.
18: RESTATEMENT AND RECLASSIFICATION
We have determined the need to make certain adjustments to our
consolidated financial statements for the fiscal years ended December 31, 2002,
December 31, 2001, and December 31, 2000. Therefore, the consolidated financial
statements for 2002 and 2001 have been restated from amounts previously
reported. The table below summarizes the significant adjustments and the effects
on our consolidated net loss.
NET LOSS (INCREASE) DECREASE 2002 2001 TOTAL
-------------------------------------------------------- ------ ------ ------
IN MILLIONS
Interest allocation reclassification for International
Energy Distribution................................... $ (3) $ 3 $ --
Derivatives related to the equity method investments.... (27) (14) (41)
------ ------ ------
Total................................................... $ (30) $ (11) $ (41)
====== ====== ======
INTEREST ALLOCATION RECLASSIFICATION FOR INTERNATIONAL ENERGY
DISTRIBUTION: Due to lack of progress on the sale, we reclassified our
international energy distribution business, which includes CPEE and SENECA, from
discontinued operations to continuing operations for the years 2003, 2002, and
2001. When we initially reported the international energy distribution business
as a discontinued operation in 2001, we applied APB Opinion No. 30, which
allowed us to record a provision for anticipated operating losses. We currently
apply FASB No. 144 which does not allow us to record a provision for future
operating losses. Therefore, in the process of reclassifying the international
energy distribution business to continuing operations and reversing such
provisions, we increased our net loss by $3 million in 2002 and decreased our
net loss by $3 million in 2001.
DERIVATIVES RELATED TO THE EQUITY METHOD INVESTMENTS: Some of our equity
affiliates hold derivative instruments, including interest rate swaps and other
similar instruments. Some of these instruments have been accounted for as cash
flow hedges, with changes in the fair value of the hedges reported in
accumulated other comprehensive income in 2003, 2002 and 2001. However, in late
2003 it was determined that certain of our equity affiliates did not formally
designate their instruments as hedges, or did not do so in a timely manner, in
accordance with SFAS No. 133. Therefore, the changes in the fair value of the
hedges should have been reported in earnings in 2003, 2002, and 2001. As a
result, the effects of the changes in the fair value of the hedges require
restatement. Our proportionate share of the adjustments increased our net loss
by $27 million in 2002 and increased our net loss by $14 million in 2001.
BALANCE SHEET IMPACTS: The most significant effects on our consolidated
balance sheets include the reclassification of International Energy Distribution
from "held for sale" to continuing operations and the change in our investments
due to the correction of the derivatives discussed above.
During the fourth quarter of 2000, we wrote down the value of our
investment in Loy Yang by $329 million ($268 million after-tax). We have now
concluded that the tax benefit associated with the write-down should have been
reduced by $38 million. Accordingly, our retained deficit as of January 1, 2001
increased by this amount.
The following tables present the effects of the adjustments we made to our
consolidated financial statements for the fiscal years ended December 31, 2002
and December 31, 2001, as well as effects of reclassifying Marysville and
Parmelia into discontinued operations.
F-120
CONSOLIDATED STATEMENTS OF INCOME
2002 2001
------------------------ ------------------------
AS REPORTED AS RESTATED AS REPORTED AS RESTATED
----------- ----------- ----------- -----------
IN MILLIONS
Operating Revenue.............................. $ 8,561 $ 8,673 $ 7,878 $ 8,006
Earnings from Equity Method Investees.......... 126 92 185 172
Operating expenses
Operation.................................... 7,177 7,242 6,762 6,851
Maintenance.................................. 211 212 224 225
Depreciation, depletion and amortization..... 403 412 398 408
General taxes................................ 199 222 196 220
Asset impairment charges..................... 598 602 240 323
-------- -------- -------- --------
Total Operating Expenses..................... 8,588 8,690 7,820 8,027
-------- -------- -------- --------
Operating Income............................... 99 75 243 151
-------- -------- -------- --------
Other Income (Deductions):
Accretion expense............................ (31) (31) (37) (37)
Gain (loss) on asset sales, net.............. 37 37 - (2)
Other, net................................... (4) (6) 25 26
-------- -------- -------- --------
Total Other Income (Deductions).............. 2 -- (12) (13)
-------- -------- -------- --------
Fixed Charges.................................. 504 508 562 566
Loss From Continuing Operations Before Income
Taxes and Minority Interests................. (403) (433) (331) (428)
-------- -------- -------- --------
Income Tax Expense (Benefit)................... 13 (41) (98) (94)
Minority Interests............................. -- 2 3 (7)
-------- -------- -------- --------
Loss From Continuing Operations................ (416) (394) (236) (327)
-------- -------- -------- --------
Loss From Discontinued Operations.............. (222) (274) (210) (128)
-------- -------- -------- --------
Loss Before Cumulative Effect of Change in
Accounting Principle......................... (638) (668) (446) (455)
-------- -------- -------- --------
Cumulative Effect of Change in Accounting...... 18 18 (2) (4)
-------- -------- -------- --------
Consolidated Net Loss.......................... $ (620) $ (650) $ (448) $ (459)
======== ======== ======== ========
Basic and Diluted Loss Per Share............... $ (4.46) $ (4.68) $ (3.42) $ (3.51)
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF CASH FLOWS
2002 2001
------------------------ ------------------------
AS REPORTED AS RESTATED AS REPORTED AS RESTATED
----------- ----------- ----------- -----------
IN MILLIONS
Consolidated net loss.......................... $ (620) $ (650) $ (448) $ (459)
Net cash provided by operating activities...... 624 614 366 372
Net cash provided by (used in) investing
activities................................... 863 829 (1,348) (1,349)
Net cash provided by (used in) financing
activities................................... (1,237) (1,223) 968 967
Effect of Exchange Rate on Cash................ -- 8 -- (10)
Net Increase (Decrease) in Cash and Temporary
Cash Investments............................. 250 228 (14) (20)
--------- --------- --------- ---------
Cash and Cash Investments, End of Period....... $ 377 $ 351 $ 127 $ 123
========= ========= ========= =========
F-121
CONSOLIDATED BALANCE SHEETS
2002 2001
------------------------ ------------------------
AS REPORTED AS RESTATED AS REPORTED AS RESTATED
----------- ----------- ----------- -----------
IN MILLIONS
ASSETS
Plant and Property (at cost)................... $ 5,234 $ 6,103 $ 5,848 $ 6,703
---------- --------- ---------- ---------
Investments.................................... 1,398 1,369 1,961 1,960
---------- --------- ---------- ---------
Current Assets:
Cash and temporary cash investments.......... 377 351 127 123
Restricted cash.............................. -- 38 -- 4
Accounts receivable, notes receivable, and
accrued revenue.......................... 757 783 704 743
Assets held for sale......................... 644 595 471 412
Price risk management assets................. 115 115 327 327
Prepayments, inventories, and other.......... 855 857 931 951
---------- --------- ---------- ---------
Total Current Assets........................... 2,748 2,739 2,560 2,560
---------- --------- ---------- ---------
Non-current Assets:
Regulatory assets............................ 1,053 1,053 1,105 1,105
Assets held for sale......................... 2,081 2,084 3,480 3,438
Price risk management assets................. 135 135 368 368
Other........................................ 1,266 1,298 1,453 1,499
---------- --------- ---------- ---------
Total Non-current Assets....................... 4,535 4,570 6,406 6,410
---------- --------- ---------- ---------
Total Assets................................... $ 13,915 $ 14,781 $ 16,775 $ 17,633
========== ========= ========== =========
2002 2001
------------------------ ------------------------
AS REPORTED AS RESTATED AS REPORTED AS RESTATED
----------- ----------- ----------- -----------
IN MILLIONS
STOCKHOLDERS' INVESTMENT AND LIABILITIES
Capitalization:
Common stockholders' equity...................... $ 1,133 $ 1,078 $ 2,038 $ 1,991
Long-term debt................................... 5,356 5,357 5,840 5,842
Non-current portion of capital leases............ 116 116 71 71
Other............................................ 927 927 1,258 1,258
---------- --------- ---------- ---------
Total Capitalization............................. 7,532 7,478 9,207 9,162
---------- --------- ---------- ---------
Minority Interests............................... 21 38 24 43
---------- --------- ---------- ---------
Current Liabilities:
Current portion of long-term debt and capital
leases...................................... 640 646 1,016 1,016
Notes payable.................................. 458 458 416 416
Accounts payable............................... 482 496 595 614
Accrued taxes.................................. 291 291 111 111
Liabilities held for sale...................... 465 427 639 605
Price risk management liabilities.............. 96 96 367 367
Deferred income taxes.......................... 15 15 49 49
Other.......................................... 451 460 478 494
---------- --------- ---------- ---------
Total Current Liabilities........................ 2,898 2,889 3,671 3,672
---------- --------- ---------- ---------
Non-current Liabilities:
Deferred income taxes.......................... 414 438 824 864
Regulatory liabilities for cost of removal..... -- 907 -- 870
Liabilities held for sale...................... 1,243 1,218 1,376 1,354
Price risk management liabilities.............. 135 135 287 287
Other.......................................... 1,672 1,678 1,386 1,381
---------- --------- ---------- ---------
Total Non-current Liabilities.................... 3,464 4,376 3,873 4,756
---------- --------- ---------- ---------
Total Stockholders' Investment and
Liabilities.................................... $ 13,915 $ 14,781 $ 16,775 $ 17,633
========== ========= ========== =========
F-122
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
2002 2001
------------------------ ------------------------
AS REPORTED AS RESTATED AS REPORTED AS RESTATED
----------- ----------- ----------- -----------
IN MILLIONS
Retained Deficit
At beginning of period.............. $ (951) $ (1,001) $ (313) $ (352)
Consolidated net loss............... (620) (650) (448) (459)
Common stock dividends declared..... (149) (149) (190) (190)
--------- --------- -------- ---------
At end of period................. (1,720) (1,800) (951) (1,001)
--------- --------- -------- ---------
Accumulated Other Comprehensive Loss
At beginning of period.............. (269) (266) (201) (198)
Minimum pension liability........... (241) (241) -- --
Investments......................... 7 7 (3) (3)
Derivative instruments.............. (25) (3) (38) (38)
Foreign currency translation........ (225) (225) (27) (27)
--------- --------- -------- ---------
At end of period................. (753) (728) (269) (266)
--------- --------- -------- ---------
Common stock.......................... 1 1 1 1
Other paid-in capital................. 3,605 3,605 3,257 3,257
--------- --------- -------- ---------
Total Common Stockholders' Equity..... $ 1,133 $ 1,078 $ 2,038 $ 1,991
========= ========= ======== =========
Total Other Comprehensive Loss........ $ (1,104) $ (1,112) $ (516) $ (527)
========= ========= ======== =========
19: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)
We have determined the need to make certain adjustments to our
consolidated financial statements for the quarterly periods of 2003 and 2002.
Therefore, the consolidated financial statements for the quarterly periods of
2003 and 2002 have been restated from amounts previously reported.
2003 (RESTATED)
------------------------------------------
QUARTERS ENDED MARCH 31 JUNE 30 SEPT. 30 DEC. 31
------------------------------------------------------------- -------- -------- --------- ---------
IN MILLIONS, EXCEPT PER SHARE AMOUNTS
Operating revenue............................................ $ 1,968 $ 1,126 $ 1,047 $ 1,372
Operating income............................................. 236 176 78 105
Income (loss) from continuing operations..................... 75 (12) (71) (35)
Discontinued operations(a)................................... 31 (53) 2 43
Cumulative effect of change in accounting principles(a)...... (24) -- -- --
Consolidated net income (loss)............................... 82 (65) (69) 8
Income (loss) from continuing operations per average common
share-- basic.............................................. 0.52 (0.08) (0.47) (0.22)
Income (loss) from continuing operations per average common
share-- diluted............................................ 0.47 (0.08) (0.47) (0.22)
Basic earnings (loss) per average common share(b)............ 0.57 (0.45) (0.46) 0.05
Diluted earnings (loss) per average common share(b).......... 0.52 (0.45) (0.46) 0.05
Dividends declared per common share.......................... -- -- -- --
Common stock prices(c)
High....................................................... 10.59 8.50 7.99 8.63
======== ======== ======== ========
Low........................................................ 3.49 4.58 6.11 7.44
======== ======== ======== ========
F-123
2002 (RESTATED)
------------------------------------------
QUARTERS ENDED MARCH 31 JUNE 30 SEPT. 30 DEC. 31
------------------------------------------------------------- -------- -------- --------- ---------
IN MILLIONS, EXCEPT PER SHARE AMOUNTS
Operating revenue............................................ $ 2,248 $ 2,123 $ 2,566 $ 1,736
Operating income (loss)...................................... 283 136 178 (522)
Income (loss) from continuing operations..................... 103 17 (1) (513)
Discontinued operations(a)................................... (52) (128) 26 (120)
Cumulative effect of change in accounting principles(a)...... -- 17 1 --
Consolidated net income (loss)............................... 51 (94) 26 (633)
Income (loss) from continuing operations per average common
share-- basic.............................................. 0.77 0.14 -- (3.57)
Income (loss) from continuing operations per average common
share-- diluted............................................ 0.77 0.14 -- (3.57)
Basic earnings (loss) per average common share(b)............ 0.38 (0.69) 0.18 (4.40)
Diluted earnings (loss) per average common share(b).......... 0.38 (0.69) 0.18 (4.40)
Dividends declared per common share.......................... 0.365 0.365 0.18 0.18
Common stock prices(c)
High....................................................... 24.62 22.24 11.28 10.48
Low........................................................ 21.27 10.46 7.49 5.79
======== ======== ======== ========
(a) Net of tax
(b) Sum of the quarters may not equal the annual earnings per share due to
changes in shares outstanding
(c) Based on New York Stock Exchange -- Composite transactions
The following tables present the effects of the adjustments we made to our
consolidated financial statements for the quarterly periods of 2003 and 2002, as
well as the effects of reclassifying Marysville and Parmelia into discontinued
operations.
2003
-------------------------------------
QUARTERS ENDED -- REPORTED VS. RESTATED MARCH 31 JUNE 30 SEPT. 30
------------------------------------------------------- ----------- ---------- -----------
IN MILLIONS, EXCEPT PER SHARE AMOUNTS
Operating revenue as reported ......................... $ 1,992 $ 1,154 $ 1,016
Operating revenue as restated ......................... 1,968 1,126 1,047
Operating income as reported .......................... 239 183 129
Operating income as restated .......................... 236 176 78
Income (loss) from continuing operations as reported .. 76 (5) (34)
Income (loss) from continuing operations as restated .. 75 (12) (71)
Discontinued operations as reported ................... 27 (40) (43)
Discontinued operations as restated ................... 31 (53) 2
Consolidated net income (loss) as reported ............ 79 (45) (77)
Consolidated net income (loss) as restated ............ 82 (65) (69)
Basic earnings (loss) per average common share as
reported ............................................ 0.55 (0.31) (0.51)
Basic earnings (loss) per average common share as
restated ............................................ 0.57 (0.45) (0.46)
Diluted earnings (loss) per average common share as
reported ............................................ 0.51 (0.31) (0.51)
Diluted earnings (loss) per average common share as
restated ............................................ 0.52 (0.45) (0.46)
F-124
2002
------------------------------------------
QUARTERS ENDED -- REPORTED VS. RESTATED MARCH 31 JUNE 30 SEPT. 30 DEC. 31
------------------------------------------------------ -------- -------- --------- ---------
IN MILLIONS, EXCEPT PER SHARE AMOUNTS
Operating revenue as reported......................... $ 2,263 $ 2,135 $ 2,534 $ 1,708
Operating revenue as restated......................... 2,248 2,123 2,566 1,736
Operating income (loss) as reported................... 275 152 190 (520)
Operating income (loss) as restated................... 283 136 178 (522)
Income (loss) from continuing operations as reported.. 93 36 11 (557)
Income (loss) from continuing operations as restated.. 103 17 (1) (513)
Discontinued operations as reported................... (51) (127) 25 (68)
Discontinued operations as restated................... (52) (128) 26 (120)
Consolidated net income (loss) as reported............ 42 (74) 37 (625)
Consolidated net income (loss) as restated............ 51 (94) 26 (633)
Basic earnings (loss) per average common share as
reported............................................ 0.32 (0.55) 0.26 (4.34)
Basic earnings (loss) per average common share as
restated............................................ 0.38 (0.69) 0.18 (4.40)
Diluted earnings (loss) per average common share as
reported............................................ 0.32 (0.55) 0.26 (4.34)
Diluted earnings (loss) per average common share as
restated............................................ 0.38 (0.69) 0.18 (4.40)
The table below summarizes the significant adjustments and the effect on
consolidated net income (loss) by quarter.
2003 2002
-------------------------- -----------------------------------
QUARTERS ENDED MAR. 31 JUNE 30 SEPT. 30 MAR. 31 JUNE 30 SEPT. 30 DEC. 31
------------------------------------ ------- ------- -------- ------- ------- -------- -------
IN MILLIONS
Consolidated net income (loss) as
reported.......................... $ 79 $ (45) $ (77) $ 42 $ (74) $ 37 $ (625)
Discontinued operations reclass(a).. -- -- -- (1) (1) (1) --
Derivative accounting changes(b).... 3 (6) 8 10 (19) (10) (8)
Panhandle sale adjustment(c)........ -- (14) -- -- -- -- --
----- ----- ----- ----- ----- ----- ------
Consolidated net income (loss) as
restated.......................... $ 82 $ (65) $ (69) $ 51 $ (94) $ 26 $ (633)
===== ===== ===== ===== ===== ===== ======
(a) We continue to pursue the sale of International Energy Distribution, which
includes CPEE and SENECA, but due to the slow progress on the sale, we
have reclassified this entity from discontinued operations to continuing
operations for the years 2003, 2002, and 2001. When we initially reported
the international energy distribution business as a discontinued operation
in 2001, we applied APB Opinion No. 30, which allowed us to record a
provision for anticipated closing costs and operating losses. We currently
apply FASB No. 144 which does not allow us to record a provision for
future operating losses. Therefore, in the process of reclassifying the
international energy distribution business to continuing operations and
reversing such provisions, we increased our net loss by $3 million in 2002
and decreased our net loss by $3 million in 2001. In 2003, there was an
increase to net income of $75 million as a result of reversing the
previously recognized impairment loss in discontinued operations.
(b) We determined that certain equity method investees inappropriately
accounted for interest rate swaps as hedges. For additional details, see
Note 18, Restatement and Reclassification.
(c) We determined the net loss recorded in the second quarter of 2003 relating
to the sale of Panhandle, reflected as Discontinued Operations, was
understated by approximately $14 million, net of tax. The understatement
occurred because we did not recognize through our second quarter 2003
earnings an unrealized loss related to certain Panhandle interest rate
hedging derivative instruments. Pursuant to SFAS No. 133, the unrealized
loss was accounted for in Other Comprehensive Income, but needed to be
recognized through earnings upon the sale of Panhandle.
F-125
(This page intentionally left blank)
F-126
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders CMS Energy Corporation
We have audited the accompanying consolidated balance sheets of CMS Energy
Corporation (a Michigan corporation) and subsidiaries as of December 31, 2003
and 2002, and the related consolidated statements of income (loss), common
stockholders' equity and cash flows for each of three years in the period ended
December 31, 2003. Our audits also included the financial statement schedule
listed in the Index at Item 15(a)(2). These financial statements and schedule
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and schedule based on our
audits. The financial statements of Midland Cogeneration Venture Limited
Partnership and Jorf Lasfar Energy Company S.C.A., which represent investments
accounted for under the equity method of accounting, have been audited by other
auditors (the other auditors for 2001 for Midland Cogeneration Venture Limited
Partnership have ceased operations) whose reports have been furnished to us;
insofar as our opinion on the consolidated financial statements relates to the
amounts included for Midland Cogeneration Venture Limited Partnership and Jorf
Lasfar Energy Company S.C.A., respectively, it is based solely on their reports.
We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States) generally accepted in the
United States. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits and the reports of other auditors
provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of other auditors, the
consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of CMS Energy Corporation
and subsidiaries at December 31, 2003 and 2002, and the consolidated results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2003 in conformity with U.S. generally accepted accounting
principles. Also, in our opinion, the related financial statement schedule, when
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
As discussed in Notes 16 and 17 to the consolidated financial statements,
in 2003, the Company adopted the provisions of Statement of Financial Accounting
Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations", EITF
Issue No. 02-03, "Recognition and Reporting of Gains and Losses on Energy
Trading Contracts" and of Financial Accounting Standards Board Interpretation
No. 46, "Consolidation of Variable Interest Entities". As discussed in Notes 3,
9 and 15 to the consolidated financial statements, in 2002, the Company adopted
the provisions of SFAS No. 142, "Goodwill and Other Intangibles", SFAS No. 148,
"Accounting for Stock-Based Compensation" and Midland Cogeneration Venture
Limited Partnership adopted the provisions of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities", as amended and interpreted.
As discussed in Note 18 to the consolidated financial statements, the
Company restated its 2002 and 2001 financial statements.
/s/ERNST & YOUNG LLP
Detroit, Michigan
February 27, 2004
F-127
REPORT OF INDEPENDENT AUDITORS
We have audited the accompanying balance sheets of Jorf Lasfar Energy
Company S.C.A (the "COMPANY") as of December 31, 2003, 2002 and 2001, and the
related statements of income, of stockholders' equity and of cash flows for the
years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statements presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Jorf Lasfar Energy Company
S.C.A at December 31, 2003, 2002 and 2001, and the results of its operations and
its cash flows for the years then ended, in conformity with accounting
principles generally accepted in the United States of America.
/s/Price Waterhouse
Casablanca, Morocco,
February 10, 2004
F-128
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners and the Management Committee of
Midland Cogeneration Venture Limited Partnership:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, partners' equity and cash flows present
fairly, in all material respects, the financial position of the Midland
Cogeneration Limited Partnership (a Michigan limited partnership) and its
subsidiaries (MCV) at December 31, 2003 and 2002, and the results of their
operations and their cash flows for the each of the two years ended December 31,
2003 and 2002 in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
MCV's management. Our responsibility is to express an opinion on these financial
statements based on our audit. We conducted our audits of these statements in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. The financial statements of
MCV for the year ended December 31, 2001, were audited by other independent
accountants who have ceased operations. Those independent accountants expressed
an unqualified opinion on those financial statements in their report dated
January 18, 2002.
As explained in Note 2 to the financial statements, effective April 1, 2002,
Midland Cogeneration Venture Limited Partnership changed its method of
accounting for derivative and hedging activities in accordance with Derivative
Implementation Group ("DIG") Issue C-16.
/S/ PricewaterhouseCoopers LLP
Detroit, Michigan
February 18, 2004
F-129
THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED
ARTHUR ANDERSEN REPORT AND THIS REPORT HAS NOT BEEN
REISSUED BY ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners and the Management Committee of the Midland Cogeneration Venture
Limited Partnership:
We have audited the accompanying consolidated balance sheets of the
MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP (a Michigan limited
partnership) and subsidiaries (MCV) as of December 31, 2001 and 2000, and the
related consolidated statements of operations, partners' equity and cash flows
for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of MCV's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of the Midland
Cogeneration Venture Limited Partnership and subsidiaries as of December 31,
2001 and 2000, and the consolidated results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States.
As explained in Note 2 to the financial statements, effective January 1,
2001, Midland Cogeneration Venture Limited Partnership changed its method of
accounting related to derivatives and hedging activities.
/s/Arthur Andersen LLP
Detroit, Michigan,
January 18, 2002
F-130
Jorf Lasfar Energy Company S.C.A
JLEC
CENTRALE THERMIQUE DE JORF LASFAR
B P 99 SIDI BOUZID
EL JADIDA
MOROCCO
Tel : 212 23 34 53 71
Fax : 212 23 34 54 05
US GAAP
FINANCIAL STATEMENTS
AS OF
DECEMBER 31, 2003, 2002 AND 2001
AUDITED
R.C. n(degree)86655 - Patente n(degree)35511273 - Identification Fiscale
(I.S TVA) n(degree)1021595
F-131
JORF LASFAR ENERGY COMPANY
INDEX TO FINANCIAL STATEMENTS
PAGE(S)
Balance Sheet
As of December 31, 2003, 2002, and 2001............
Statement of Income
For year ending December 31, 2003, 2002, and 2001..
Statement of Stockholders' Equity
For year ending December 31, 2003, 2002, and 2001..
Statement of Cash Flows
For year ending December 31, 2003, 2002, and 2001..
Notes to US GAAP Financial Statements..........................
F-132
REPORT OF INDEPENDENT AUDITORS
We have audited the accompanying balance sheets of Jorf Lasfar Energy
Company S.C.A (the "COMPANY") as of December 31, 2003, 2002 and 2001, and the
related statements of income, of stockholders' equity and of cash flows for the
years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statements presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Jorf Lasfar Energy Company
S.C.A at December 31, 2003, 2002 and 2001, and the results of its operations and
its cash flows for the years then ended, in conformity with accounting
principles generally accepted in the United States of America.
Price Waterhouse
Casablanca, Morocco,
February 10, 2004
F-133
JORF LASFAR ENERGY COMPANY
BALANCE SHEET
NOTE DECEMBER 31, 2003 DECEMBER 31, 2002 DECEMBER 31, 2001
---------- ------------------ ------------------ ------------------
(000) U.S. DOLLARS (000) U.S. DOLLARS (000) U.S. DOLLARS
ASSETS
Current Assets
Cash............................................ 3.1 65,611 46,683 67,106
Inventories..................................... 2.c & 4 38,548 40,615 31,759
Account Receivable.............................. 5 85,486 76,175 86,515
Prepayments..................................... 6 8,138 10,431 4,477
Net investment from $ DFL model................. 2.b & 17.3 38,461 20,206 56,061
Net investment from Euro DFL model.............. 2.b & 17.3 40,942 31,298 21,301
Other........................................... 0 0 0
--------- --------- ---------
Total current assets..................... 277,186 225,408 267,219
Long Term Assets, net
Restricted Cash................................. 3.2 83,049 53,778 17,140
Fixed Assets.................................... 7 9,603 6,554 6,284
Net investment from $ DFL model................. 2.b & 17.3 638,004 678,549 686,660
Net investment from Euro DFL model.............. 2.b & 17.3 411,100 374,509 339,492
$ Capacity Charges less than $ DFL model........ 13.1 713 0 9,907
Euro Capacity Charges less than Euro DFL model.. 13.2 0 0 4,225
Other Long Term Assets.......................... 9 19,058 10,968 9,445
--------- --------- ---------
Total Long Term Assets................... 1,161,527 1,124,357 1,073,153
--------- --------- ---------
Total assets............................. 1,438,713 1,349,765 1,340,372
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable to third parties............... 10 47,851 25,498 34,764
Accounts payable to related parties............. 11 176,693 145,065 74,704
VAT Liability.................................. 8 3,972 2,871 3,078
Taxes payable................................... 12 7,527 4,866 873
Current part of Long-term loans in US Dollars... 15 25,749 25,749 24,873
Current part of Long-term loans in Euro......... 15 44,491 36,855 31,167
Other current liabilities....................... 14 7,739 7,955 18,607
--------- --------- ---------
Total current liabilities................ 314,023 248,859 188,066
Non-Current Liabilities
Long-term loans in US Dollars................... 15 212,426 238,174 251,667
Long-term loans in Euro......................... 15 367,052 340,912 319,457
$ Capacity Charges greater than $ DFL model..... 13.1 0 2,441 0
Euro Capacity Charges greater than Euro DFL
model......................................... 13.2 422 236 0
Deferred Tax Liability.......................... 2.f 0 13,005 6,097
Derivative Instrument Liability................. 20 22,050 21,410 10,665
Unfunded Pension Obligations.................... 19.1 9,878 5,693 0
--------- --------- ---------
Total non-current liabilities............ 611,828 621,872 587,886
Commitment and Contingencies........................ 22
Stockholders' Equity
Common Stock.................................... 16.1 58 58 58
Convertible Stockholders' Securities............ 16.2 201,425 201,425 201,425
Preferred Stock................................. 16.3 185,930 185,930 185,930
Retained Earnings............................... 16.4 147,499 113,031 187,672
Other Comprehensive Income or (Loss)............ 20 (22,050) (21,410) (10,665)
--------- --------- ---------
Total stockholders' equity............... 512,862 479,033 564,420
--------- --------- ---------
Total liabilities and stockholders'
equity................................. 1,438,713 1,349,765 1,340,372
The accompanying Notes 1 to 23 are an integral part of these financial
statements.
F-134
JORF LASFAR ENERGY COMPANY
STATEMENT OF INCOME
JANUARY 1, 2003 JANUARY 1, 2002 JANUARY 1, 2001
TO TO TO
NOTE DECEMBER 31, 2003 DECEMBER 31, 2002 DECEMBER 31, 2001
--------- ------------------ ------------------ ------------------
(000) U.S. DOLLARS (000) U.S. DOLLARS (000) U.S. DOLLARS
REVENUE
Lease Revenue from $ DFL model............ 2.b 17.2 81,793 88,464 100,679
Lease Revenue from Euro DFL model......... 2.b 17.2 104,635 95,078 94,545
Energy Payments........................... 128,981 130,446 116,709
O&M Revenue............................... 45,066 42,930 38,809
Supplemental Capacity Charges............. 3,949 4,017 3,887
Sale of Fly Ash........................... 214 247 303
License Tax Reimbursement................. 4,102 0 0
Others.................................... 138 3,090 2,364
------- ------- -------
TOTAL REVENUE 368,878 364,272 357,296
OPERATING EXPENSES
Coal Cost................................. 129,935 126,957 115,066
Fuel Oil Cost............................. 1,280 910 754
O&M Costs................................. 33,554 25,057 20,329
Operator's Incentive...................... 2,784 3,721 2,099
Generator Costs........................... 11,994 11,397 12,547
License Tax Costs......................... 4,102 0 0
Amortization of Major Maintenance......... 9.1 1,935 1,128 261
Depreciation of Other Assets.............. 2,093 1,624 470
Provision For Future Pension Obligations.. 2,902 5,427 0
------- ------- -------
TOTAL OPERATING EXPENSES 190,580 176,222 151,525
OPERATING INCOME................................ 178,299 188,050 205,771
FINANCIAL ITEMS
Financial Income.......................... 2,025 1,764 4,735
Exchange Gain (+) or Loss (-)............. 2.d (8,605) (1,558) 8,197
Financial Expenses........................ 18 (49,425) (44,834) (50,617)
------- ------- -------
TOTAL FINANCIAL ITEMS (56,005) (44,628) (37,685)
INCOME BEFORE TAXES 122,293 143,422 168,086
Income Taxes
Current............................ 2.e 15,448 4,226 603
Deferred........................... 2.f (13,005) 6,908 6,097
------- ------- -------
NET INCOME 16.4 & 21 119,850 132,288 161,386
The accompanying Notes 1 to 23 are an integral part of these financial
statements.
F-135
JORF LASFAR ENERGY COMPANY
STATEMENT OF STOCKHOLDERS' EQUITY
JANUARY 1, 2003 JANUARY 1, 2002 JANUARY 1, 2001
TO TO TO
NOTE DECEMBER 31, 2003 DECEMBER 31, 2002 DECEMBER 31, 2001
---- ----------------- ------------------ -----------------
(000) U.S. Dollars
--------------------------------------------------------
COMMON STOCK
At beginning and end of period in number of shares 16.1 5,500 5,500 5,500
At beginning and end of period in thousands of USD 16.1 58 58 58
CONVERTIBLE STOCKHOLDERS' SECURITIES
At beginning of period 201,425 201,425 387,355
Conversion of Convertible Stockholders' Securities
to Preferred Stock 0 0 (185,930)
Conversion of Convertible Stockholders' Securities
to Common Stock 0 0 0
------- -------- --------
At end of period 16.2 201,425 201,425 201,425
PREFERRED STOCK
At beginning of period 185,930 185,930 0
Conversion of Convertible Stockholders' Securities
to Preferred Stock 0 0 185,930
Conversion of Preferred Stock to Common Stock 0 0 0
------- -------- --------
At end of period 16.3 185,930 185,930 185,930
RETAINED EARNINGS (DEFICIT)
At beginning of period 113,031 187,672 296,409
Net income 119,850 132,288 161,386
Common stock dividend (64,973) (184,891) (270,123)
Preferred stock dividend (9,796) (9,942) 0
Convertible stockholders' securities (10,613) (12,096) 0
------- -------- --------
At end of period 16.4 147,499 113,031 187,672
OTHER COMPREHENSIVE INCOME (LOSS) (A)
Derivative Instruments
At beginning of period (21,410) (10,665) 0
Reclassification of gains (losses) included in net
income 6,871 5,811 699
Unrealized gain (loss) on derivative instruments (7,511) (16,556) (11,364)
------- -------- --------
At end of period 20 (22,050) (21,410) (10,665)
------- -------- --------
512,862 479,034 564,420
======= ======== ========
(a) Disclosure of Comprehensive Income (Loss)
Net income 119,850 132,288 161,386
Derivative instruments
Reclassification of gains (losses) in net income 6,871 5,811 699
Unrealized gain (loss) on derivative instruments (7,511) (16,556) (11,364)
------- -------- --------
Total Comprehensive Income 119,211 121,543 150,721
======= ======== ========
The accompanying Notes 1 to 23 are an integral part of these financial
statements.
F-136
JORF LASFAR ENERGY COMPANY
STATEMENT OF CASH FLOWS
JANUARY 1, 2003 JANUARY 1, 2002 JANUARY 1, 2001
TO TO TO
DECEMBER 31, 2003 DECEMBER 31, 2002 DECEMBER 31, 2001
------------------ ------------------ ------------------
NOTE (000) U.S. DOLLARS (000) U.S. DOLLARS (000) U.S. DOLLARS
----- ------------------ ------------------ ------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Payments received from ONE........................ $ 426,250 $ 471,044 $ 411,872
Interest received................................. 1,870 1,748 4,543
Insurance Payments................................ (5,699) (5,665) (7,104)
Payments of Operating Costs....................... (233,068) (249,255) (228,771)
Cash Effect of Value Added Tax.................... 2,463 (321) 4,430
------------ ------------ ------------
Net cash provided by operating activities.. 21 191,816 217,551 184,970
CASH FLOWS USED FOR INVESTING ACTIVITIES
Net (increase) in restricted cash................. (25,942) (36,638) (17,140)
Acquisition of fixed assets....................... (2,300) (3,957) (5,501)
Payment of Major Maintenance costs................ (6,261) (93) (21,504)
------------ ------------ ------------
Net cash used in investing activities...... (34,503) (40,688) (44,145)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from loans............................... 0 0 92,589
Proceeds of share capital payments................ 0 0 0
Repayment of loans................................ (65,639) (57,964) (41,961)
Payment of Convertible Securities interest........ (11,417) (12,386) 0
Payment of Preferred Stock dividend............... (10,539) (10,181) 0
Payment of Common Stock dividend.................. (54,877) (121,933) (189,600)
Repayment of Stockholders loans................... 0 0 0
Purchase of Preferred Stock shares................ 0 0 0
Purchase of Common Stock shares................... 0 0 0
------------ ------------ ------------
Net cash provided by financing activities.. (142,472) (202,464) (138,972)
Effect of exchange rate changes on cash........... 4,087 5,178 (1,950)
CASH AT BEGINNING OF PERIOD.............................. 46,683 67,106 67,203
NET INCREASE (DECREASE) IN CASH DURING PERIOD............ 18,928 (20,422) (97)
------------ ------------ ------------
CASH AT END OF PERIOD.................................... 3.1 $ 65,611 $ 46,683 $ 67,106
============ ============ ============
SUPPLEMENTAL CASH FLOWS INFORMATION
Cash paid during the year-
Interest 49,136 56,054 45,486
Income taxes 12,826 5,150 6,173
The accompanying Notes 1 to 23 are an integral part of these financial
statements.
F-137
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
1. GENERAL
A. BACKGROUND
The power station at Jorf Lasfar is located on the Atlantic coast of
Morocco, adjacent to the Port of Jorf Lasfar, in the Province of El Jadida. This
location is approximately 127 km south--west of Casablanca. Units 1 and 2 of the
power station were constructed by GEC Alstom for the Moroccan Electricity
Company, Office National de l'Electricite ("ONE"), and are now in commercial
operation. Each of these existing Units is 330 MW, fired by coal. In October of
1994, the ONE issued a public tender for international companies to expand the
power station at Jorf Lasfar. In February of 1995, the ONE selected the
"Consortium" of ABB Energy Ventures and CMS Generation as the preferred bidder
and exclusive partner for negotiation. In April of 1996, the Consortium and the
ONE reached agreement in principle, and initialed the necessary Project
Agreements.
B. ESTABLISHMENT
In order to officially conclude and implement these Project Agreements,
the Consortium established the Jorf Lasfar Energy Company (the "COMPANY" or
"JLEC") on January 20, 1997. The Company was established as a limited
partnership ("societe en commandite par actions") in accordance with the Laws of
the Kingdom of Morocco, with Commercial Registration Number 86655, Fiscal
Identification Number 1021595, and Patente Number 35511274. In accordance with
its charter documents, the Company's objective and purpose is to construct,
operate, manage and maintain the power station at Jorf Lasfar, including the
development, financing, engineering, design, construction, commissioning,
testing, operation and maintenance of two (2) new coal-fired Units, which are
very similar in size and technology to the existing Units. In order to secure
its fuel supply the Company also operates and maintains the coal-unloading pier
in the Port of Jorf Lasfar. For these activities, the Company received a "right
of possession" ("droit de jouissance") for the Site, the existing Units, the new
Units and coal unloading pier. This "right of possession" will continue for the
duration of the Project Agreements, which is anticipated to be in the range from
15 to 30 years.
C. COMPANY LOAN, TRANSFER OF POSSESSION, PROJECT FINANCING AND INITIAL
DISBURSEMENT
On September 12, 1997, all Project Agreements were signed, the Company
Loan Agreement was executed and the first disbursement of the Company Loan was
used to pay the TPA fee to ONE. As a consequence, JLEC received possession of
the power station at Jorf Lasfar on September 13, 1997, and began to sell its
available capacity and net generation to ONE. All remaining requirements for
project financing were completed in November, and initial disbursement of the
Project Loans occurred on November 25, 1997.
D. CONSTRUCTION, COMMERCIAL OPERATION, PURCHASE OF COMPANY LOAN AND REPAYMENT OF
PROJECT LOANS
After a period of construction lasting 33 months and 41 months, Unit 3 and
4 began normal commercial operation on June 9, 2000, and February 2, 2001,
respectively. Consequently, the JLEC stockholders purchased 100% of the Company
Loan Notes on December 11, 2000, and JLEC began the repayment of all Project
Loans on May 15, 2001. After JLEC completes the repayment of all Project Loans
(which is scheduled for February 15, 2013), ONE has the option to pay JLEC the
Termination Amount, and then terminate all Project Agreements and retake
possession of the Site and power station at Jorf Lasfar.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. BASIS OF PREPARATION OF FINANCIAL STATEMENTS
The Company's financial statements are prepared using the historical cost
convention. The accounting and reporting policies of the Company are in
accordance with the generally accepted accounting principles of Morocco, which
are called "Code General de Normalisation Comptable" or "CGNC". Financial
statements are prepared in accordance with these CGNC standards, and expressed
in Dirhams. In addition to and separately from Moroccan (CGNC) financial
statements in Dirhams, the Company uses the U.S Dollar as functional currency,
and has prepared these financial statements in accordance with generally
accepted accounting principles of the United States.
F-138
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
B. REVENUE RECOGNITION
On September 12, 1997, the Company and the Office National de
L'Electricite executed a set of contracts related to the power station at Jorf
Lasfar. In accordance with Statement of Financial Accounting Standard (SFAS) No.
13, these contracts are accounted for as a direct financing lease. Accordingly,
JLEC (the "LESSOR") will receive a stream of payments from ONE (the "LESSEE")
over the term of the lease. The term of the lease is determined in accordance
with SFAS No. 13 Section (5)(f) which has been superseded by SFAS No. 98 Section
22(a). The following policies are used to calculate the minimum lease payments
and the unearned income from the lease.
MINIMUM LEASE PAYMENTS are determined in accordance with SFAS No. 13
Section 5(j), and are based on the capacity payments that ONE will take to
JLEC. These minimum lease payments do not include reimbursable or
executory costs such as the reimbursement of coal costs. The sum of these
capacity payments equal the gross investment under the lease.
This gross investment minus the net investment in the plants is defined to
be the UNEARNED INTEREST INCOME. This unearned interest income will be
accreted and recognized into earnings as LEASE REVENUE over the lease term
using the effective interest method so as to produce a constant periodic
rate of return on the net investment.
The NET INVESTMENT represents the cost of acquiring and constructing the
leased assets. These ACQUISITION AND CONSTRUCTION COSTS include the
following items which are capitalized and allocated to Units 1 and 2 and
Units 3 and 4 based upon appropriate allocation methodologies:
TRANSFER OF POSSESSION AGREEMENT (TPA): The TPA payment is included
in the cost basis of the leased assets.
DIRECT CONSTRUCTION COSTS: All direct costs related to construction
are included in the cost basis of the leased assets.
CAPITALIZED COSTS: Interest and financing costs incurred during
construction are capitalized and included in the cost of the
constructed units.
PROJECT DEVELOPMENT COSTS AND FEES: These costs and fees are also
capitalized and included in the cost basis of the leased assets.
FINANCING COSTS: Interest expense is recognized on the effective interest
method over the life of the debt. Other financing costs such as commitment
fees, guarantee fees, etc. are considered a component of the interest
expense of the related debt or financing. As such, they are amortized into
expense using the effective interest method over the life of the related
debt or financing.
C. INVENTORIES
The Company accounts for inventories by consistently applying the FIFO or
average cost method to each item, and uses the conservatism principle (lesser of
market value or cost) in its procedures for valuing inventories.
D. FOREIGN CURRENCY TRANSACTIONS
The books and records of the Company for U.S. GAAP are maintained in U.S.
Dollars, which is both the reporting and functional currency. Transactions in
other currencies are translated to U.S. Dollars at the spot rate for current
period expenses and at the settlement rate for non-period transactions. Monetary
assets and monetary liabilities outstanding in other foreign currencies on
balance sheet dates are translated into U.S. Dollars at rates prevailing on such
balance sheet dates. Exchange gains and losses on those foreign currency
operations are included in determining net income for the period in which
exchange rates change.
F-139
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
E. CORPORATE TAX
Current Income tax is determined under Moroccan Income tax rules. In 1997,
JLEC signed a "tax incentive" convention with the Moroccan tax authorities. The
main principles of this convention are summarized below:
- Income is subject to corporate tax and "Produit de Solidarite
National" tax (PSN)
- PSN tax rate is 8.75% and is not subject of any tax holiday
- Income tax holiday period is ten years
- Income tax holiday period starts on the "commercial operation date"
for each unit
- Income tax holiday is 100% during the first five-year period then at
50% of the income tax rate during the second five-year period
- Income not related to the sale of electricity is subject to a tax
rate of 35%
The "commercial operation date" for Units 1 and 2, Unit 3 and Unit 4 were
September 1997, June 2000 and February 2001, respectively. On September 13,
2002, income related to Units 1 and 2 became taxable at 17.5%. Unit 3 and Unit 4
are still in the 100% tax holiday period. The PSN tax was eliminated on January
1, 2001.
F. DEFERRED INCOME TAX
Starting September 13, 2002, JLEC tax rate on Units 1&2 is 17.5%. JLEC
determines and books the current income tax (US$ 15,448,426 for 2003 ) as
required by the tax laws and regulations of Morocco. Temporary differences
between the US GAAP and the CGNC balance sheets are creating the need to record
deferred income taxes. The main temporary differences result from the use of the
Direct Financing Lease method under US GAAP. In particular, the treatment of Net
Investment and revenue recognition (as disclosed in note 2.b above) under US
GAAP are quite different from the treatment of these items under Moroccan GAAP .
The total of all the deferred tax liabilities is $ 0 ($13,005,298 as of December
31, 2002 minus $13,005,298 for 2003).
G. OFF BALANCE SHEET COMMITMENTS
The Company discloses all off-balance sheet commitments, if any, on
balance sheet dates.
H. USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenue and
expenses during the reported period. Actual result could differ from these
estimates and assumptions.
3. CASH
3.1 CASH
The Company's cash as of December 31, 2003, includes the initial capital
deposits of the Company's stockholders, as explained further in Note 16.1 . Such
cash is held in Moroccan Dirhams in accounts at CITIBANK MAGHREB, which is
located at Zenith Millenium Immeuble 1, Lotissement Attaoufik, Sidi Maarouf,
Casablanca Morocco. The remainder of the company's cash is held by the Offshore
Collateral Agent, Deutsche Bank Trust Company Americas in US$ and Euro, and by
the Onshore Collateral Agent, BMCI - Banque Marocaine pour le Commerce et
l'Industrie in Morocain Dirhams and US$.
F-140
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
The cash balances includes the following categories:
12/31/03 12/31/02 12/31/01
US$ US$ US$
----------- ----------- ----------
Off-shore Revenue in US$ 24,426,875 22,666,875 36,223,422
Off-shore Revenue in Euro 6,590,224 5,331,124 5,000,414
----------- ----------- ----------
Total Off-Shore Revenue 31,017,099 27,997,998 41,223,836
On-shore O&M Account - Generator 6,946,245 793,293 2,899,102
On-shore O&M Account - Operator 4,279,000 3,258,836 2,298,642
Off-shore O&M Accounts 4,546 10,607 8,464
----------- ----------- ----------
Total O&M Accounts 11,229,792 4,062,735 5,206,208
Fuel & Spare Part Accounts 12,929,694 5,289,381 12,080,028
On-shore Construction Accounts 0 0 1,100,363
Off-shore Debt Service Accrual Accounts in US$ 3,734,278 3,843,187 3,540,479
Off-shore Debt Service Accrual Accounts in Euro 6,637,737 5,433,301 3,898,143
----------- ----------- ----------
Total Debt Service Accrual Accounts 10,372,015 9,276,488 7,438,623
Stockholder capital deposits 62,863 56,624 56,624
----------- ----------- ----------
Total 65,611,462 46,683,227 67,105,682
=========== =========== ==========
3.2 Restricted Cash
The Reserve Accounts are as follow:
Major Maintenance Reserve Account in US$ 3.4 a 2,500,000 2,500,000 5,000,000
Fixed O&M Reserve Account in US$ 3.4 b 4,800,000 4,800,000 9,600,000
Debt Service Reserve Account in US$ 3.4 c 11,200,000 11,730,000 730,000
Super Reserve Account in US$ 3.4 d 45,600,000 18,100,000 0
Distribution Account in US$ 0 0 0
----------- ----------- ----------
Off-shore Reserve Accounts in US$ 64,100,000 37,130,000 15,330,000
Fixed O&M Reserve Account in Euro 243,656 197,262 161,372
Debt Service Reserve Account in Euro 3.4 e 18,705,220 16,450,805 1,649,031
----------- ----------- ----------
Off-shore Reserve Accounts in Euro 18,948,876 16,648,067 1,810,404
----------- ----------- ----------
Total Reserve Accounts 83,048,876 53,778,067 17,140,404
=========== =========== ==========
3.3 Total Cash
Cash 3.1 65,611,462 46,683,227 67,105,682
Restricted Cash in Reserve Accounts 3.2 83,048,876 53,778,067 17,140,404
----------- ----------- ----------
148,660,339 100,461,294 84,246,086
=========== =========== ==========
3.4 LETTERS OF CREDIT
Additional liquidity is available, if needed for debt service, from Sponsor
(CMS and ABB) Letters of Credit in the following accounts:
12/31/03 12/31/02 12/31/01
---------- ---------- ----------
a. Major Maintenance Reserve Account US$ 2,500,000 2,500,000 0
b. Fixed O&M Reserve Account US$ 4,800,000 4,800,000 0
c. Debt Service Reserve Account US$ 11,300,000 11,300,000 22,600,000
d. Super Reserve Account US$ 39,086,700 47,900,000 36,800,000
e. Debt Service Reserve Account Euro 15,000,000 15,000,000 30,000,000
4. INVENTORIES
The inventories are detailed as follows for the year ending:
12/31/03 12/31/02 12/31/01
US$ US$ US$
---------- ---------- ----------
Stock of Coal 4.1 24,763,321 22,499,748 23,305,684
Stock of Fuel-oil 4.2 1,638,256 2,078,600 2,988,752
Stock of Spare Parts 4.3 10,940,862 15,081,606 4,952,377
Other Stocks (Chemicals, Oils, ...) 1,205,566 954,692 512,445
---------- ---------- ----------
38,548,005 40,614,646 31,759,259
========== ========== ==========
F-141
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
4.1 The stock of coal represents the value of 397,745 tones existing in the coal
storage area plus 184,318 tones in transit to Jorf Lasfar, for a total
inventory of 582,063 tones as of December 31, 2003 (606,115 tones total as
of December 31, 2002 and 643,042 tones total as of December 31, 2001).
4.2 The stock of fuel oil represents 9,471 m3 existing in the fuel tanks as of
December 31, 2003 (12,300 m3 as of December 31, 2002).
4.3 The stock of Spare Parts represents the value of spare parts as of
December 31, 2003, that were purchased after the close-out of the Net
Investment on December 31, 2000. ($ 15,081,606 as of December 31, 2002).
5. RECEIVABLES
The "Accounts Receivables" as of December 31, 2003 are detailed as follows:
12/31/03 12/31/02 12/31/01
US$ US$ US$
---------- ---------- ----------
Account Receivable - ONE 5.1 85,214,510 76,098,673 85,811,099
Account Receivable - Others 5.2 271,345 76,097 704,024
---------- ---------- ----------
85,485,855 76,174,769 86,515,123
========== ========== ==========
5.1 The account receivable - ONE includes November 2003 and December 2003
invoices The account receivable balance as of December 31, 2002 was US$
76,098,673 (Nov. and Dec. Invoices).
5.2 The other receivables include a) invoices to Valcen Gie (association of
Moroccan cement companies) for purchases of fly ash during 4Q 2003 (US$
71,101), b) accrued interest earned by investment of JLEC's cash balances
($ 67,425), and c) other receivable (US$ 132,819).
6. PREPAYMENTS
The "Prepayments" as of December 31, 2003 are detailed as follows:
12/31/03 12/31/02 12/31/01
US$ US$ US$
--------- ---------- ---------
Prepaid Insurance 3,599,349 3,582,404 3,822,746
Prepayments for Income Tax 3,929,580 5,194,869 0
Other Prepayments 609,277 1,653,537 653,896
--------- ---------- ---------
8,138,206 10,430,810 4,476,641
========= ========== =========
7. FIXED ASSETS
The "Fixed Assets" are detailed as follows for year ending:
12/31/03 12/31/02 12/31/01
US$ US$ US$
---------- ---------- ---------
Fixed Asset - Gross 11,694,954 7,455,511 5,314,528
Depreciation -2,516,437 -1,884,137 -260,099
Construction in Progress 424,902 982,455 1,229,571
---------- ---------- ---------
9,603,420 6,553,829 6,284,000
========== ========== =========
8. V.A.T LIABILITY
The "V.A.T Liability" account represents the net amount of Value Added Tax
as shown below:
12/31/03 12/31/02 12/31/01
US$ US$ US$
---------- ---------- ----------
Value Added Tax received from ONE to be declared 5,179,969 4,805,614 8,415,330
Value Added Tax to be paid & declared -1,207,918 -1,934,168 -5,337,662
---------- ---------- ----------
3,972,052 2,871,446 3,077,668
========== ========== ==========
F-142
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
9. OTHER LONG TERM ASSETS
The Other Long Term Assets are as follows:
12/31/03 12/31/02 12/31/01
US$ US$ US$
---------- ---------- ---------
Long Term Receivables Loan 3,372,930 2,754,540 2,016,161
Long Term Ash Disposal Site 1,389,307 1,913,308 0
Major Maintenance capitalized during 2001 Unit 1 turbine overhaul outage 7,898,850 7,898,850 7,898,850
Less: Amortization of Unit 1 Major Maintenance in 2001 and 2002 -1,598,577 -470,170 -470,170
9.1 Less: Amortization of Unit 1 Major Maintenance in 2003 -1,036,582 -1,128,407 0
Less: Adjustments due to changes in methodes -599,070 0 0
Major Maintenance capitalized during 2003 - Unit 2 turbine overhaul outage 10,529,148 0 0
9.1 Less: Amortization of Unit 2 Major Maintenance in 2003 -898,320 0 0
---------- ---------- ---------
19,057,685 10,968,120 9,444,841
========== ========== =========
9.1 Capitalized major maintenance costs are amortized over the estimated useful
life of the investment, which for the turbine overhauls is 7 years (84
months).
10. ACCOUNTS PAYABLE TO THIRD PARTIES
The "Account Payable to Third Parties" includes the main suppliers of JLEC
as of December 31, 2003 and are detailed as follows:
12/31/03 12/31/02 12/31/01
US$ US$ US$
---------- ---------- ----------
Billiton (coal supplier) 2,800,790 4,119,817 16,060,510
Anglo (coal supplier) 6,320,391 2,245,218 5,281,412
RAG Trading (coal supplier) 0 4,499,958 0
Glencore (coal supplier) 20,030,571 2,187,744 0
BULK (coal supplier) 4,470,349 0 0
Total (coal supplier) 0 0 2,267,178
Alstom Power 1,507,931 2,845,357 2,607,834
ONE - Rebate 4,139,908 2,767,010 3,547,774
Other suppliers 8,581,419 6,832,615 4,999,250
---------- ---------- ----------
Total 47,851,359 25,497,718 34,763,957
========== ========== ==========
11. RELATED PARTY TRANSACTIONS
During the year 2003, JLEC has booked a number of related parties
transactions as follows:
ABB ABB CMS CMS CMS TOTAL
EV MAROC MOPCO MOPCO RD & GEN
US$ MAD MAD MAD US$ US$
CURRENCIES
Acc. Payable 12/31/02 105,764 125,880 -1,452,394 46,253,345 82,686
2003:
Management Fees 32,938,795
Incentive Accrual 29,320,319
Other 214,644 237,916 3,582,315
Total Payments 2003 230,400 363,796 30,311,126 46,253,688 82,686
Acc. Payable 90,007 0 4,757,590 29,319,976 0
Acc. Pay. in US$ 90,007 0 542,101 3,340,851 0 3,972,960
F-143
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
11. RELATED PARTY TRANSACTIONS (CONTINUED)
JORF LASFAR JORF LASFAR TRE KRONOR
ENERGIAKTIE- POWER ENERGY JORF LASFAR INVESTMENT
BOLAG AB HANDELSBOLAG AB AB CYTHERE 61 AB CYTHERE 63 TOTAL
COMMON STOCK MAD MAD MAD MAD MAD MAD MAD
CURRENCIES
Acc. Payable 12/31/02 220,166,565 202,553,239 17,613,325 39,682,115 2,164,464 950,199,532 1,432,379,240
Dividend Payable 10/30/03 151,250,000 139,150,000 12,100,000 12,100,000 660,000 289,740,000 605,000,000
Total Payments 2003 156,487,853 143,968,825 12,519,028 8,343,124 455,079 199,779,902 521,553,812
Acc. Payable 214,928,711 197,734,415 17,194,297 43,438,991 2,369,384 1,040,159,631 1,515,825,428
B/S FX Rate MAD/USD 8.776 8.776 8.776 8.776 8.776 8.776 8.776
Acc. Pay. in US$ 24,489,951 22,530,755 1,959,196 4,949,635 269,978 118,520,502 172,720,019
JORF LASFAR JORF LASFAR TRE KRONOR
PREFERRED STOCK & CONVERTIBLE ENERGIAKTIE- POWER ENERGY JORF LASFAR INVESTMENT AB AB
SECURITIES BOLAG AB HANDELSBOLAG AB CYTHERE 61 CYTHERE 63 TOTAL
MAD MAD MAD MAD MAD MAD MAD
CURRENCIES
Preferred Stock Dividend payable 0 0 0 0 226,840 99,666,957 99,893,797
Convertible Securities Interest
payable 52,028,019 47,865,778 4,162,242 4,162,242 0 0 108,218,281
Total Payments 2003 52,028,019 47,865,778 4,162,242 4,162,242 226,840 99,666,957 208,112,078
Acc. Payable 0 0 0 0 0 0 0
B/S FX Rate MAD/USD 8.776 8.776 8.776 8.776 8.776 8.776 8.776
Acc. Pay. in US$ 0 0 0 0 0 0 0
-----------
Total Accounts Payable to Related Parties 176,692,979
During 2002, related party transactions consisted of the following:
ABB ABB CMS CMS CMS
EV MAROC MOPCO MOPCO RD & GEN TOTAL
US$ MAD MAD MAD US$ US$
CURRENCIES
Acc. Payable 12/31/01 137,581 78,576 7,726,314 44,598,493 76,753
Management Fees 35,654,033
Incentive Accrual 46,253,517
Other 207,059 778,086 6,139,521 114,510
Total Payments 2002 238,876 730,782 38,693,220 44,598,665 108,577
Acc. Payable 12/31/02 105,764 125,880 1,452,394 46,253,345 82,686
Acc. Pay. in US$ 12/31/02 105,764 12,345 142,433 4,535,976 82,686 4,594,337
JORF LASFAR JORF LASFAR TRE KRONOR
ENERGIAKTIE- POWER ENERGY JORF LASFAR INVESTMENT
BOLAG AB HANDELSBOLAG AB AB CYTHERE 61 AB CYTHERE 63 TOTAL
COMMON STOCK MAD MAD MAD MAD MAD MAD MAD
CURRENCIES
Acc. Payable 12/31/01 202,826,993 186,600,834 16,226,160 16,226,160 885,063 388,542,764 811,307,973
Dividend Payable Oct 29, 2002 495,000,000 455,400,000 39,600,000 39,600,000 2,160,000 948,240,000 1,980,000,000
Total Payments 2002 477,660,429 439,447,594 38,212,834 16,144,045 880,600 386,583,232 1,358,928,734
Acc. Payable 12/31/02 220,166,565 202,553,239 17,613,325 39,682,115 2,164,464 950,199,532 1,432,379,240
B/S FX Rate MAD/USD 10.197 10.197 10.197 10.197 10.197 10.197 10.197
Acc. Pay. in US$ 12/31/02 21,591,308 19,864,003 1,727,305 3,891,548 212,265 93,184,224 140,470,652
JORF LASFAR JORF LASFAR TRE KRONOR
ENERGIAKTIE- POWER ENERGY JORF LASFAR INVESTMENT
PREFERRED STOCK & BOLAG AB HANDELSBOLAG AB AB CYTHERE 61 AB CYTHERE 63 TOTAL
CONVERTIBLE SECURITIES MAD MAD MAD MAD MAD MAD MAD
CURRENCIES
Preferred Stock
Dividend payable 0 0 0 0 261,774 115,016,078 115,277,852
Convertible Securities
Interest payable 63,882,171 58,771,597 5,110,574 5,110,574 16,749 7,359,167 140,250,832
Total Payments 2002 63,882,171 58,771,597 5,110,574 5,110,574 278,523 122,375,245 255,528,684
Acc. Payable 12/31/02 0 0 0 0 0 0 0
B/S FX Rate MAD/USD 10.197 10.197 10.197 10.197 10.197 10.197 10.197
Acc. Pay. in US$ 12/31/02 0 0 0 0 0 0 0
Total Accounts Payable to Related Parties 145,064,990
F-144
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
11. RELATED PARTY TRANSACTIONS (CONTINUED)
During 2001, related party transactions consisted of the following:
ABB ABB ABB ABB CMS CMS CMS
EV SECHERON SECHERON MAROC MOPCO MOPCO RD & GEN TOTAL
US$ DEM CHF MAD MAD MAD US$ US$
CURRENCIES
Acc. Payable 12/31/00 43,545 - - - 16,747,904 96,757,074 200,667
Management Fees 35,287,098
Incentive Accrual 44,314,093
Other 331,716 375,000 25,200 469,461 5,873,718 471,870
Total Payments 2001 237,679 375,000 25,200 390,885 38,434,970 96,472,673 595,784
Acc. Payable 12/31/01 137,581 - - 78,576 7,726,314 44,598,493 76,753
Acc. Pay. in US$ 12/31/01 137,581 - - 6,777 666,349 3,846,356 76,753 4,733,816
JORF LASFAR JORF LASFAR TRE KRONOR JORF LASFAR AB
ENERGIAKTIE- POWER ENERGY INVESTMENT HANDELS- CYTHERE
AB CYTHERE 63 BOLAG AB AB BOLAG 61 TOTAL
MAD MAD MAD MAD MAD MAD MAD
CURRENCIES
Dividend Payable Apr 24, 2001 790,200,000 412,500,000 379,500,000 33,000,000 33,000,000 1,800,000 1,650,000,000
Dividend Payable Oct 29, 2001 650,598,000 339,625,000 312,455,000 27,170,000 27,170,000 1,482,000 1,358,500,000
Total Payments 2001 1,052,255,236 549,298,007 505,354,166 43,943,841 43,943,841 2,396,937 2,197,192,027
Acc. Payable 12/31/01 388,542,764 202,826,993 186,600,834 16,226,160 16,226,160 885,063 811,307,973
B/S FX Rate MAD/USD 11.60 11.60 11.60 11.60 11.60 11.60 11.60
Acc. Pay. in US$ 12/31/01 33,509,510 17,492,626 16,093,216 1,399,410 1,399,410 76,331 69,970,502
Total Accounts Payable to Related Parties 74,704,318
12. TAXES PAYABLE:
The "taxes payable" includes the following items as of December 31, 2003:
12/31/03 12/31/02 12/31/01
US$ US$ US$
--------- --------- -------
Value Added Tax on behalf of foreign suppliers 309,190 299,199 312,044
Income Tax 2001 0 0 186,202
Income Tax 2002 0 4,226,098 0
Income Tax 2003 5,393,931 0 0
Withholding Tax 260,841 155,281 192,380
Payroll Tax 237,358 185,575 182,715
Licence Tax 1,325,971 0 0
--------- --------- -------
Total 7,527,291 4,866,153 873,340
========= ========= =======
13. CAPACITY CHARGES
13.1 $ CAPACITY CHARGES GREATER THAN $ DFL MODEL
ACTUAL DFL MODEL
$ CAPACITY MIN LEASE
CHARGES PAYMENTS DIFFERENCE
CGNC US GAAP US GAAP
USD USD USD
----------- ----------- --------
$ Capacity Charges 103,690,956 104,516,335 -825,379
$ O.N.E Rebate -2,761,910 -2,874,199 112,289
----------- ----------- --------
2003 in USD 100,929,046 101,642,136 -713,090
$ Capacity Charges greater than $ DFL Model -713,090
--------
13.2 EURO CAPACITY CHARGES GREATER THAN EURO DFL MODEL
ACTUAL DFL MODEL
EURO CAPACITY MIN LEASE
CHARGES PAYMENTS DIFFERENCE
CGNC US GAAP US GAAP
EURO EURO EURO/USD
----------- ----------- ----------
Euro Capacity Charges 125,149,979 124,917,610 232,369
Euro O.N.E Rebate -3,333,492 -3,435,234 101,742
----------- ----------- ----------
2003 in Euro 121,816,487 121,482,376 334,111
B/S FX Rate X 1.263417
----------
Euro Capacity Charges greater than Euro DFL Model in USD 422,122
F-145
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
13. CAPACITY CHARGES (CONTINUED)
13.1 $ CAPACITY CHARGES GREATER THAN $ DFL MODEL
ACTUAL DFL MODEL
$ CAPACITY MIN LEASE
CHARGES PAYMENTS DIFFERENCE
CGNC US GAAP US GAAP
USD USD USD
----------- ----------- ----------
$ Capacity Charges 152,243,461 148,653,918 3,589,543
$ O.N.E Rebate -7,466,514 -6,317,791 -1,148,723
----------- ----------- ----------
2002 in USD 144,776,947 142,336,127 2,440,820
$ Capacity Charges greater than $ DFL Model 2,440,820
----------
13.2 EURO CAPACITY CHARGES GREATER THAN EURO DFL MODEL
ACTUAL DFL MODEL
EURO CAPACITY MIN LEASE
CHARGES PAYMENTS DIFFERENCE
CGNC US GAAP US GAAP
EURO EURO EURO/USD
------------ ----------- ----------
Euro Capacity Charges 131,283,947 130,150,792 1,133,155
Euro O.N.E Rebate -6,438,591 -5,531,409 -907,183
------------ ----------- ----------
2002 in Euro 124,845,355 124,619,384 225,971
B/S FX Rate X 1.046582
----------
Euro Capacity Charges greater than Euro DFL Model in USD 236,497
13.1 $ CAPACITY CHARGES GREATER THAN $ DFL MODEL
ACTUAL DFL MODEL
$ CAPACITY MIN LEASE
CHARGES PAYMENTS DIFFERENCE
CGNC US GAAP US GAAP
USD USD USD
----------- ----------- ----------
$ Capacity Charges 167,725,226 174,863,943 -7,138,718
$ O.N.E Rebate -4,643,978 -1,876,144 -2,767,834
----------- ----------- ----------
2001 in USD 163,081,248 172,987,799 -9,906,551
$ Capacity Charges greater than $ DFL Model -9,906,551
----------
13.2 EURO CAPACITY CHARGES GREATER THAN EURO DFL MODEL
ACTUAL DFL MODEL
EURO CAPACITY MIN LEASE
CHARGES PAYMENTS DIFFERENCE
CGNC US GAAP US GAAP
EURO EURO EURO/USD
----------- ----------- ----------
Euro Capacity Charges 114,874,856 117,731,467 -2,856,611
Euro O.N.E Rebate -3,180,600 -1,263,161 -1,917,440
----------- ----------- ----------
2001 in Euro 111,694,256 116,468,307 -4,774,051
B/S FX Rate X 0.88504
---------
Euro Capacity Charges greater than Euro DFL Model in USD -4,225,210
14. OTHER CURRENT LIABILITIES
The "Other Current Liabilities" as of December 31, 2003 are detailed as
follows:
12/31/03 12/31/02 12/31/01
US$ US$ US$
----------- --------- ----------
Accrued Expenses: interest, swaps and fees 14.1 5,904,937 6,072,924 17,293,488
Accrued salaries expense 1,198,164 1,390,179 986,669
Liability for Compensated Absences 298,523 307,449 108,027
Other Liabilities 337,780 184,470 218,670
----------- --------- ----------
7,739,404 7,955,022 18,606,854
=========== ========= ==========
F-146
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
14. OTHER CURRENT LIABILITIES (CONTINUED)
14.1 The accrued interests and fee expenses are detailed by loans as
follows:
12/31/03 12/31/02 12/31/01
US$ US$ US$
--------- ---------- ----------
OPIC 728,141 807,914 907,733
SACE 1,586,760 1,522,740 1,413,325
WB 1,712,739 1,629,541 1,146,864
US EXIM - Exposure Fees 0 0 12,255,922
US EXIM 1,574,138 1,823,435 1,370,400
ERG 303,158 289,295 199,245
--------- ---------- ----------
5,904,937 6,072,924 17,293,488
========= ========== ==========
15. LONG TERM LOANS
Long term loans are detailed as follows as of December 31, 2003:
INTEREST REIMBURSEMENT
BORROWING PRINCIPAL ---------------------- INTERES --------------------------
LOAN DATE CURRENCY AMOUNT TYPE RATE PAYMENT MATURITY PERIODICITY
------------ ----------- --------- ------------ -------- --------- --------- ------------- -----------
US EXIM 9/12/02 US$ 181,363,762 Fixed 7.2000% Quarterly Feb. 15, 2013 Quarterly
OPIC Note A 11/25/97 US$ 46,635,417 Fixed 10.2300% Quarterly Feb. 15, 2013 Quarterly
OPIC Note B 02/11/98 US$ 10,175,000 Fixed 9.9200% Quarterly Feb. 15, 2013 Quarterly
-----------
56,810,417
-----------
Total L.T loan in US$ 238,174,179
-----------
Current part in USD 25,748,560
-----------
Non-Current part in USD 212,425,619
-----------
INTEREST REIMBURSEMENT
BORROWING PRINCIPAL ---------------------- INTERES --------------------------
LOAN DATE CURRENCY AMOUNT TYPE RATE PAYMENT MATURITY PERIODICITY
------------ ------------- --------- ------------ -------- --------- --------- ------------- -----------
SACE 11/17/03 Euro 179,332,929 Fixed 5.7300% Quarterly Feb. 15, 2013 Quarterly
ERG 11/17/03 Euro 23,045,939 Variable 4.16888% Quarterly Feb. 15, 2013 Quarterly
World Bank 11/17/03 Euro 123,359,818 Variable 3.9189% Quarterly Feb. 15, 2013 Quarterly
-----------
Total L.T loan in Euro 325,738,687
-----------
B/S FX Rate Euro/USD 1.26342
-----------
Total L.T loan in USD 411,543,784
-----------
Current part in USD 44,491,219
-----------
Non-Current part in USD 367,052,565
-----------
Total principal repayments for the next five years are detailed below.
Forecasts of interest payments, interest-rate swap payments and guarantee fees
are also shown below. For further information regarding swaps, see Note 20.
REMAINING REMAINING REMAINING
PRINCIPAL PRINCIPAL PRINCIPAL PRINCIPAL PRINCIPAL INTEREST SWAP GUARANTEE
REPAYMENT IN REPAYMENT IN REPAYMENT IN REPAYMENT IN REPAYMENT IN PAYMENTS PAYMENTS FEES
2004 2005 2006 2007 2008 2004-2013 2004-2013 2004-2013
In USD
US EXIM 19,606,893 19,606,893 19,606,893 19,606,893 19,606,893 62,017,946 0 0
OPIC A 5,041,667 5,041,666 5,041,666 5,041,666 5,041,666 22,657,888 0 0
OPIC B 1,100,000 1,100,000 1,100,000 1,100,000 1,100,000 4,793,735 0 0
Total in USD 25,748,560 25,748,559 25,748,559 25,748,559 25,748,559 89,469,569 0 0
In Euro
SACE 19,387,344 19,387,344 19,387,344 19,387,344 19,387,344 49,481,105 0 0
ERG 2,491,452 2,491,452 2,491,452 2,491,452 2,491,452 4,730,553 4,774,063 0
WB 13,336,197 13,336,197 13,336,197 13,336,197 13,336,197 22,600,374 25,202,063 5,472,842
Total in Euro 35,214,993 35,214,993 35,214,993 35,214,993 35,214,993 76,812,032 29,976,126 5,472,842
B/S FX Rate
Euro/USD 1.26342 1.26342 1.26342 1.26342 1.26342 1.26342 1.26342 1.26342
Total in USD 44,491,219 44,491,219 44,491,219 44,491,219 44,491,219 97,045,624 37,872,347 6,914,481
F-147
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
15. LONG TERM LOANS (CONTINUED)
Long term loans are detailed as follows as of December 31, 2002:
INTEREST REIMBURSEMENT
BORROWING PRINCIPAL ---------------- INTEREST ---------------------------
LOAN DATE CURRENCY AMOUNT TYPE RATE PAYMENT MATURITY PERIODICITY
US EXIM 9/12/02 US$ 200,971,655 Fixed 7.2% Quarterly Feb. 15, 2013 Quarterly
OPIC Note A 11/25/97 US$ 51,677,083 Fixed 10.23% Quarterly Feb. 15, 2013 Quarterly
OPIC Note B 02/11/98 US$ 11,275,000 Fixed 9.92% Quarterly Feb. 15, 2013 Quarterly
-----------
62,952,083
-----------
Total L.T loan in US$ 263,923,738
-----------
Current part in USD 25,748,560
-----------
Non-Current part in USD 238,175,178
-----------
INTEREST REIMBURSEMENT
BORROWING PRINCIPAL ---------------- INTEREST ---------------------------
LOAN DATE CURRENCY AMOUNT TYPE RATE PAYMENT MATURITY PERIODICITY
SACE 11/15/02 Euro 198,720,273 Fixed 5.73% Quarterly Feb. 15, 2013 Quarterly
ERG 11/15/02 Euro 25,537,392 Variable 5.14% Quarterly Feb. 15, 2013 Quarterly
World Bank 11/15/02 Euro 136,696,015 Variable 4.89% Quarterly Feb. 15, 2013 Quarterly
------------
Total L.T loan in Euro 360,953,680
------------
B/S FX Rate Euro/USD 1.04658
------------
Total L.T loan in USD 377,767,743
------------
Current part in USD 36,855,389
------------
Non-Current part in USD 340,912,354
------------
Total principal repayments for the next five years are detailed below.
Forecasts of interest payments, interest-rate swap payments and guarantee fees
are also shown below. For further information regarding swaps, see Note 20.
REMAINING REMAINING REMAINING
PRINCIPAL PRINCIPAL PRINCIPAL PRINCIPAL PRINCIPAL INTEREST SWAP GUARANTEE
REPAYMENT IN REPAYMENT IN REPAYMENT IN REPAYMENT IN REPAYMENT IN PAYMENTS PAYMENTS FEES
2003 2004 2005 2006 2007 2003-2013 2003-2013 2003-2013
In USD
US EXIM 19,606,893 19,606,893 19,606,893 19,606,893 19,606,893 76,033,383 0 0
OPIC A 5,041,667 5,041,666 5,041,666 5,041,666 5,041,666 27,754,052 0 0
OPIC B 1,100,000 1,100,000 1,100,000 1,100,000 1,100,000 5,871,955 0 0
Total in USD 25,748,560 25,748,559 25,748,559 25,748,559 25,748,559 109,659,390 0 0
In Euro
SACE 19,387,344 19,387,344 19,387,344 19,387,344 19,387,344 60,663,342 0 0
ERG 2,491,452 2,491,452 2,491,452 2,491,452 2,491,452 7,093,552 4,535,473 0
WB 13,336,197 13,336,197 13,336,197 13,336,197 13,336,197 36,148,188 23,844,995 6,757,469
Total in Euro 35,214,993 35,214,993 35,214,993 35,214,993 35,214,993 103,905,082 28,380,468 6,757,469
B/S FX Rate
Euro/USD 1.04658 1.04658 1.04658 1.04658 1.04658 1.04658 1.04658 1.04658
Total in USD 36,855,389 36,855,389 36,855,389 36,855,389 36,855,389 108,745,223 29,702,496 7,072,248
Long term loans are detailed as follows as of December 31, 2002:
DRAWDOWN DRAWDOWN INTEREST INTEREST REIMBURSEMENT
LOAN DATE CURRENCY AMOUNT TYPE RATE PAYMENT MATURITY PERIODICITY
US EXIM 11/15/2001 US$ 207,446,204 Variable 4.14% Quarterly Feb. 15, 2013 Quarterly
OPIC Note A 11/25/97 US$ 56,718,750 Fixed 10.48% Quarterly Feb. 15, 2013 Quarterly
OPIC Note B 02/11/98 US$ 12,375,000 Fixed 10.17% Quarterly Feb. 15, 2013 Quarterly
69,093,750
Total L.T loan in US$ 276,539,954
Current part in USD 24,873,137
Non-Current part in USD 251,666,817
DRAWDOWN DRAWDOWN INTEREST INTEREST REIMBURSEMENT
LOAN DATE CURRENCY AMOUNT TYPE RATE PAYMENT MATURITY PERIODICITY
SACE 11/15/2001 Euro 218,107,617 Fixed 5.73% Quarterly Feb. 15, 2013 Quarterly
ERG 11/15/2001 Euro 28,028,845 Variable 5.34% Quarterly Feb. 15, 2013 Quarterly
World Bank 11/15/2001 Euro 150,032,211 Variable 5.09% Quarterly Feb. 15, 2013 Quarterly
Total L.T loan in Euro 396,168,673
B/S FX Rate Euro/USD 0.885
Total L.T loan in USD 350,623,797
Current part in USD 31,166,559
Non-Current part in USD 319,457,237
F-148
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
15. LONG TERM LOANS (CONTINUED)
Total principal repayments for the next five years are detailed below.
Forecast interest payments, interest-rate swap payments and guarantee fees are
also shown below. For further information regarding swaps, see Note 20.
REMAINING REMAINING REMAINING
PRINCIPAL PRINCIPAL PRINCIPAL PRINCIPAL PRINCIPAL INTEREST SWAP GUARANTEE
REPAYMENT IN REPAYMENT IN REPAYMENT IN REPAYMENT IN REPAYMENT IN PAYMENTS PAYMENTS FEES
2002 2003 2004 2005 2006 2002-2013 2002-2013 2002-2013
In USD
US EXIM 18,731,470 19,606,893 19,606,893 19,606,893 19,606,893 87,235,810 0 1,176,315
OPIC A 5,041,667 5,041,666 5,041,666 5,041,666 5,041,666 33,499,497 0 0
OPIC B 1,100,000 1,100,000 1,100,000 1,100,000 1,100,000 7,088,426 0 0
Total in USD 24,873,137 25,748,559 25,748,559 25,748,559 25,748,559 127,823,733 0 1,176,315
In Euro
SACE 19,387,344 19,387,344 19,387,344 19,387,344 19,387,344 72,907,871 0 0
ERG 2,491,452 2,491,452 2,491,452 2,491,452 2,491,452 8,830,924 4,982,063 0
WB 13,336,197 13,336,197 13,336,197 13,336,197 13,336,197 45,081,853 25,824,728 8,173,329
Total in Euro 35,214,993 35,214,993 35,214,993 35,214,993 35,214,993 126,820,648 30,806,791 8,173,329
B/S FX Rate
USD/Euro 0.88504 0.88504 0.88504 0.88504 0.88504 0.88504 0.88504 0.88504
Total in USD 31,166,559 31,166,559 31,166,559 31,166,559 31,166,559 112,240,922 27,265,139 7,233,696
PLEADGE OF STOCK AND OTHER ASSETS
As security for the repayment of the loans, and the payment of all related
interest, fees and swap obligations, JLEC and its stockholders have entered into
various pledge agreements with Deutsche Bank Trust Company Americas, as Offshore
Collateral Agent, and with Banque Marocaine pour le Commerce et l'Industrie, as
Onshore Collateral Agent, for the benefit of such lenders and other secured
parties. Such security shall continue in effect until the repayment in full of
all outstanding principal amounts and the payment in full of all related
interest, fee and swap obligations, which is scheduled to occur in February of
2013. The principle pledge agreements are:
1. The Stockholder Pledge and Security Agreements, in which each of JLEC's
stockholders pledges all of its shares, claims, rights and interests in JLEC to
the Offshore Collateral Agent.
2. The Security and Assignment Agreement, in which JLEC assigns to the
Offshore Collateral Agent a security interest in all of JLEC's rights, title and
interest in the following collateral, among others:
a. all of JLEC's contractual rights,
b. all rents, profits, income and revenues derived by JLEC from its
ownership of the Project,
c. all cash deposits and other assets in any of JLEC's accounts with
financial institutions,
d. all permits, licenses and other governmental authorizations obtained by
JLEC in connection with its ownership of the Project,
e. all of JLEC's insurance policies and related claims and proceeds, and
f. all personal property and inventories of JLEC.
3. The Agreement for Pledge of Shares, in which each of JLEC's
stockholders pledges all of its shares, claims, rights and interests in JLEC to
the Onshore Collateral Agent, and assigns to the Onshore Collateral Agent the
direct payment by JLEC of all dividends and other stockholder distributions if
and whenever a Default has occurred and is continuing.
4. The General Delegation of Contract Claims, in which JLEC assigns to the
Onshore Collateral Agent the direct payment of any and all contract claims due
to JLEC if and whenever a Default has occurred and is continuing.
5. The Pledge over General Operating Accounts, in which JLEC pledges to
the Onshore Collateral Agent any and all monies in JLEC's accounts with the
Onshore Collateral Agent.
6. The Master Agreement for Assignment of Accounts Receivable as Security,
in which JLEC assigns to the Onshore Collateral Agent a security interest in all
of the accounts receivable payable by ONE to JLEC under the Power Purchase
Agreement.
F-149
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
COVENANTS
The covenants on the loans also place restrictions on JLEC's payment of
dividends and other distributions to JLEC's stockholders.
Specifically, JLEC may not:
1. Pay any dividends to its stockholders, or
2. Make any distribution, payment or delivery of property or cash to its
stockholders, or
3. Redeem, retire, purchase or otherwise acquire any shares of its capital
stock, or
4. Purchase or redeem any subordinated debt except, on quarterly repayment
dates and only then after first satisfying all debt service obligations and
satisfying all of the following conditions, among others:
a. No default shall have occurred,
b. The cash balance in all JLEC reserve and accrual accounts shall equal
or exceed required levels,
c. JLEC's actual debt service coverage ratios for the current quarter and
preceding four quarters have all been greater than 1.3, and
d. JLEC's forecasted debt service coverage ratios for the next succeeding
two quarters are greater than 1.3 JLEC has complied with these covenants since
May 2001, when the loans began to be repaid.
16. STOCKHOLDERS' EQUITY
The composition of Stockholders' Equity as of December 31, 2003 was:
16.1 COMMON STOCK
COMMON STOCK
---------------------------------
NUMBER PAR VALUE PAR VALUE
STOCKHOLDERS OF SHARES DIRHAM US DOLLAR
------------------------------------------ --------- --------- -----------
AB Cythere 63, Sweden..................... 2,634 263,400 27,668
Jorf Lasfar Energiaktiebolag, Sweden...... 1,375 137,500 14,443
Jorf Lasfar Power Energy AB, Sweden....... 1,265 126,500 13,288
Tre Kronor Investment AB, Sweden.......... 110 11,000 1,155
Jorf Lasfar Handelsbolag, Sweden.......... 110 11,000 1,155
AB Cythere 61, Sweden..................... 6 600 63
----- -------- ------
Total 5,500 550,000 57,773
16.2 CONVERTIBLE STOCKHOLDERS' SECURITIES
On December 11, 2000, the JLEC stockholders purchased 100% of all Company
Loan Notes for $387,355,000, and amended the Company Loan Agreement to make such
stockholder securities convertible into Preferred Stock or Common Stock. On
January 1, 2001, the convertible securities (Company Loan Principal) held by AB
Cythere 61 and AB Cythere 63 were converted into Preferred Stock as shown below
on Note 16.3. Such conversions shall be made into a fixed number of JLEC shares
as listed below:
NUMBER PAR VALUE PAR VALUE
STOCKHOLDERS OF SHARES DIRHAM US DOLLAR
----------------------------------------- ---------- ------------- -----------
AB Cythere 63, Sweden.................... 0 0 0
Jorf Lasfar Energiaktiebolag, Sweden..... 10,537,024 1,053,702,400 96,838,750
Jorf Lasfar Power Energy AB, Sweden...... 9,694,062 969,406,200 89,091,650
Tre Kronor Investment AB, Sweden......... 842,962 84,296,200 7,747,100
Jorf Lasfar Handelsbolag, Sweden......... 842,962 84,296,200 7,747,100
AB Cythere 61, Sweden.................... 0 0 0
---------- ------------- -----------
Total 21,917,010 2,191,701,000 201,424,600
F-150
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
Under the terms of the amended Company Loan Agreement summarized below,
these convertible securities constitute an hybrid instrument which are delt with
in accordance with the substance of the transaction, i.e. as a Preferred Stock
equivalent:
(a) Expression of the Loan in MAD
The outstanding USD 201,424,600 principal amount is expressed as MAD
2,191,701,000 for the purpose of computing interest and principal payments due
under this Agreement. However, interest and principal payments will be paid to
the stockholders in USD, provided that the Company is not responsible for any
losses realized by the stockholders resulting from the depreciation of the value
of the MAD relative to the USD.
(b) Repayment or conversion into Stock
Under the terms of the amended Agreement:
- the Security may only be repaid, in whole or in part, at the
Company's option;
- the part of the Security principal held by other Company Lenders
listed above may be converted into Common Stock at any time, using
the same conversion ratio used for the conversion of the parts of AB
Cythere 61 and AB Cythere 63;
- the shares of Preferred Stock issued to AB Cythere 61 and AB Cythere
63 may be converted into Common Stock. In this case, all outstanding
Security principal held by other Company Lenders will be mandatorily
converted into Common Stock at the same conversion ratio.
(c) Interest payment and accruals as Retained Earning In accordance with
Amendment N(degree).2, the Company will pay interest on the unpaid
principal amount once per year, at the interest rate per annum equal
to the greater of (1) the Moroccan maximum deductible rate, and (2)
4.00%. The applicable interest rate for 2003 is 4.00%. Accruals for
such interest payments are reported as part of the Retained Earning
allocation in Note 16.4, and are not expensed.
16.3 PREFERRED STOCK
In accordance with Section 3.01 par.(b) of the amended Company Loan
Agreement (see note 16.2 above), the Company as converted on January 1, 2001,
all outstanding Company Loan principal held by AB Cythere 61 and AB Cythere 63,
at the conversion ratio of one (1) share of Preferred Stock for each one hundred
(100) MAD of such Company Loan principal converted into Preferred Stock, as
follows:
PREFERRED STOCK
----------------------------------------
NUMBER PAR VALUE PAR VALUE
STOCKHOLDERS OF SHARES DIRHAM US DOLLAR
------------------------------------------ ---------- ------------- -----------
AB Cythere 63, Sweden..................... 20,185,145 2,018,514,500 185,508,183
Jorf Lasfar Energiaktiebolag, Sweden...... 0 0 0
Jorf Lasfar Power Energy AB, Sweden....... 0 0 0
Tre Kronor Investment AB, Sweden.......... 0 0 0
Jorf Lasfar Handelsbolag, Sweden.......... 0 0 0
AB Cythere 61, Sweden..................... 45,941 4,594,100 422,217
---------- ------------- -----------
Total 20,231,086 2,023,108,600 185,930,400
Such shares are non-participating voting shares of convertible Preferred
Stock of the Company, and:
- are convertible at any moment into shares of Common Stock;
- give right to the collection of a minimum priority dividend, at
least equal to 4% of the aggregate par value of the preferred
shares,
F-151
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
- do not participate in the distribution of the remaining balance of
Retained Earning, which is divided among the shares of Common Stock
as shown in Note 16.4.
16.4 RECONCILIATION AND ALLOCATION OF RETAINED EARNINGS
2003 US$
----------------------------------------------------------------------------- -----------
Retained Earnings as of December 31, 2002 113,030,506
Retained Earnings increase during 2003 119,850,319
Retained Earnings decrease during 2003
Convertible Securities interest payable as of January 1, 2003 -10,612,757
108,218,281 Dirhams
10.1970 Dirhams per US Dollar
Preferred Stock Dividend payable as of January 1, 2003 -9,796,391
99,893,797 Dirhams
10.1970 Dirhams per US Dollar
Common Stock Dividend payable as of October 30, 2003 -64,972,722
5,500 Common Stock Shares
110,000 Dirhams per share
605,000,000 Dirhams
9.3116 Dirhams per US Dollar on October 30, 2003
-----------
Total Retained Earnings 147,498,955
The Retained Earnings are allocated among the stockholders as follows:
COMMON
CONVERTIBLE SECURITIES PREFERRED STOCK STOCK TOTAL
------------------------ ----------------------- --------------------------
STOCKHOLDERS DIRHAMS US DOLLARS DIRHAMS US DOLLARS US DOLLARS US DOLLARS
---------------------------------------------- ---------- ---------- ---------- ---------- ----------- ------------
AB Cythere 63, Sweden......................... 0 0 81,861,977 9,327,725 61,310,884 70,638,608
Jorf Lasfar Energiaktiebolag, Sweden.......... 42,733,486 4,869,247 0 0 32,005,492 36,874,739
Jorf Lasfar Power Energy AB, Sweden........... 39,314,807 4,479,707 0 0 29,445,052 33,924,760
Tre Kronor Investment AB, Sweden.............. 3,418,679 389,540 0 0 2,560,439 2,949,979
Jorf Lasfar Handelsbolag, Sweden.............. 3,418,679 389,540 0 0 2,560,439 2,949,979
AB Cythere 61, Sweden......................... 0 0 186,316 21,230 139,660 160,890
---------- ---------- ---------- --------- ---------- -----------
Total 88,885,652 10,128,034 82,048,293 9,348,954 128,021,967 147,498,955
The allocations for Convertible Securities (88,885,652 Dirhams) and
Preferred Stock (82,048,293 Dirhams) are payable as of January 1, 2004, and are
scheduled for payment on May 17, 2004.
2002 US$
----------------------------------------------------------------------------------- ----------
Retained Earnings as of December 31, 2001 187,671,644
Retained Earnings increase during 2002 132,287,908
Retained Earnings decrease during 2002:
Convertible Securities interest payable as of January 1, 2002 -12,095,803
140,250,832 Dirhams
11.5950 Dirhams per US Dollar
Preferred Stock Dividend payable as of January 1, 2002 -9,942,031
115,277,852 Dirhams
11.5950 Dirhams per US Dollar
Common Stock Dividend payable as of October 29, 2002 -184,891,213
5,500 Common Stock Shares
360,000 Dirhams per share
1,980,000,000 Dirhams
10.7090 Dirhams per US Dollar on October 29, 2002
-----------
Total Retained Earnings 113,030,506
F-152
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
The Retained Earnings are allocated among the shareholders as follows:
COMMON
CONVERTIBLE SECURITIES PREFERRED STOCK STOCK TOTAL
------------------------- ------------------------ ---------------------------
SHAREHOLDERS DIRHAMS US DOLLARS DIRHAMS US DOLLARS US DOLLARS US DOLLARS
---------------------------------------- ---------- ------------ ---------- ---------- ----------- ------------
AB Cythere 63, Sweden.................. 0 0 99,666,957 9,774,145 44,357,210 54,131,355
Jorf Lasfar Energiaktiebolag, Sweden... 52,028,019 5,102,287 0 0 23,155,340 28,257,626
Jorf Lasfar Power Energy AB, Sweden.... 47,865,778 4,694,104 0 0 21,302,912 25,997,016
Tre Kronor Investment AB, Sweden....... 4,162,242 408,183 0 0 1,852,427 2,260,610
Jorf Lasfar Handelsbolag, Sweden....... 4,162,242 408,183 0 0 1,852,427 2,260,610
AB Cythere 61, Sweden 0 0 226,840 22,246 101,041 123,287
----------- ----------- ---------- --------- ----------- ------------
Total 108,218,281 10,612,757 99,893,797 9,796,391 92,621,358 113,030,506
2001 USD
----------------------------------------------------------------------------------------- -----------
Retained Earnings as of December 31, 2000 296,408,600
Retained Earnings increase during 2001 161,385,686
Retained Earnings decrease during 2001
Common Stock dividend declared payable on April 24, 2001 -151,362,260
5,500 Common Stock Shares
300,000 Dirhams per share
1,650,000,000 Dirhams
10.9010 Dirhams per US Dollar on April 24, 2001
Common Stock dividend declared payable on October 29, 2001 -118,760,381
5,500 Common Stock Shares
247,000 Dirhams per share
1,358,500,000 Dirhams
11.4390 Dirhams per US Dollar on October 29, 2001
-----------
Total Retained Earnings 187,671,644
The Retained Earnings are allocated among the shareholders as follows:
COMMON
CONVERTIBLE SECURITIES PREFERRED STOCK STOCK TOTAL
SHAREHOLDERS DIRHAMS US DOLLARS DIRHAMS US DOLLARS US DOLLARS US DOLLARS
---------------------------------------- ------------ ----------- ----------- ---------- ----------- -----------
AB Cythere 63, Sweden.................. 7,359,167 634,685 115,016,078 9,919,455 79,323,538 89,877,677
Jorf Lasfar Energiaktiebolag, Sweden... 63,882,171 5,509,458 0 0 41,408,453 46,917,911
Jorf Lasfar Power Energy AB, Sweden.... 58,771,597 5,068,702 0 0 38,095,776 43,164,478
Tre Kronor Investment AB, Sweden....... 5,110,574 440,757 0 0 3,312,676 3,753,433
Jorf Lasfar Handelsbolag, Sweden....... 5,110,574 440,757 0 0 3,312,676 3,753,433
AB Cythere 61, Sweden.................. 16,749 1,445 261,774 22,576 180,691 204,712
----------- ----------- ----------- --------- ----------- -----------
Total 140,250,833 12,095,803 115,277,852 9,942,031 165,633,810 187,671,644
17. DIRECT FINANCING LEASE - (D.F.L)
As explained in Note 2b, JLEC is using the Direct Financing Lease
methodology. Specific accounts were created to reflect this method. These
accounts are detailed below.
DIRECT FINANCING LEASE - (D.F.L) AS OF DECEMBER 31, 2003
17.1 LONG TERM RECEIVABLES AS OF DECEMBER 31, 2003
US$ EURO
UNITS 1 TO 4 UNITS 1 TO 4
------------- ------------
Total Minimum Lease Payments 1,283,596,155 956,285,785
Minimum Lease Payments for 2003 -101,642,136 -121,482,375
------------- -------------
Total of Future Minimum Lease Payments 1,181,954,019 834,803,410
X 1.263417
------------- -------------
Total of Future Minimum Lease Payments in US$ 17.3 1,181,954,019 1,054,704,794
============= =============
F-153
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
The minimum lease payments under the US GAAP model for the next five years
are as follows:
US$ EURO
------------ ------------
YEAR UNITS 1 TO 4 UNITS 1 TO 4
---- ------------ ------------
2004 116,664,592 116,635,941
2005 116,371,118 107,167,144
2006 108,749,430 92,362,540
2007 96,617,923 85,060,254
2008 104,467,842 84,500,888
17.2 UNEARNED INCOME AS OF DECEMBER 31, 2003
US$ EURO
------------ ------------
UNITS 1 TO 4 UNITS 1 TO 4
------------ ------------
Total Unearned Income 587,282,368 568,767,180
Lease Revenue 2003 -81,792,828 -91,756,966 X 1.14035 104,635,053
----------- ----------- --------- ------------
505,489,540 477,010,214
X 1.263417
----------- -----------
Total Remaining Unearned Income in US$ 17.3 505,489,540 602,662,799
=========== ===========
The minimum lease payments under the US GAAP model for the next five years
are as follows:
US$ EURO
------------ ------------
YEAR UNITS 1 TO 4 UNITS 1 TO 4
---- ------------ ------------
2004 78,203,985 84,230,456
2005 73,392,008 76,117,547
2006 68,172,214 69,587,224
2007 64,172,868 64,534,124
2008 59,591,568 58,711,491
17.3 NET INVESTMENT IN DIRECT FINANCING LEASES AS OF DECEMBER 31, 2003
US$ EURO
------------ ------------
UNITS 1 TO 4 UNITS 1 TO 4
------------ ------------
Total of Future Minimum Lease Payments in US$ 17.1 1,181,954,019 1,054,704,794
Total Remaining Unearned Income in US$ 17.2 -505,489,540 -602,662,799
------------- -------------
Net investment in direct financing leases in US$ 676,464,479 452,041,995
============= =============
Current part in US$ 38,460,607 40,941,639
Non-Current part in US$ 638,003,872 411,100,356
DIRECT FINANCING LEASE - (D.F.L) AS OF DECEMBER 31, 2002
17.1 LONG TERM RECEIVABLES AS OF DECEMBER 31, 2002
US$ EURO
------------ ------------
UNITS 1 TO 4 UNITS 1 TO 4
------------ ------------
Total Minimum Lease Payments 1,426,008,468 1,081,037,348
Minimum Lease Payments for 2002 -142,336,127 -124,619,384
------------ -------------
Total of Future Minimum Lease Payments 1,283,672,341 956,417,964
------------ -------------
X 1.046582
Total of Future Minimum Lease Payments in US$ 17.3 1,283,672,341 1,000,970,139
============= =============
F-154
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
The minimum lease payments under the US GAAP model for the next five years
are as follows:
US$ EURO
------------ ------------
YEAR UNITS 1 TO 4 UNITS 1 TO 4
------------- ------------ ------------
2003 101,642,136 121,482,376
2004 116,664,592 116,635,941
2005 116,371,118 107,167,144
2006 106,872,046 90,768,049
2007 96,617,923 85,060,254
17.2 UNEARNED INCOME AS OF DECEMBER 31, 2002
US$ EURO
------------ ------------
UNITS 1 TO 4 UNITS 1 TO 4
------------ ------------
Total Unearned Income 673,381,447 668,603,895
Lease Revenue 2002 -88,463,713 -99,930,507 X 0.95144 95,077,872
----------- ------------ --------- ----------
584,917,734 568,673,388
------------ ------------
X 1.046582
------------ ------------
Total Remaining Unearned Income in US$ 17.3 584,917,734 595,163,517
=========== ===========
The Lease Revenue under the US GAAP model for the next five years are as
follows:
US$ EURO
------------ ------------
YEAR UNITS 1 TO 4 UNITS 1 TO 4
----------- ------------ ------------
2003 81,436,213 91,576,926
2004 77,831,811 84,020,822
2005 73,012,360 75,871,769
2006 67,896,425 69,487,000
2007 64,019,517 64,661,480
17.3 NET INVESTMENT IN DIRECT FINANCING LEASES AS OF DECEMBER 31, 2002
US$ EURO
------------ ------------
UNITS 1 TO 4 UNITS 1 TO 4
------------ ------------
Total of Future Minimum Lease Payments in US$ 17.1 1,283,672,341 1,000,970,139
Total Remaining Unearned Income in US$ 17.2 -584,917,734 -595,163,517
------------- -------------
Net investment in direct financing leases in US$ 698,754,607 405,806,622
============= =============
Current part in US$ 20,205,960 31,298,090
Non-Current part in US$ 678,548,647 374,508,532
17.1 LONG TERM RECEIVABLES AS OF DECEMBER 31, 2001
US$ EURO
------------ ------------
UNITS 1 TO 4 UNITS 1 TO 4
------------ ------------
Total Minimum Lease Payments 1,638,683,000 1,210,483,496
Minimum Lease Payments for 2001 -172,987,799 -116,468,307
------------- -------------
Total of Future Minimum Lease Payments 1,465,695,201 1,094,015,189
------------- -------------
X 0.88504
------------- -------------
Total of Future Minimum Lease Payments in US$ 17.3 1,465,695,201 968,243,542
============= ============
The minimum lease payments under the US GAAP model for the next five years
are as follows:
US$ EURO
------------ ------------
YEAR UNITS 1 TO 4 UNITS 1 TO 4
----------- ------------ ------------
2002 147,453,739 125,654,878
2003 108,352,169 125,448,188
2004 121,415,209 118,233,920
2005 120,444,202 108,413,086
2006 109,842,978 91,398,693
F-155
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
17.2 UNEARNED INCOME AS OF DECEMBER 31, 2001
US$ EURO
------------ ------------
UNITS 1 TO 4 UNITS 1 TO 4
------------ ------------
Total Unearned Income 823,653,897 792,223,192
Lease Revenue 2001 -100,679,205 -105,867,406 X 0.89305 94,544,727
----------- ----------- --------- ----------
722,974,692 686,355,786
----------- -----------
91,398,693
----------- -----------
Total Remaining Unearned Income in US$ 17.3 722,974,692 607,450,028
=========== ===========
The Lease Revenue under the US GAAP model for the next five years are as
follows:
US$ EURO
------------- ------------
YEAR UNITS 1 TO 4 UNITS 1 TO 4
-------------- ------------- ------------
2002 91,392,805 101,298,144
2003 87,462,185 94,047,617
2004 83,519,951 86,014,881
2005 78,375,499 77,627,453
2006 73,017,083 71,189,178
17.3 NET INVESTMENT IN DIRECT FINANCING LEASES AS OF DECEMBER 31, 2001
US$ EURO
------------ ------------
UNITS 1 TO 4 UNITS 1 TO 4
------------ ------------
Total of Future Minimum Lease Payments in US$ 17.1 1,465,695,201 968,243,542
Total Remaining Unearned Income in US$ 17.2 -722,974,692 -607,450,028
------------- ------------
Net investment in direct financing leases in US$ 742,720,509 360,793,514
============= ============
Current part in US$ 56,060,930 21,301,261
Non-Current part in US$ 686,659,570 339,492,340
18. FINANCIAL EXPENSES
The Financial Expenses are detailed as follows, for the year ending:
12/31/03 12/31/02 12/31/01
US$ US$ US$
----------- ----------- -----------
Interest, Fees and Swaps incurred from inception to December 31, 2003
Up-Front Fees 25,609,073 25,609,073 25,609,073
Interest Costs 287,290,576 246,526,514 210,187,205
Premiums 23,808,481 23,808,481 23,808,481
Commitment Fees 19,312,672 19,312,672 18,136,357
Arrangement Fees 2,396,273 2,396,273 2,396,273
Other Fees (acceptance fees, Agent fees...etc) 9,754,617 9,297,751 8,875,953
Guarantee Fees 20,598,822 19,101,732 5,496,128
Swaps 37,238,114 30,362,978 25,851,201
----------- ----------- -----------
426,008,628 376,415,474 320,360,671
Accrued Interest, Fees, Swaps (see Note 14.1) 5,904,937 6,072,924 17,293,488
----------- ----------- -----------
Total Interest, Fees and Swaps 431,913,565 382,488,398 337,654,159
Interest, fees and swaps capitalized as part of
the project construction for Units 3&4 -210,949,363 -210,949,363 -210,949,363
----------- ----------- -----------
Interest and swaps expensed - Total 220,964,202 171,539,035 126,704,796
Interest and swaps expensed from 1997 through 2002 -171,539,035 -126,704,796 -76,088,286
----------- ----------- -----------
Interest and swaps expensed 49,425,167 44,834,239 50,616,510
=========== =========== ===========
F-156
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
19. PENSION PLANS
JLEC contributes to the following pension plans:
19.1 COMMON FUND FOR RETIREMENT (CAISSE COMMUNE DES RETRAITES OR CCR)
As required by PPA Section 23.2.4, most of JLEC's employees (259 employees
of 313, or 84%) plus 1 recent retiree are participants in the CCR defined
benefit pension plan. This plan is funded by employee payroll deductions equal
to 9% of the employee's gross pay, plus JLEC contributions equal to 18% of the
participating employee's gross pay. In 2003, 2002 and 2001, JLEC contributed to
the CCR US$ 350,071, US$ 291,036 and US$ 266,972, respectively.
Benefits provided under this plan include pension and retiree health
insurance. As of December 31, 2003, the benefit obligation totalled US$
14,584,092 (MAD 127,992,907/8.7762). The fair value of assets contributed to the
CCR was US$ 4,705,965 (MAD 41,300,493/8.7762) as of December 31, 2003. The net
unfunded benefit obligation as of December 31, 2003 reflected in the
accompanying balance sheet was US$ 9,878,126 (MAD 86,692,413/8.7762).
The following assumptions were used to perform the actuarial valuations:
2003 2002 2001
------ ----- -----
Discount rate 6.00% 7.58% 7.58%
Rate of compensation increase 6.50% 6.50% 6.50%
19.2 MOROCCAN RETIREMENT FUND FOR PROFESSIONALS (CAISSE INTERPROFESSIONNELLE
MAROCAINE DE RETRAITES OR CIMR)
Employees of JLEC not covered by CCR participate in a fund to which the
employer contributes an amount equal to 12 percent of the employee's gross pay.
This fund is carried in the employee's name, and the pension benefits an
employee will receive depend only on the amount contributed to this account and
the returns earned on investments of those contributions. In 2003, JLEC's
contribution to that fund amounted to USD 145,677 (USD 109,147 in 2002, and USD
105,912 in 2001)
20. DERIVATIVE INSTRUMENT LIABILITY / OTHER COMPREHENSIVE INCOME
JLEC adopted SFAS N(degree). 133 on January 1, 2001. This standard
requires JLEC to recognize at fair value on the balance sheet, as assets or
liabilities, all contracts that meet the definition of a derivative instrument.
Details of all JLEC derivative instruments (interest rate swaps) are provided in
the following table as of December 31, 2003, and all such swaps qualify with
100% effectiveness as cash flow hedge for JLEC's variable interest rate loans.
Therefore, in accordance with SFAS N(degree). 133, the changes in fair value of
these interest rate swaps are reflected directly in Stockholders' Equity under
"Other Comprehensive Income or (Loss)". JLEC determines fair value based upon
market price estimations provided by the swap providers.
2003
FIXED RATE CURRENT CURRENT SETTLEMENT FORECAST OF VALUATION
CREDIT SWAP PAID BY LIBOR PAID NOTIONAL AND TERMINATION REMAINING IN
FACILITY PROVIDERS CURRENCY JLEC TO JLEC AMOUNT AMORTIZATION DATE PAYMENTS EURO
---------- ---------- -------- -------- ---------- ----------- ------------ ----------- ------------ -----
World Bank BNP Euro 6.4115% 2.16888% 41,119,939 Quarterly 2/15/2013 8,400,358 4,942,789
ABN Euro 6.4175% 2.16888% 41,119,939 Quarterly 2/15/2013 8,412,238 4,940,969
CSFB Euro 6.4060% 2.16888% 41,119,939 Quarterly 2/15/2013 8,389,468 4,733,058
----------- ---------- ----------
123,359,818 25,202,063 14,616,816
----------- ---------- ----------
ERG BNP Euro 6.4700% 2.16888% 7,681,980 Quarterly 2/15/2013 1,590,984 942,887
ABN Euro 6.4750% 2.16888% 7,681,980 Quarterly 2/15/2013 1,592,834 942,179
CSFB Euro 6.4680% 2.16888% 7,681,980 Quarterly 2/15/2013 1,590,245 950,471
----------- ---------- ----------
23,045,940 4,774,063 2,835,537
----------- ---------- ----------
Total in Euro 17,452,353
----------
B/S FX rate X 1.26342
Total in USD 22,049,599
==========
F-157
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
2002
FIXED RATE CURRENT CURRENT SETTLEMENT FORECAST OF VALUATION
CREDIT SWAP PAID BY LIBOR PAID NOTIONAL AND TERMINATION REMAINING IN
FACILITY PROVIDERS CURRENCY JLEC TO JLEC AMOUNT AMORTIZATION DATE PAYMENTS EURO
-------- --------- -------- ---- ------- ------ ------------ ---- -------- ----
World Bank BNP Euro 6.4115% 3.13725% 45,565,338 Quarterly 2/15/2013 7,947,927 5,729,083
ABN Euro 6.4175% 3.13725% 45,565,338 Quarterly 2/15/2013 7,962,491 5,739,581
CSFB Euro 6.4060% 3.13725% 45,565,338 Quarterly 2/15/2013 7,934,576 5,719,459
----------- ---------- ----------
136,696,014 23,844,995 17,188,122
----------- ---------- ----------
ERG BNP Euro 6.4700% 3.13725% 8,512,464 Quarterly 2/15/2013 1,511,371 1,089,437
ABN Euro 6.4750% 3.13725% 8,512,464 Quarterly 2/15/2013 1,513,638 1,091,072
CSFB Euro 6.4680% 3.13725% 8,512,464 Quarterly 2/15/2013 1,510,464 1,088,783
----------- ----------- -----------
25,537,392 4,535,473 3,269,292
----------- ----------- -----------
Total in Euro 20,457,415
----------
B/S FX rate X 1.04658
Total in USD 21,410,369
==========
2001
FIXED RATE CURRENT CURRENT SETTLEMENT FORECAST OF VALUATION
CREDIT SWAP PAID BY LIBOR PAID NOTIONAL AND TERMINATION REMAINING IN
FACILITY PROVIDERS CURRENCY JLEC TO JLEC AMOUNT AMORTIZATION DATE PAYMENTS EURO
-------- --------- -------- ---- ------- ------ ------------ ---- -------- ----
World Bank BNP Euro 6.4300% 3.34000% 48,899,387 Quarterly 12/17/2012 8,614,748 3,369,696
ABN Euro 6.4300% 3.34000% 48,899,387 Quarterly 12/17/2012 8,614,748 3,369,696
CSFB Euro 6.4230% 3.34000% 48,899,387 Quarterly 12/17/2012 8,595,232 3,362,062
----------- ---------- ----------
146,698,162 25,824,728 10,101,454
----------- ---------- ----------
ERG BNP Euro 6.3600% 3.34000% 9,654,551 Quarterly 12/17/2012 1,662,339 650,231
ABN Euro 6.3600% 3.34000% 9,654,551 Quarterly 12/17/2012 1,662,339 650,231
CSFB Euro 6.3510% 3.34000% 9,654,551 Quarterly 12/17/2012 1,657,385 648,293
----------- ---------- ----------
28,963,653 4,982,063 1,948,755
----------- ---------- ----------
Total in Euro 12,050,209
----------
B/S FX rate X 0.88504
Total is USD 10,664,877
21. CASH FLOWS FOR 2003
Reconciliation of net income to net cash from operating activities under
the Direct Method is as follows :
2003 2002 2001
US$ US$ US$
--- --- ---
Net Income.............................................................. 119,850,319 132,287,908 161,385,686
Adjustment to reconcile Net Income to cash provided from operating
activities :
Depreciation and amortization.................................. 4,028,115 2,752,641 731,003
Deferred taxes................................................. (13,005,297) 6,908,298 6,097,093
Lease Revenue.................................................. (186,427,881) (183,541,585) (195,223,932)
Finance tariff cash revenue.................................... 246,405,730 263,559,812 262,829,803
Changes in operating assets and liabilities:
Inventories.................................................... 2,066,641 (8,855,387) (9,242,424)
Accounts receivable............................................ (9,311,086) 10,340,353 (22,975,149)
Prepayments.................................................... 2,292,604 (5,954,169) 979,429
Accounts payable............................................... 22,353,640 (9,266,000) (20,701,000)
Unfunded pension obligation.................................... 4,185,183 5,692,943 --
Other liabilities.............................................. (2,445,519) (608,934) 3,093,490
Effect of exchange rate changes................................ 1,824,028 4,235,487 (2,003,877)
-------------- ------------- -----------
Net cash provided by operating activities............................... 191,816,478 217,551,367 184,970,122
22. UNCERTAINTIES AS OF DECEMBER 31, 2003
22.1 JLEC's corporate tax return, payroll tax and VAT returns for the
years 2000 to 2003 are open to audit by the Moroccan Tax Authorities. JLEC is
periodically involved in other legal, tax and other proceedings regarding
matters arising in the ordinary course of business. JLEC believes that the
outcome of these matters will not materially affect its results of operations or
liquidity.
22.2 Discussions are currently underway between JLEC and ONE, which may
result in amendments of the Power Purchase Agreement (PPA) and the Transfer of
Possession Agreement (TPA). As currently drafted, such amendments would
eliminate ONE's right of termination for convenience (which right ONE could
otherwise exercise starting on September 13, 2012) and reduce ONE's right of
termination due to adverse economic
F-158
JORF LASFAR ENERGY COMPANY
NOTES TO US GAAP FINANCIAL STATEMENTS DATED DECEMBER 31, 2003
circumstances (which right ONE might otherwise be entitled to exercise after all
of the principal amount of JLEC's indebtedness to the project lenders has been
repaid); and thereby, the proposed amendments would increase the likelihood that
the PPA and TPA continue in effect until their scheduled expiration on September
13, 2027. In exchange, it is proposed that the PPA's gross capacity charges be
reduced by means of a new rebate (to be paid by JLEC to ONE on a quarterly
basis, and calculated starting from September 13, 2003) and future tariff
reductions (starting from September 13, 2014). These possible PPA and TPA
amendments are still under negotiation, and such negotiations may or may not
converge on agreements acceptable to both JLEC and ONE. Furthermore, any
potential PPA and TPA amendments agreed between JLEC and ONE would still be
subject to change by and the approval of ONE's Board of Directors, JLEC's
shareholders and JLEC's lenders before coming into effect. This process of
negotiation, review and approval will require several months at least, and may
possibly never result in any amendments. This uncertainty exists as of the date
of these financial statements.
23. NEW ACCOUNTING STANDARDS
In June 2002, FASB issued SFAS No 146, "Accounting for Costs Associated
with Exit or Disposal Activities.". This statement addresses the recognition,
measurement and reporting of costs that are associated with exit and disposal
activities and nullifies EITF 94-3 "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to exit an Activity (Including Certain
costs incurred in a Restructuring)". Under SFAS 146, the cost associated with an
exit or disposal activity is recognized in the periods in which it is incurred
rather than at the date the company committed to the exit plan. This statement
became effective for exit or disposal activities initiated after December 31,
2002. The adoption of SFAS No 146 did not have a material impact on JLEC's
results of operations or its financial position.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity." The
Standard specifies that instruments within its scope embody obligations of the
issuer and that, therefore, the issuer must classify them as liabilities. The
Standard is effective for interim or fiscal periods ending after June 15, 2003.
JLEC is currently assessing the new standard and has not yet determined the
impact on its financial statements.
F-159
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners and the Management Committee of
Midland Cogeneration Venture Limited Partnership:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, partners' equity and cash flows present
fairly, in all material respects, the financial position of the Midland
Cogeneration Limited Partnership (a Michigan limited partnership) and its
subsidiaries (MCV) at December 31, 2003 and 2002, and the results of their
operations and their cash flows for the each of the two years ended December 31,
2003 and 2002 in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
MCV's management. Our responsibility is to express an opinion on these financial
statements based on our audit. We conducted our audits of these statements in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. The financial statements of
MCV for the year ended December 31, 2001, were audited by other independent
accountants who have ceased operations. Those independent accountants expressed
an unqualified opinion on those financial statements in their report dated
January 18, 2002.
As explained in Note 2 to the financial statements, effective April 1, 2002,
Midland Cogeneration Venture Limited Partnership changed its method of
accounting for derivative and hedging activities in accordance with Derivative
Implementation Group ("DIG") Issue C-16.
/s/ PricewaterhouseCoopers LLP
------------------------------
Detroit, Michigan
February 18, 2004
F-160
THE FOLLOWING REPORT IS A COPY OF A PREVIOUSLY ISSUED REPORT BY ARTHUR ANDERSEN
LLP (ANDERSEN). THIS REPORT HAS NOT BEEN REISSUED BY ANDERSEN, AND ANDERSEN DID
NOT CONSENT TO THE INCLUSION OF THIS REPORT INTO THIS FORM 10-K. THE FOOTNOTE
SHOWN BELOW WAS NOT PART OF ANDERSEN'S REPORT.
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners and the Management Committee of the Midland Cogeneration Venture
Limited Partnership:
We have audited the accompanying consolidated balance sheets of the MIDLAND
COGENERATION VENTURE LIMITED PARTNERSHIP (a Michigan limited partnership) and
subsidiaries (MCV) as of December 31, 2001 and 2000*, and the related
consolidated statements of operations, partners' equity and cash flows for each
of the three years in the period ended December 31, 2001*. These financial
statements are the responsibility of MCV's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of the Midland
Cogeneration Venture Limited Partnership and subsidiaries as of December 31,
2001 and 2000*, and the consolidated results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001*, in
conformity with accounting principles generally accepted in the United States.
As explained in Note 2 to the financial statements, effective January 1, 2001,
Midland Cogeneration Venture Limited Partnership changed its method of
accounting related to derivatives and hedging activities.
ARTHUR ANDERSEN LLP
Detroit, Michigan January 18, 2002
*The MCV's consolidated balance sheets as of December 31, 2001 and 2000 and the
consolidated statements of operations, partners' equity and cash flows for the
years ended December 31, 1999 and 2000 are not included in this Annual Report on
Form 10-K.
F-161
MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP
CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31,
(IN THOUSANDS)
2003 2002
----------- -----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 173,651 $ 160,425
Accounts and notes receivable - related parties 43,805 48,448
Accounts receivable 38,333 32,479
Gas inventory 20,298 19,566
Unamortized property taxes 17,672 18,355
Derivative assets 86,825 73,819
Broker margin accounts and prepaid expenses 8,101 5,165
----------- -----------
Total current assets 388,685 358,257
----------- -----------
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment 2,463,931 2,449,148
Pipeline 21,432 21,432
----------- -----------
Total property, plant and equipment 2,485,363 2,470,580
Accumulated depreciation (991,556) (920,614)
----------- -----------
Net property, plant and equipment 1,493,807 1,549,966
----------- -----------
OTHER ASSETS:
Restricted investment securities held-to-maturity 139,755 138,701
Derivative assets non-current 18,100 31,037
Deferred financing costs, net of accumulated
amortization of $17,285 and $15,930,
respectively 7,680 9,035
Prepaid gas costs, materials and supplies 21,623 11,077
----------- -----------
Total other assets 187,158 189,850
----------- -----------
TOTAL ASSETS $ 2,069,650 $ 2,098,073
=========== ===========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities $ 57,368 $ 58,080
Gas supplier funds on deposit 4,517 --
Interest payable 53,009 56,386
Current portion of long-term debt 134,576 93,928
----------- -----------
Total current liabilities 249,470 208,394
----------- -----------
NON-CURRENT LIABILITIES:
Long-term debt 1,018,645 1,153,221
Other 2,459 2,148
----------- -----------
Total non-current liabilities 1,021,104 1,155,369
----------- -----------
COMMITMENTS AND CONTINGENCIES
TOTAL LIABILITIES 1,270,574 1,363,763
----------- -----------
PARTNERS' EQUITY 799,076 734,310
----------- -----------
TOTAL LIABILITIES AND PARTNERS' EQUITY $ 2,069,650 $ 2,098,073
=========== ===========
The accompanying notes are an integral part of these statements.
F-162
MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31,
(IN THOUSANDS)
2003 2002 2001
------------ ------------ ------------
OPERATING REVENUES:
Capacity $ 404,681 $ 404,713 $ 409,633
Electric 162,093 177,569 184,707
Steam 17,638 14,537 16,473
------------ ------------ ------------
Total operating revenues 584,412 596,819 610,813
------------ ------------ ------------
OPERATING EXPENSES:
Fuel costs 254,988 255,142 288,167
Depreciation 89,437 88,963 92,176
Operations 16,943 16,642 16,082
Maintenance 15,107 12,666 13,739
Property and single business taxes 30,040 27,087 26,410
Administrative, selling and general 9,959 8,195 16,404
------------ ------------ ------------
Total operating expenses 416,474 408,695 452,978
------------ ------------ ------------
OPERATING INCOME 167,938 188,124 157,835
------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest and other income 5,100 5,555 16,725
Interest expense (113,247) (119,783) (126,296)
------------ ------------ ------------
Total other income (expense), net (108,147) (114,228) (109,571)
------------ ------------ ------------
NET INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE 59,791 73,896 48,264
Cumulative effect of change in method of accounting for
derivative option contracts (to April 1, 2002) (Note 2) -- 58,131 --
------------ ------------ ------------
NET INCOME $ 59,791 $ 132,027 $ 48,264
============ ============ ============
The accompanying notes are an integral part of these statements.
F-163
MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP
CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31,
(IN THOUSANDS)
GENERAL LIMITED
PARTNERS PARTNERS TOTAL
----------- ----------- -----------
BALANCE, DECEMBER 31, 2000 $ 448,100 $ 79,638 $ 527,738
Comprehensive Income
Net Income 42,020 6,244 48,264
Other Comprehensive Income
Cumulative effect of accounting change 13,688 2,034 15,722
Unrealized loss on hedging activities (42,444) (6,307) (48,751)
Reclassification adjustments recognized in net income above 7,608 1,131 8,739
----------- ----------- -----------
Total other comprehensive income (21,148) (3,142) (24,290)
----------- ----------- -----------
Total Comprehensive Income 20,872 3,102 23,974
----------- ----------- -----------
BALANCE, DECEMBER 31, 2001 $ 468,972 $ 82,740 $ 551,712
Comprehensive Income
Net Income 114,947 17,080 132,027
Other Comprehensive Income
Unrealized gain on hedging activities since beginning of period 33,311 4,950 38,261
Reclassification adjustments recognized in net income above 10,717 1,593 12,310
----------- ----------- -----------
Total other comprehensive income 44,028 6,543 50,571
----------- ----------- -----------
Total Comprehensive Income 158,975 23,623 182,598
----------- ----------- -----------
BALANCE, DECEMBER 31, 2002 $ 627,947 $ 106,363 $ 734,310
Comprehensive Income
Net Income 52,056 7,735 59,791
Other Comprehensive Income
Unrealized gain on hedging activities since beginning of period 34,484 5,125 39,609
Reclassification adjustments recognized in net income above (30,153) (4,481) (34,634)
----------- ----------- -----------
Total other comprehensive income 4,331 644 4,975
----------- ----------- -----------
Total Comprehensive Income 56,387 8,379 64,766
----------- ----------- -----------
BALANCE, DECEMBER 31, 2003 $ 684,334 $ 114,742 $ 799,076
=========== =========== ===========
The accompanying notes are an integral part of these statements.
F-164
MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31,
(IN THOUSANDS)
2003 2002 2001
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 59,791 $ 132,027 $ 48,264
Adjustments to reconcile net income to net cash provided by operating
activities
Depreciation and amortization 90,792 90,430 93,835
Cumulative effect of change in accounting principle -- (58,131) --
(Increase) decrease in accounts receivable (1,211) 48,343 55,127
(Increase) decrease in gas inventory (732) 133 (5,225)
(Increase) decrease in unamortized property taxes 683 (1,730) (415)
(Increase) decrease in broker margin accounts and prepaid expenses (4,778) 31,049 (26,587)
(Increase) decrease in derivative assets 4,906 (20,444) --
(Increase) decrease in prepaid gas costs, materials and supplies (8,704) 1,376 8,414
Increase (decrease) in accounts payable and accrued liabilities (712) 8,774 (43,704)
Increase in gas supplier funds on deposit 4,517 -- --
Decrease in interest payable (3,377) (3,948) (7,082)
Increase (decrease) in other non-current liabilities 311 (24) 245
------------ ------------ ------------
Net cash provided by operating activities 141,486 227,855 122,872
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Plant modifications and purchases of plant equipment (33,278) (29,529) (30,530)
Maturity of restricted investment securities held-to-maturity 601,225 377,192 538,327
Purchase of restricted investment securities held-to-maturity (602,279) (374,426) (539,918)
------------ ------------ ------------
Net cash used in investing activities (34,332) (26,763) (32,121)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of financing obligation (93,928) (182,084) (155,632)
------------ ------------ ------------
Net cash used in financing activities (93,928) (182,084) (155,632)
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 13,226 19,008 (64,881)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 160,425 141,417 206,298
------------ ------------ ------------
CASH AND EQUIVALENTS AT END OF PERIOD $ 173,651 $ 160,425 $ 141,417
============ ============ ============
The accompanying notes are an integral part of these statements.
F-165
MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) THE PARTNERSHIP AND ASSOCIATED RISKS
MCV was organized to construct, own and operate a combined-cycle,
gas-fired cogeneration facility (the "FACILITY") located in Midland, Michigan.
MCV was formed on January 27, 1987, and the Facility began commercial operation
in 1990.
In 1992, MCV acquired the outstanding common stock of PVCO Corp., a
previously inactive company. MCV and PVCO Corp. entered into a partnership
agreement to form MCV Gas Acquisition General Partnership ("MCV GAGP") for the
purpose of buying and selling natural gas on the spot market and other
transactions involving natural gas activities. Currently, MCV GAGP is not
actively engaged in any business activity.
The Facility has a net electrical generating capacity of approximately
1500 MW and approximately 1.5 million pounds of process steam capacity per hour.
MCV has entered into three principal energy sales agreements. MCV has contracted
to (i) supply up to 1240 MW of electric capacity ("CONTRACT CAPACITY") to
Consumers Energy Company ("CONSUMERS") under the Power Purchase Agreement
("PPA"), for resale to its customers through 2025, (ii) supply electricity and
steam to The Dow Chemical Company ("DOW") under the Steam and Electric Power
Agreement ("SEPA") through 2015 and (iii) supply steam to Dow Corning
Corporation ("DCC") under the Steam Purchase Agreement ("SPA") through 2011.
From time to time, MCV enters into other sales agreements for the sale of excess
capacity and/or energy available above MCV's internal use and obligations under
the PPA, SEPA and SPA. Results of operations are primarily dependent on
successfully operating the Facility at or near contractual capacity levels and
on Consumers' ability to perform its obligations under the PPA. Sales pursuant
to the PPA have historically accounted for over 90% of MCV's revenues.
The PPA permits Consumers, under certain conditions, to reduce the
capacity and energy charges payable to MCV and/or to receive refunds of capacity
and energy charges paid to MCV if the Michigan Public Service Commission
("MPSC") does not permit Consumers to recover from its customers the capacity
and energy charges specified in the PPA (the "REGULATORY-OUT" PROVISION). Until
September 15, 2007, however, the capacity charge may not be reduced below an
average capacity rate of 3.77 cents per kilowatt-hour for the available Contract
Capacity notwithstanding the "regulatory-out" provision. Consumers and MCV are
required to support and defend the terms of the PPA.
The Facility is a qualifying cogeneration facility ("QF") originally
certified by the Federal Energy Regulatory Commission ("FERC") under the Public
Utility Regulatory Policies Act of 1978, as amended ("PURPA"). In order to
maintain QF status, certain operating and efficiency standards must be
maintained on a calendar-year basis and certain ownership limitations must be
met. In the case of a topping-cycle generating plant such as the Facility, the
applicable operating standard requires that the portion of total energy output
that is put to some useful purpose other than facilitating the production of
power (the "THERMAL PERCENTAGE") be at least 5%. In addition, the Facility must
achieve a PURPA efficiency standard (the sum of the useful power output plus
one-half of the useful thermal energy output, divided by the energy input (the
"EFFICIENCY PERCENTAGE")) of at least 45%. If the Facility maintains a Thermal
Percentage of 15% or higher, the required Efficiency Percentage is reduced to
42.5%. Since 1990, the Facility has achieved the applicable Thermal and
Efficiency Percentages. For the twelve months ended December 31, 2003, the
Facility achieved a Thermal Percentage of 21.0% and an Efficiency Percentage of
47.4%. The loss of QF status could, among other things, cause the Facility to
lose its rights under PURPA to sell power to Consumers at Consumers' "avoided
cost" and subject the Facility to additional federal and state regulatory
requirements. MCV believes that the Facility will meet the required Thermal
Percentage and the corresponding Efficiency Percentage in 2003 and beyond, as
well as the PURPA ownership limitations.
The Facility is wholly dependent upon natural gas for its fuel supply and
a substantial portion of the Facility's operating expenses consist of the costs
of natural gas. MCV recognizes that its existing gas contracts are not
sufficient to satisfy the anticipated gas needs over the term of the PPA and, as
such, no assurance can be given as to the availability or price of natural gas
after the expiration of the existing gas contracts. In addition, to the extent
that the costs associated with production of electricity rise faster than the
energy charge payments, MCV's financial performance will be negatively affected.
The extent of such impact will depend upon the amount of the average
F-166
energy charge payable under the PPA, which is based upon costs incurred at
Consumers' coal-fired plants and upon the amount of energy scheduled by
Consumers for delivery under the PPA. However, given the unpredictability of
these factors, the overall economic impact upon MCV of changes in energy charges
payable under the PPA and in future fuel costs under new or existing contracts
cannot accurately be predicted.
At both the state and federal level, efforts continue to restructure the
electric industry. A significant issue to MCV is the potential for future
regulatory denial of recovery by Consumers from its customers of above market
PPA costs Consumers pays MCV. At the state level, the MPSC entered a series of
orders from June 1997 through February 1998 (collectively the "RESTRUCTURING
ORDERS"), mandating that utilities "wheel" third-party power to the utilities'
customers, thus permitting customers to choose their power provider. MCV, as
well as others, filed an appeal in the Michigan Court of Appeals to protect
against denial of recovery by Consumers of PPA charges. The Michigan Court of
Appeals found that the Restructuring Orders do not unequivocally disallow such
recovery by Consumers and, therefore, MCV's issues were not ripe for appellate
review and no actual controversy regarding recovery of costs could occur until
2008, at the earliest. In June 2000, the State of Michigan enacted legislation
which, among other things, states that the Restructuring Orders (being
voluntarily implemented by Consumers) are in compliance with the legislation and
enforceable by the MPSC. The legislation provides that the rights of parties to
existing contracts between utilities (like Consumers) and QFs (like MCV),
including the rights to have the PPA charges recovered from customers of the
utilities, are not abrogated or diminished, and permits utilities to securitize
certain stranded costs, including PPA charges.
In 1999, the U.S. District Court granted summary judgment to MCV declaring
that the Restructuring Orders are preempted by federal law to the extent they
prohibit Consumers from recovering from its customers any charge for avoided
costs (or "STRANDED COSTS") to be paid to MCV under PURPA pursuant to the PPA.
In 2001, the United States Court of Appeals ("APPELLATE COURT") vacated the U.S.
District Court's 1999 summary judgment and ordered the case dismissed based upon
a finding that no actual case or controversy existed for adjudication between
the parties. The Appellate Court determined that the parties' dispute is
hypothetical at this time and the QFs' (including MCV) claims are premised on
speculation about how an order might be interpreted by the MPSC, in the future.
MCV continues to monitor and participate in these industry restructuring
matters as appropriate, and to evaluate potential impacts on both cash flows and
recoverability of the carrying value of property, plant and equipment. MCV
management cannot, at this time, predict the impact or outcome of these matters.
(2) SIGNIFICANT ACCOUNTING POLICIES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Following is a discussion of MCV's significant accounting policies.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of MCV and its
wholly owned subsidiaries. All material transactions and balances among
entities, which comprise MCV, have been eliminated in the consolidated financial
statements.
REVENUE RECOGNITION
MCV recognizes revenue for the sale of variable energy and fixed energy
when delivered. Capacity and other installment revenues are recognized based on
plant availability or other contractual arrangements.
FUEL COSTS
MCV's fuel costs are those costs associated with securing natural gas,
transportation and storage services necessary to generate electricity and steam
from the Facility. These costs are recognized in the income statement
F-167
based upon actual volumes burned to produce the delivered energy. In addition,
MCV engages in certain cost mitigation activities to offset the fixed charges
MCV incurs for these activities. The gains or losses resulting from these
activities have resulted in net gains of approximately $7.7 million, $3.9
million and $5.5 million for the years ended 2003, 2002 and 2001, respectively.
These net gains are reflected as a component of fuel costs.
In July 2000, in response to rapidly escalating natural gas prices and
since Consumers electric rates were frozen, MCV entered into transactions with
Consumers whereby Consumers agreed to reduce MCV's dispatch level and MCV agreed
to share with Consumers the savings realized by not having to generate
electricity ("DISPATCH MITIGATION"). For the years ended 2003, 2002 and 2001,
MCV estimates that Dispatch Mitigation resulted in net savings of approximately
$13.0 million, $2.5 million and $7.6 million, respectively, a portion of which
will be realized in reduced maintenance expenditures in future years.
Subsequently, on January 1, 2004, Dispatch Mitigation ceased and Consumers
began dispatching MCV pursuant to the 915 MW Settlement and the 325 MW
Settlement "availability caps" provision (i.e., minimum dispatch of 1100 MW on-
and off-peak ("FORCED DISPATCH")). On February 12, 2004, MCV and Consumers
entered into a Resource Conservation Agreement ("RCA") which, among other
things, provides that Consumers will economically dispatch MCV, if certain
conditions are met. Such dispatch is expected to reduce electric production from
what would have occurred under the Forced Dispatch, as well as decrease gas
consumption by MCV. The RCA provides that Consumers has a right of first refusal
to purchase, at market prices, the gas conserved under the RCA. The RCA further
provides for the parties to enter into another agreement implementing the terms
of the RCA including the sharing of savings realized by not having to generate
electricity. The RCA is subject to MPSC approval and MCV and Consumers must
accept the terms of the MPSC order as a condition precedent to the RCA becoming
effective. The MPSC has not yet acted upon Consumers' application for approval
of the RCA. MCV cannot predict the outcome of the MPSC proceedings necessary to
effectuate the RCA.
INVENTORY
MCV's inventory of natural gas is stated at the lower of cost or market,
and valued using the last-in, first-out ("LIFO") method. Inventory includes the
costs of purchased gas, variable transportation and storage. The amount of
reserve to reduce inventories from first-in, first-out ("FIFO") basis to the
LIFO basis at December 31, 2003 and 2002, was $8.4 million and $7.4 million,
respectively. Inventory cost, determined on a FIFO basis, approximates current
replacement cost.
MATERIALS AND SUPPLIES
Materials and supplies are stated at the lower of cost or market using the
weighted average cost method. The majority of MCV's materials and supplies are
considered replacement parts for MCV's Facility.
DEPRECIATION
Original plant, equipment and pipeline were valued at cost for the
constructed assets and at the asset transfer price for purchased and contributed
assets, and are depreciated using the straight-line method over an estimated
useful life of 35 years, which is the term of the PPA, except for the hot gas
path components of the GTGs which are primarily being depreciated over a 25-year
life. Plant construction and additions, since commercial operations in 1990, are
depreciated using the straight-line method over the remaining life of the plant
which currently is 22 years. Major renewals and replacements, which extend the
useful life of plant and equipment are capitalized, while maintenance and
repairs are expensed when incurred. Major equipment overhauls are capitalized
and amortized to the next equipment overhaul. Personal property is depreciated
using the straight-line method over an estimated useful life of 5 to 15 years.
The cost of assets and related accumulated depreciation are removed from the
accounts when sold or retired, and any resulting gain or loss reflected in
operating income.
FEDERAL INCOME TAX
MCV is not subject to Federal or State income taxes. Partnership earnings
are taxed directly to each individual partner.
F-168
STATEMENT OF CASH FLOWS
All liquid investments purchased with a maturity of three months or less
at time of purchase are considered to be current cash equivalents.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts of cash and cash equivalents and short-term
investments approximate fair value because of the short maturity of these
instruments. MCV's short-term investments, which are made up of investment
securities held-to-maturity, as of December 31, 2003 and December 31, 2002 have
original maturity dates of approximately one year or less. The unique nature of
the negotiated financing obligation discussed in Note 6 makes it unnecessary to
estimate the fair value of the Owner Participants' underlying debt and equity
instruments supporting such financing obligation, since SFAS No. 107
"Disclosures about Fair Value of Financial Instruments" does not require fair
value accounting for the lease obligation.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Effective January 1, 2001, MCV adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" which was issued in June 1998 and
then amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of SFAS No. 133," SFAS No. 138
"Accounting for Certain Derivative Instruments and Certain Hedging Activities -
An amendment of FASB Statement No. 133" and SFAS No. 149 "Amendment of Statement
133 on Derivative Instruments and Hedging Activity (collectively referred to as
"SFAS NO. 133"). SFAS No. 133 establishes accounting and reporting standards
requiring that every derivative instrument be recorded on the balance sheet as
either an asset or liability measured at its fair value. SFAS No. 133 requires
that changes in a derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for
qualifying hedges in some cases allows a derivative's gains and losses to offset
related results on the hedged item in the income statement or permits
recognition of the hedge results in other comprehensive income, and requires
that a company formally document, designate and assess the effectiveness of
transactions that receive hedge accounting.
ELECTRIC SALES AGREEMENTS
MCV believes that its electric sales agreements currently do not qualify
as derivatives under SFAS No. 133, due to the lack of an active energy market
(as defined by SFAS No. 133) in the State of Michigan and the transportation
cost to deliver the power under the contracts to the closest active energy
market at the Cinergy hub in Ohio and as such does not record the fair value of
these contracts on its balance sheet. If an active energy market emerges, MCV
intends to apply the normal purchase, normal sales exception under SFAS No. 133
to its electric sales agreements, to the extent such exception is applicable.
FORWARD FOREIGN EXCHANGE CONTRACTS
An amended service agreement was entered into between MCV and Alstom Power
Company ("ALSTOM") (the "AMENDED SERVICE AGREEMENT"), under which Alstom will
provide hot gas path parts for MCV's twelve gas turbines. The payments due to
Alstom under the Amended Service Agreement are adjusted annually based on the
U.S. dollar to Swiss franc currency exchange rate.
To manage this currency exchange rate risk and hedge against adverse
currency fluctuations impacting the payments under the Amended Service
Agreement, MCV maintained a foreign currency hedging program whereby MCV
periodically entered into forward purchase contracts for Swiss francs. Under
SFAS No. 133, the forward foreign currency exchange contracts qualified as fair
value hedges, since they hedged the identifiable foreign currency commitment of
the Amended Service Agreement. As of December 31, 2003, MCV did not have any
such transactions outstanding and does not anticipate any future transactions
since the Alstom Agreement is expected to be terminated in the near future. As
of December 31, 2002, MCV had a forward purchase contract involving Swiss francs
in the notional amount of $5.0 million. This hedge was considered highly
effective, therefore, there was no material gain or loss recognized in earnings
during the twelve months ended December 31, 2002.
F-169
NATURAL GAS SUPPLY CONTRACTS
MCV management believes that its long-term natural gas contracts which do
not contain volume optionality qualify under SFAS No. 133 for the normal
purchases and normal sales exception. Therefore, these contracts are currently
not recognized at fair value on the balance sheet.
The FASB issued DIG Issue C-16, which became effective April 1, 2002,
regarding natural gas commodity contracts that combine an option component and a
forward component. This guidance requires either that the entire contract be
accounted for as a derivative or the components of the contract be separated
into two discrete contracts. Under the first alternative, the entire contract
considered together would not qualify for the normal purchases and sales
exception under the revised guidance. Under the second alternative, the newly
established forward contract could qualify for the normal purchases and sales
exception, while the option contract would be treated as a derivative under SFAS
No. 133 with changes in fair value recorded through earnings. At April 1, 2002,
MCV had nine long-term gas contracts that contained both an option and forward
component. As such, they were no longer accounted for under the normal purchases
and sales exception and MCV began mark-to-market accounting of these nine
contracts through earnings. Based on the natural gas prices, at the beginning of
April 2002, MCV recorded a $58.1 million gain for the cumulative effect of this
accounting change. During the fourth quarter of 2002, MCV removed the option
component from three of the nine long-term gas contracts, which should reduce
some of the earnings volatility. Since April 2002, MCV has recorded an
additional mark-to-market gain of $16.9 million for these gas contracts for a
cumulative mark-to-market gain through December 31, 2003 of $75.0 million, which
will reverse over the remaining life of these gas contracts, ranging from 2004
to 2007.
For the twelve months ended December 31, 2003, MCV recorded in "Fuel
costs" a $5.0 million net mark-to-market loss in earnings associated with these
contracts. In addition, as of December 31, 2003 and December 31, 2002, MCV
recorded "Derivative assets" in Current Assets in the amount of $56.9 million
and $48.9 million, respectively, and for the same periods recorded "Derivative
assets" in Other Assets in the amount of $18.1 million and $31.0 million,
respectively, representing the mark-to-market gain on these long-term natural
gas contracts.
NATURAL GAS SUPPLY FUTURES AND OPTIONS
To manage market risks associated with the volatility of natural gas
prices, MCV maintains a gas hedging program. MCV enters into natural gas futures
and option contracts in order to hedge against unfavorable changes in the market
price of natural gas in future months when gas is expected to be needed. These
financial instruments are being utilized principally to secure anticipated
natural gas requirements necessary for projected electric and steam sales, and
to lock in sales prices of natural gas previously obtained in order to optimize
MCV's existing gas supply, storage and transportation arrangements.
These financial instruments are derivatives under SFAS No. 133 and the
contracts that are utilized to secure the anticipated natural gas requirements
necessary for projected electric and steam sales qualify as cash flow hedges
under SFAS No. 133, since they hedge the price risk associated with the cost of
natural gas. MCV also engages in cost mitigation activities to offset the fixed
charges MCV incurs in operating the Facility. These cost mitigation activities
include the use of futures and options contracts to purchase and/or sell natural
gas to maximize the use of the transportation and storage contracts when it is
determined that they will not be needed for Facility operation. Although these
cost mitigation activities do serve to offset the fixed monthly charges, these
cost mitigation activities are not considered a normal course of business for
MCV and do not qualify as hedges under SFAS No. 133. Therefore, the resulting
mark-to-market gains and losses from cost mitigation activities are flowed
through MCV's earnings.
Cash is deposited with the broker in a margin account at the time futures
or options contracts are initiated. The change in market value of these
contracts requires adjustment of the margin account balances. The margin account
balance as of December 31, 2003 and December 31, 2002 was recorded as a current
asset in "Broker margin accounts and prepaid expenses," in the amount of $4.1
million and $.8 million, respectively.
For the twelve months ended December 31, 2003, MCV has recognized in other
comprehensive income, an unrealized $5.0 million increase on the futures
contracts, which are hedges of forecasted purchases for plant use of market
priced gas. This resulted in a net $31.3 million gain in other comprehensive
income as of December 31, 2003.
F-170
This balance represents natural gas futures and options with maturities ranging
from January 2004 to December 2007, of which $21.8 million of this gain is
expected to be reclassified into earnings within the next twelve months. MCV
also has recorded, as of December 31, 2003, a $29.9 million current derivative
asset in "Derivative assets," representing the mark-to-market gain on natural
gas futures for anticipated projected electric and steam sales accounted for as
hedges. In addition, for the twelve months ended December 31, 2003, MCV has
recorded a net $35.0 million gain in earnings included in fuel costs from
hedging activities related to MCV natural gas requirements for Facility
operations and a net $1.0 million gain in earnings from cost mitigation
activities.
For the twelve months ended December 31, 2002, MCV recognized an
unrealized $50.6 million increase in other comprehensive income on the futures
contracts, which are hedges of forecasted purchases for plant use of market
priced gas, resulting in a $26.3 million gain balance in other comprehensive
income as of December 31, 2002. As of December 31, 2002, MCV had recorded a
$24.9 million current derivative asset in "Derivative assets." For the twelve
months ended December 31, 2002, MCV had recorded a net $12.2 million loss in
earnings from hedging activities related to MCV natural gas requirements for
Facility operations and a net $.4 million gain in earnings from cost mitigation
activities.
INTEREST RATE SWAPS
To manage the effects of interest rate volatility on interest income while
maximizing return on permitted investments, MCV established an interest rate
hedging program. The notional amounts of the hedges are tied directly to MCV's
anticipated cash investments, without physically exchanging the underlying
notional amounts. Cash is deposited with the broker in a margin account at the
time the interest rate swap transactions are initiated. The change in market
value of these contracts may require further adjustment of the margin account
balance. The margin account balance at December 31, 2002, of approximately
$25,000, which was recorded as a current asset in "Broker margin accounts and
prepaid expenses," was returned to MCV during the month of January 2003 since
MCV currently does not have any outstanding interest rate swap transactions.
As of December 31, 2002, MCV had one interest rate swap, with a notional
amount of $20.0 million with a period of performance that extended to December
1, 2002, which did not qualify as a hedge under SFAS No. 133. The gains and
losses on this swap were recorded currently in earnings. For the twelve months
ended December 31, 2002, MCV recorded an immaterial loss in earnings.
RECLASSIFICATION
Certain prior period amounts have been reclassified to conform to the
current year financial statement presentation.
NEW ACCOUNTING STANDARDS
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133
on Derivative Instruments and Hedging Activities." This SFAS amends SFAS No. 133
for decisions made (1) as part of the Derivative Implementations Group process
that effectively required amendments to SFAS No. 133, (2) for other Financial
Accounting Standards Board projects dealing with financial instruments and (3)
for implementation issues raised in relation to the application of this
definition of a derivative. The changes in this SFAS No. 149 improve financial
reporting by requiring that contracts with comparable characteristics be
accounted for similarly, which will result in more consistent reporting of
contracts as either derivatives or hybrid instruments. This standard is
effective for contracts entered into or modified after June 30, 2003, with some
exceptions. MCV has adopted this standard and does not expect the application to
materially affect its financial position or results of operations.
(3) RESTRICTED INVESTMENT SECURITIES HELD-TO-MATURITY
Non-current restricted investment securities held-to-maturity have
carrying amounts that approximate fair value because of the short maturity of
these instruments and consist of the following at December 31 (in thousands):
2003 2002
----------- -----------
Funds restricted for rental payments pursuant to the
Overall Lease Transaction $ 137,296 $ 136,554
Funds restricted for management non-qualified plans 2,459 2,147
----------- -----------
Total $ 139,755 $ 138,701
=========== ===========
F-171
(4) ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Accounts payable and accrued liabilities consist of the following at
December 31 (in thousands):
2003 2002
---------- ----------
Accounts payable
Related parties $ 7,386 $ 12,224
Trade creditors 34,786 27,935
Property and single business taxes 12,548 14,842
Other 2,648 3,079
---------- ----------
Total $ 57,368 $ 58,080
========== ==========
(5) GAS SUPPLIER FUNDS ON DEPOSIT
Pursuant to individual gas contract terms with counterparties, deposit
amounts may be required by one party to the other based upon the net amount of
exposure. The net amount of exposure will vary with changes in market prices,
credit provisions and various other factors. Collateral paid or received will be
posted by one party to the other based upon the net amount of exposure. The net
amount of exposure will vary with changes in market prices, credit provisions
and various other factors. Collateral paid or received will be posted by one
party to the other based on the net amount of the exposure. Interest is earned
on funds on deposit. As of December 31, 2003 MCV was not supplying any credit
support in the form of cash or letters of credit. As of December 31, 2003 MCV
was holding $4.5 million of cash on deposit and letters of credit totaling
$116.6 million from two gas suppliers as collateral support.
(6) LONG-TERM DEBT
Long-term debt consists of the following at December 31 (in thousands):
2003 2002
------------- -------------
Financing obligation, maturing through 2015, payable in semi-
annual installments of principal and interest, collateralized
by property, plant and equipment $ 1,153,221 $ 1,247,149
Less current portion (134,576) (93,928)
------------- -------------
Total long-term debt $ 1,018,645 $ 1,153,221
============= =============
FINANCING OBLIGATION
In June 1990, MCV obtained permanent financing for the Facility by
entering into sale and leaseback agreements ("OVERALL LEASE TRANSACTION") with a
lessor group, related to substantially all of MCV's fixed assets. Proceeds of
the financing were used to retire borrowings outstanding under existing loan
commitments, make a capital distribution to the Partners and retire a portion of
notes issued by MCV to MEC Development Corporation ("MDC") in connection with
the transfer of certain assets by MDC to MCV. In accordance with SFAS No. 98,
"Accounting For Leases," the sale and leaseback transaction has been accounted
for as a financing arrangement.
The financing obligation utilizes the effective interest rate method,
which is based on the minimum lease payments required through the end of the
basic lease term of 2015 and management's estimate of additional anticipated
obligations after the end of the basic lease term. The effective interest rate
during the remainder of the basic lease term is approximately 9.4%.
Under the terms of the Overall Lease Transaction, MCV sold undivided
interests in all of the fixed assets of the Facility for approximately $2.3
billion, to five separate owner trusts ("OWNER TRUSTS") established for the
benefit of certain institutional investors ("OWNER PARTICIPANTS"). U.S. Bank
National Association (formerly known as State Street Bank and Trust Company)
serves as owner trustee ("OWNER TRUSTEE") under each of the Owner Trusts, and
leases undivided interests in the Facility on behalf of the Owner Trusts to MCV
for an initial term of 25 years. CMS
F-172
Midland Holdings Company ("CMS HOLDINGS"), currently a wholly owned subsidiary
of Consumers, acquired a 35% indirect equity interest in the Facility through
its purchase of an interest in one of the Owner Trusts.
The Overall Lease Transaction requires MCV to achieve certain rent
coverage ratios and other financial tests prior to a distribution to the
Partners. Generally, these financial tests become more restrictive with the
passage of time. Further, MCV is restricted to making permitted investments and
incurring permitted indebtedness as specified in the Overall Lease Transaction.
The Overall Lease Transaction also requires filing of certain periodic operating
and financial reports, notification to the lessors of events constituting a
material adverse change, significant litigation or governmental investigation,
and change in status as a qualifying facility under FERC proceedings or court
decisions, among others. Notification and approval is required for plant
modification, new business activities, and other significant changes, as
defined. In addition, MCV has agreed to indemnify various parties to the sale
and leaseback transaction against any expenses or environmental claims asserted,
or certain federal and state taxes imposed on the Facility, as defined in the
Overall Lease Transaction.
Under the terms of the Overall Lease Transaction and refinancing of the
tax-exempt bonds, approximately $25.0 million of transaction costs were a
liability of MCV and have been recorded as a deferred cost. Financing costs
incurred with the issuance of debt are deferred and amortized using the interest
method over the remaining portion of the 25-year lease term. Deferred financing
costs of approximately $1.4 million, $1.5 million and $1.7 million were
amortized in the years 2003, 2002 and 2001, respectively.
Interest and fees incurred related to long-term debt arrangements during
2003, 2002 and 2001 were $111.9 million, $118.3 million and $124.6 million,
respectively.
Interest and fees paid during 2003, 2002 and 2001 were $115.4 million,
$122.1 million and $131.7 million, respectively.
Minimum payments due under these long-term debt arrangements over the next
five years are (in thousands):
PRINCIPAL INTEREST TOTAL
----------- ---------- -----------
2004 $ 134,576 $ 108,233 $ 242,809
2005 76,547 97,836 174,383
2006 63,459 92,515 155,974
2007 62,916 87,988 150,904
2008 67,753 83,163 150,916
----------- ---------- -----------
$ 405,251 $ 469,735 $ 874,986
=========== ========== ===========
REVOLVING CREDIT AGREEMENT
MCV has also entered into a working capital line ("WORKING CAPITAL
FACILITY"), which expires August 29, 2004. Under the terms of the existing
agreement, MCV can borrow up to the $50 million commitment, in the form of
short-term borrowings or letters of credit collateralized by MCV's natural gas
inventory and earned receivables. At any given time, borrowings and letters of
credit are limited by the amount of the borrowing base, defined as 90% of earned
receivables and 50% of natural gas inventory, capped at $15 million. During
2003, MCV did not utilize the Working Capital Facility. At December 31, 2003,
MCV had no outstanding borrowings or letters of credit.
INTERCREDITOR AGREEMENT
MCV has also entered into an Intercreditor Agreement with the Owner
Trustee, Working Capital Lender, U.S. Bank National Association as Collateral
Agent ("COLLATERAL AGENT") and the Senior and Subordinated Indenture Trustees.
Under the terms of this agreement, MCV is required to deposit all revenues
derived from the operation of the Facility with the Collateral Agent for
purposes of paying operating expenses and rent. In addition, these funds are
required to pay construction modification costs and to secure future rent
payments. As of December 31, 2003, MCV has deposited $137.3 million into the
reserve account. The reserve account is to be maintained at not less than $40
million nor more than $137 million (or debt portion of next succeeding basic
rent payment, whichever is greater). Excess funds in the reserve account are
periodically transferred to MCV. This agreement also contains provisions
governing the distribution of revenues and rents due under the Overall Lease
Transaction, and establishes
F-173
the priority of payment among the Owner Trusts, creditors of the Owner Trusts,
creditors of MCV and the Partnership.
(7) COMMITMENTS AND OTHER AGREEMENTS
MCV has entered into numerous commitments and other agreements related to
the Facility. Principal agreements are summarized as follows: Power Purchase
Agreement
MCV and Consumers have executed the PPA for the sale to Consumers of a
minimum amount of electricity, subject to the capacity requirements of Dow and
any other permissible electricity purchasers. Consumers has the right to
terminate and/or withhold payment under the PPA if the Facility fails to achieve
certain operating levels or if MCV fails to provide adequate fuel assurances. In
the event of early termination of the PPA, MCV would have a maximum liability of
approximately $270 million if the PPA were terminated in the 12th through 24th
years. The term of this agreement is 35 years from the commercial operation date
and year-to-year thereafter.
STEAM AND ELECTRIC POWER AGREEMENT
MCV and Dow executed the SEPA for the sale to Dow of certain minimum
amounts of steam and electricity for Dow's facilities.
If the SEPA is terminated, and Consumers does not fulfill MCV's
commitments as provided in the Backup Steam and Electric Power Agreement, MCV
will be required to pay Dow a termination fee, calculated at that time, ranging
from a minimum of $60 million to a maximum of $85 million. This agreement
provides for the sale to Dow of steam and electricity produced by the Facility
for terms of 25 years and 15 years, respectively, commencing on the commercial
operation date and year-to-year thereafter.
STEAM PURCHASE AGREEMENT
MCV and DCC executed the SPA for the sale to DCC of certain minimum
amounts of steam for use at the DCC Midland site. Steam sales under the SPA
commenced in July 1996. Termination of this agreement, prior to expiration,
requires the terminating party to pay to the other party a percentage of future
revenues, which would have been realized had the initial term of 15 years been
fulfilled. The percentage of future revenues payable is 50% if termination
occurs prior to the fifth anniversary of the commercial operation date and
33-1/3% if termination occurs after the fifth anniversary of this agreement. The
term of this agreement is 15 years from the commercial operation date of steam
deliveries under the contract and year-to-year thereafter.
GAS SUPPLY AGREEMENTS
MCV has entered into gas purchase agreements with various producers for
the supply of natural gas. The current contracted volume totals 227,561 MMBtu
per day annual average for 2004. As of January 1, 2004, gas contracts with U.S.
suppliers provide for the purchase of 149,423 MMBtu per day while gas contracts
with Canadian suppliers provide for the purchase of 78,138 MMBtu per day. Some
of these contracts require MCV to pay for a minimum amount of natural gas per
year, whether or not taken. The estimated minimum commitments under these
contracts based on current long term prices for gas for the years 2004 through
2008 are $267.3 million, $338.6 million, $344.1 million, $340.4 million and
$283.9 million, respectively. A portion of these payments may be utilized in
future years to offset the cost of quantities of natural gas taken above the
minimum amounts.
GAS TRANSPORTATION AGREEMENTS
MCV has entered into firm natural gas transportation agreements with
various pipeline companies. These agreements require MCV to pay certain
reservation charges in order to reserve the transportation capacity.
MCV incurred reservation charges in 2003, 2002 and 2001, of $34.8 million,
$35.1 million and $36.2 million, respectively. The estimated minimum reservation
charges required under these agreements for each of the years 2004 through 2008
are $34.9 million, $33.8 million, $30.0 million, $21.6 million and $21.6
million, respectively. These projections are based on current commitments.
F-174
GAS TURBINE SERVICE AGREEMENT
MCV entered into a Service Agreement, as amended, with Alstom, which
commenced on January 1, 1990 and was set to expire upon the earlier of the
completion of the sixth series of major GTG inspections or December 31, 2009.
Under the terms of this agreement, Alstom sold MCV an initial inventory of spare
parts for the GTGs and provides qualified service personnel and supporting staff
to assist MCV, to perform scheduled inspections on the GTGs, and to repair the
GTGs at MCV's request. Upon termination of the Service Agreement (except for
nonperformance by Alstom), MCV must pay a cancellation payment. MCV and Alstom
amended the Service Agreement, effective December 31, 1993, to include the
supply of hot gas path parts. Under the amended Service Agreement, Alstom
provides hot gas path parts for MCV's twelve gas turbines through the fourth
series of major GTG inspections, which were completed in 2002. In January 1998,
MCV and Alstom amended the length of the amended Service Agreement to extend
through the sixth series of major GTG inspections, which are expected to be
completed by year end 2008, for a lump sum fixed price covering the entire term
of the amended Service Agreement of $266.5 million (in 1993 dollars, which is
adjusted based on exchange rates and Swiss inflation indices), payable on the
basis of operating hours as they occur over the same period. MCV has made
payments totaling approximately $200.7 million under this amended Service
Agreement through December 31, 2003.
MCV signed a new maintenance service and parts agreement with General
Electric International, Inc. ("GEII"), effective December 31, 2002 ("GEII
Agreement"). GEII will provide maintenance services and hot gas path parts for
MCV's twelve GTG's. Under terms and conditions similar to the MCV/Alstom Service
Agreement, as described above the GEII Agreement will cover four rounds of major
GTG inspections, which are expected to be completed by the year 2015, at a
savings to MCV as compared to the Service Agreement with Alstom. The GEII
Agreement is expected to replace the current Alstom Service Agreement commencing
July 1, 2004. The GEII Agreement can be terminated by either party for cause or
convenience. Should termination for convenience occur, a buy out amount will be
paid by the terminating party with payments ranging from approximately $19.0
million to $.9 million, based upon the number of operating hours utilized since
commencement of the GEII Agreement.
MCV terminated the Alstom Service Agreement in February 2004, for cause
and therefore does not owe the approximately $5.8 million termination payment to
Alstom. MCV has a claim against Alstom for approximately $3.0 million for
adjustments due to reduced equivalent operating hours experienced under the
Service Agreement, that was paid by MCV and a claim against Alstom for one set
of hot gas path spare parts (valued within a range of $3.0 million to $7.0
million). These matters may be disputed by Alstom and other disputes may arise.
MCV will seek final resolution of all claims that may arise between the parties.
At this time, MCV has not recognized any liability to or receivable from Alstom
in connection with these claims or termination.
STEAM TURBINE SERVICE AGREEMENT
MCV entered into a nine year Steam Turbine Maintenance Agreement with
General Electric Company effective January 1, 1995, which is designed to improve
unit reliability, increase availability and minimize unanticipated maintenance
costs. In addition, this contract includes performance incentives and penalties,
which are based on the length of each scheduled outage and the number of forced
outages during a calendar year. Effective February 1, 2004, MCV and GE amended
this contract to extend its term through August 31, 2007. MCV will continue
making monthly payments over the life of the contract, which will total $22.3
million (subject to escalation based on defined indices). The parties have
certain termination rights without incurring penalties or damages for such
termination. Upon termination, MCV is only liable for payment of services
rendered or parts provided prior to termination.
SITE LEASE
In December 1987, MCV leased the land on which the Facility is located
from Consumers ("SITE LEASE"). MCV and Consumers amended and restated the Site
Lease to reflect the creation of five separate undivided interests in the Site
Lease as of June 1, 1990. Pursuant to the Overall Lease Transaction, MCV
assigned these undivided interests in the Site Lease to the Owner Trustees,
which in turn subleased the undivided interests back to MCV under five separate
site subleases.
F-175
The Site Lease is for a term which commenced on December 29, 1987, and
ends on December 31, 2035, including two renewal options of five years each. The
rental under the Site Lease is $.6 million per annum, including the two
five-year renewal terms.
GAS TURBINE GENERATOR COMPRESSOR BLADE AGREEMENT
MCV entered into an agreement with MTS Machinery Tools & Services AG
("MTS"), in January 2002. Under this agreement MTS redesigned and will
manufacture and install new design compressor blades for MCV's twelve GTG's,
which is expected to increase the overall electrical capacity and efficiency of
each GTG. MCV has purchased three sets of such blades and has the option to
purchase an additional nine sets. The first set of compressor blades was
installed in the second quarter of 2003 for approximately $4.2 million. At this
time, an additional two sets have been ordered at a cost of $4.1 million.
(8) PROPERTY TAXES
In 1997, MCV filed a property tax appeal against the City of Midland at
the Michigan Tax Tribunal contesting MCV's 1997 property taxes. Subsequently,
MCV filed appeals contesting its property taxes for tax years 1998 through 2003
at the Michigan Tax Tribunal. A trial was held for tax years 1997 - 2000. The
appeals for tax years 2001-2003 are being held in abeyance. On January 23, 2004,
the Michigan Tax Tribunal issued its decision in MCV's tax appeal against the
City of Midland for tax years 1997 through 2000. MCV management has estimated
that the decision will result in a refund to MCV for the tax years 1997 through
2000 of approximately $29 million in taxes plus $7 million of interest. The
decision is subject to reconsideration at the Tribunal and may be appealed to
the Michigan Appellate Court and Michigan Supreme Court. The City of Midland has
filed a motion for reconsideration at the Michigan Tax Tribunal, asking the
Tribunal to make certain technical corrections, as well as substantive changes
to the decision. MCV has opposed this motion. MCV management cannot predict the
outcome of these further legal proceedings. MCV has not recognized any of the
above stated refunds (net of approximately $15.5 million of deferred expenses)
in earnings at this time.
(9) RETIREMENT BENEFITS
POSTRETIREMENT HEALTH CARE PLANS
In 1992, MCV established defined cost postretirement health care plans
("PLANS") that cover all full-time employees, excluding key management. The
Plans provide health care credits, which can be utilized to purchase medical
plan coverage and pay qualified health care expenses. Participants become
eligible for the benefits if they retire on or after the attainment of age 65 or
upon a qualified disability retirement, or if they have 10 or more years of
service and retire at age 55 or older. The Plans granted retroactive benefits
for all employees hired prior to January 1, 1992. This prior service cost has
been amortized to expense over a five year period. MCV annually funds the
current year service and interest cost as well as amortization of prior service
cost to both qualified and non-qualified trusts. The MCV accounts for retiree
medical benefits in accordance with SFAS 106, "Employers Accounting for
Postretirement Benefits Other Than Pensions." This standard required the full
accrual of such costs during the years that the employee renders service to the
MCV until the date of full eligibility. The accumulated benefit obligation of
the Plans were $3.3 million at December 31, 2003 and $2.7 million at December
31, 2002. The measurement date of these Plans was December 31, 2003.
On December 8, 2003, President Bush signed into law the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 (the "ACT"). The
Act expanded Medicare to include, for the first time, coverage for prescription
drugs. At this time, because of various uncertainties related to this
legislation and the appropriate accounting methodology, MCV has elected to defer
financial recognition of this legislation until the FASB issues final accounting
guidance. When issued, that final guidance could require MCV to change
previously reported information. This deferral election is permitted under SFAS
106-1.
F-176
The following table reconciles the change in the Plans' benefit obligation
and change in Plan assets as reflected on the balance sheet as of December 31
(in thousands):
2003 2002
----------- -----------
Change in benefit obligation:
Benefit obligation at beginning of year $ 2,741.9 $ 2,405.1
Service cost 212.5 197.3
Interest cost 178.2 188.7
Actuarial gain (loss) 147.4 (44.6)
Benefits paid during year (4.0) (4.6)
----------- -----------
Benefit obligation at end of year 3,276.0 2,741.9
----------- -----------
Change in Plan assets:
Fair value of Plan assets at beginning of year 2,045.8 2,088.0
Actual return on Plan assets 527.5 (270.9)
Employer contribution 257.5 233.3
Benefits paid during year (4.0) (4.6)
----------- -----------
Fair value of Plan assets at end of year 2,826.8 2,045.8
----------- -----------
Unfunded (funded) status 449.2 696.1
Unrecognized prior service cost (170.3) (184.6)
Unrecognized net gain (loss) (278.9) (511.5)
----------- -----------
Accrued benefit cost $ -- $ --
=========== ===========
Net periodic postretirement health care cost for years ending December 31,
included the following components (in thousands):
2003 2002 2001
---------- ---------- ----------
Components of net periodic benefit cost:
Service cost $ 212.5 $ 197.3 $ 173.5
Interest cost 178.2 188.7 142.9
Expected return on Plan assets (163.7) (167.0) (171.3)
Amortization of unrecognized net (gain)
or loss 30.5 14.3 (12.6)
---------- ---------- ----------
Net periodic benefit cost $ 257.5 $ 233.3 $ 132.5
========== ========== ==========
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percentage-point change in
assumed health care cost trend rates would have the following effects (in
thousands):
1-PERCENTAGE-POINT 1-PERCENTAGE-POINT
INCREASE DECREASE
------------------ ------------------
Effect on total of service and
interest cost components $ 48.6 $ 41.8
Effect on postretirement
benefit obligation $ 358.1 $ 310.9
Assumptions used in accounting for the Post-Retirement Health Care Plan
were as follows:
2003 2002 2001
---- ---- ----
Discount rate 6.00% 6.75% 7.25%
Long-term rate of return on Plan
assets 8.00% 8.00% 8.00%
Inflation benefit amount
1998 through 2004 0.00% 0.00% 0.00%
2005 and later years 4.00% 4.00% 4.00%
The long-term rate of return on Plan assets is established based on MCV's
expectations of asset returns for the investment mix in its Plan (with some
reliance on historical asset returns for the Plans). The expected returns for
various asset categories are blended to derive one long-term assumption.
F-177
PLAN ASSETS. Citizens Bank has been appointed as trustee ("TRUSTEE") of
the Plan. The Trustee serves as investment consultant, with the responsibility
of providing financial information and general guidance to the MCV Benefits
Committee. The Trustee shall invest the assets of the Plan in the separate
investment options in accordance with instructions communicated to the Trustee
from time to time by the MCV Benefit Committee. The MCV Benefits Committee has
the fiduciary and investment selection responsibility for the Plan. The MCV
Benefits Committee consists of MCV Officers (excluding the President and Chief
Executive Officer).
The MCV has a target allocation of 80% equities and 20% debt instruments.
These investments emphasis total growth return, with a moderate risk level. The
MCV Benefits Committee reviews the performance of the Plan investments
quarterly, based on a long-term investment horizon and applicable benchmarks,
with rebalancing of the investment portfolio, at the discretion of the MCV
Benefits Committee.
MCV's Plan's weighted-average asset allocations, by asset category are as
follows as of December 31:
2003 2002
---- ----
Asset Category:
Cash and cash equivalents 11% 1%
Fixed income 17% 23%
Equity securities 72% 76%
---- ----
Total 100% 100%
---- ----
CONTRIBUTIONS. MCV expects to contribute approximately $.2 million to the
Plan in 2004.
RETIREMENT AND SAVINGS PLANS
MCV sponsors a defined contribution retirement plan covering all
employees. Under the terms of the plan, MCV makes contributions to the plan of
either five or ten percent of an employee's eligible annual compensation
dependent upon the employee's age. MCV also sponsors a 401(k) savings plan for
employees. Contributions and costs for this plan are based on matching an
employee's savings up to a maximum level. In 2003, 2002 and 2001, MCV
contributed $1.3 million, $1.2 million and $1.1 million, respectively under
these plans.
SUPPLEMENTAL RETIREMENT BENEFITS
MCV provides supplemental retirement, postretirement health care and
excess benefit plans for key management. These plans are not qualified plans
under the Internal Revenue Code; therefore, earnings of the trusts maintained by
MCV to fund these plans are taxable to the Partners and trust assets are
included in the assets of MCV.
F-178
MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(CONTINUED)
(10) PARTNERS' EQUITY AND RELATED PARTY TRANSACTIONS
The following table summarizes the nature and amount of each of MCV's
Partner's equity interest, interest in profits and losses of MCV at December 31,
2003, and the nature and amount of related party transactions or agreements that
existed with the Partners or affiliates as of December 31, 2003, 2002 and 2001,
and for each of the twelve month periods ended December 31 (in thousands).
BENEFICIAL OWNER, EQUITY PARTNER, RELATED PARTY
TYPE OF PARTNER AND NATURE EQUITY TRANSACTIONS AND
OF RELATED PARTY INTEREST INTEREST AGREEMENTS 2003 2002 2001
------------------------------------- ---------- -------- --------------------- --------- --------- ----------
CMS ENERGY COMPANY
Power purchase
CMS Midland, Inc. agreements $ 513,774 $ 557,149 $ 550,477
General Partner; wholly-owned Purchases under gas
subsidiary of Consumers Energy transportation
Company agreements 14,294 23,552 24,059
Purchases under
spot gas agreements 663 3,631 3,756
Purchases under gas
supply agreements 2,330 11,306 10,725
Gas storage agreement 2,563 2,563 2,563
Land lease/easement
agreements 600 600 600
Accounts receivable 40,373 44,289 48,843
Accounts payable 1,025 3,502 4,772
Sales under spot
$ 391,546 49.0% gas agreements 3,260 1,084 7,107
========== ======
El Paso Corporation
Source Midland Limited Partnership
("SMLP") General Partner; owned by
subsidiaries of El Paso Corporation(1)
Purchase under gas
transportation
agreements 13,023 12,463 13,653
Purchases under
spot gas agreement 610 15,655 45,130
Purchases under gas
supply agreement 54,308 47,136 5,912
Gas agency agreement 238 365 1,989
Deferred
reservation charges
under gas purchase
agreement 4,728 -- 7,880
Accounts receivable -- 523 --
Accounts payable 5,751 7,706 5,198
Sales under spot
gas agreements 3,474 14,007 28,451
Partner cash
withdrawal
(including accrued
$ 139,421 18.1% interest)(2) -- -- 56,714
El Paso Midland, Inc. ("EL PASO See related party
MIDLAND") General Partner; activity listed
wholly-owned subsidiary of El under SMLP.
Paso Corporation(1)
83,653 10.9
See related party
activity listed
MEI Limited Partnership ("MEI") under SMLP.
A General and Limited Partner; 50%
interest owned by El Paso Midland,
Inc. and 50% interest owned by SMLP(1)
General Partnership Interest 69,714 9.1
Limited Partnership Interest 6,969 .9
See related party
activity listed
Micogen Limited Partnership 34,854 4.5 under SMLP.
F-179
("MLP") Limited Partner, owned
subsidiaries of El Paso
Corporation(1)
Total El Paso
---------- ------
Corporation $ 334,611 43.5%
========== ======
The Dow Chemical Company
Steam and electric
The Dow Chemical Company power agreement 36,207 29,385 33,727
Steam purchase
agreement - Dow
Corning Corp
Limited Partner (affiliate) 4,017 3,746 3,781
Purchases under
demineralized water
supply agreement 6,396 6,605 6,913
Accounts receivable 3,431 3,635 3,191
Accounts payable 610 1,016 948
Standby and backup
fees 731 734 696
Sales of gas under
$ 72,918 7.5% tolling agreement -- 6,442 --
========== ======
Alanna Corporation
Alanna Corporation Note receivable 1 1 1
Limited Partner; wholly-owned
subsidiary of Alanna Holdings
Corporation $ 1(3) .00001%
========== ======
FOOTNOTES TO PARTNERS' EQUITY AND RELATED PARTY TRANSACTIONS
(1) On January 29, 2001, El Paso Corporation ("EL PASO") announced that it had
completed its merger with The Coastal Corporation ("COASTAL"). Coastal was
the previous parent company of El Paso Midland (formerly known as Coastal
Midland, Inc.), SMLP, MLP and, through SMLP, MEI. After the merger,
Coastal became a wholly-owned subsidiary of El Paso and has changed its
name to El Paso CGP Company.
(2) A letter of credit has been issued and recorded as a note receivable from
El Paso Midland, this amount includes their share of cash available, as
well as, cash available to MEI, MLP and SMLP.
(3) Alanna's capital stock is pledged to secure MCV's obligation under the
lease and other overall lease transaction documents.
SUPPLEMENTAL INFORMATION
Supplemental information is to be furnished with reports filed pursuant to
Section 15 (d) of the Act by registrants, which have not registered securities
pursuant to Section 12 of the Act. No such annual report or proxy statement has
been sent to security holders.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP
Date: March 1, 2004
By /s/ James M. Kevra
---------------------
James M. Kevra
President and Chief Executive Officer
F-180
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
SIGNATURE TITLE DATE
--------------------- --------------------------------------- -------------
/s/ James M. Kevra President and Chief Executive Officer March 1, 2004
------------------
_____________________ (Principal Executive Officer)
James M. Kevra
/s/ James M. Rajewski Chief Financial Officer, Vice President March 1, 2004
---------------------
_____________________ and Controller (Principal Accounting
James M. Rajewski Officer)
/s/ John J. O'Rourke Chairman, Management Committee March 1, 2004
--------------------
John J. O'Rourke
/s/ David W. Joos Member, Management Committee March 1, 2004
-----------------
David W. Joos
F-181
EMIRATES CMS POWER COMPANY PJSC
FINANCIAL STATEMENTS
F-182
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTNG FIRM
TO THE BOARD OF DIRECTORS OF
EMIRATES CMS POWER COMPANY PJSC
We have audited the accompanying balance sheet of Emirates CMS Power
Company Private Joint Stock Company ("the Company") as of 31 December 2003 and
the related statements of income, cash flows and stockholders' equity for the
year then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of the Company as of 31
December 2003, and the results of its operations and its cash flows for the year
then ended in conformity with US generally accepted accounting principles.
/S/ Ernst & Young
Abu Dhabi, United Arab Emirates
27 June 2004
F-183
EMIRATES CMS POWER COMPANY PJSC
BALANCE SHEETS
31 December 2003 and 2002
UNAUDITED
NOTES 2003 2002
AED `000 AED `000
ASSETS
Current assets
Cash and cash equivalents 120,300 124,278
Prepayments and other current assets 4 25,074 10,933
Amounts due from related party 5 38,799 37,986
Advance to Al Taweelah Shared Facilities Company LLC 6 1,747 1,800
Inventories 7 166,734 160,247
---------- ---------
352,654 335,244
---------- ---------
NON-CURRENT ASSETS
Advance to Al Taweelah Shared Facilities Company LLC 6 34,058 35,674
Other long term asset 5,173 -
Investment 9 178 178
Property, plant and equipment, net 8 2,242,212 2,291,152
Intangible asset, net 10 106,720 109,683
---------- ---------
2,388,341 2,436,687
---------- ---------
TOTAL ASSETS 2,740,995 2,771,931
========== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Trade accounts payable 2,847 962
Amounts due to related parties 11 3,477 2,424
Accruals and other liabilities 12 346,690 388,346
Current portion of long term debt 13 58,631 81,676
Current portion of loan from shareholders 14 129,000 -
---------- ---------
540,645 473,408
---------- ---------
NON-CURRENT LIABILITIES
Asset retirement obligation 15,403 -
Loan from shareholders 14 131,000 272,000
Long term debt 13 1,769,539 1,828,171
---------- ---------
1,915,942 2,100,171
---------- ---------
TOTAL LIABILITIES 2,456,587 2,573,579
---------- ---------
STOCKHOLDERS' EQUITY
Share capital (ordinary shares, AED 10 par value,
authorised, issued and outstanding 41,324,000 shares) 15 413,240 413,240
Accumulated losses 15 (147,665) (237,512)
Accumulated other comprehensive income 18 18,833 22,624
---------- ---------
TOTAL STOCKHOLDERS' EQUITY 284,408 198,352
---------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY 2,740,995 2,771,931
========== =========
The attached notes 1 to 21 form part of these financial statements.
F-184
EMIRATES CMS POWER COMPANY PJSC
INCOME STATEMENTS
Years ended 31 December 2003, 2002 and 2001
UNAUDITED UNAUDITED
2003 2002 2001
NOTES AED `000 AED `000 AED `000
Revenue 363,564 370,686 196,091
-------- --------- ---------
Cost of sales
Contractors' staff costs (14,149) (14,297) (13,982)
Repairs, maintenance and consumables used (47,095) (36,262) (42,046)
Depreciation (63,591) (63,402) (35,370)
Amortisation of intangible asset 10 (2,963) (2,940) -
-------- --------- ---------
(127,798) (116,901) (91,398)
-------- --------- ---------
GROSS PROFIT 235,766 253,785 104,693
Administrative and other operating expenses 20 (8,087) (7,925) (4,821)
-------- --------- ---------
INCOME FROM OPERATIONS 227,679 245,860 99,872
Financing cost (119,730) (124,163) (57,835)
Accretion expense (872) - -
Interest income 784 1,848 783
Changes in fair value of derivative instruments 18 55,867 (199,093) (108,536)
Other income (expense) 1,084 704 (33)
-------- --------- ---------
NET INCOME (LOSS) BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES 164,812 (74,844) (65,749)
Cumulative effect of change in accounting for derivatives 18 - - (21,477)
Cumulative effect of change in accounting for
asset retirement obligation (1,165) - -
-------- --------- ---------
NET INCOME (LOSS) 163,647 (74,844) (87,226)
======== ========= =========
The attached notes 1 to 21 form part of these financial statements.
F-185
EMIRATES CMS POWER COMPANY PJSC
STATEMENTS OF CASH FLOWS
Years ended 31 December 2003, 2002 and 2001
UNAUDITED UNAUDITED
2003 2002 2001
NOTES AED `000 AED `000 AED `000
OPERATING ACTIVITIES
Net income (loss) 163,647 (74,844) (87,226)
Adjustments to reconcile net income (loss)
to net cash provided by (used in) operating activities:
Depreciation and amortisation of intangible asset 66,554 66,342 35,370
Accretion expense 872 - -
Changes in fair value of derivative instruments (55,867) 199,093 108,536
Reclassification from accumulated other comprehensive
income to earnings of cash flow hedges (3,791) (3,955) (4,098)
Cumulative effect of change in accounting principles 1,165 - 21,477
Loss on disposal of property, plant and equipment 14 173 -
Changes in assets and liabilities:
Increase in inventories (6,487) (63,623) (53,137)
(Increase) decrease in amounts due from related parties (813) 21,064 (39,852)
Increase in prepayments and other current assets (5,644) 17,742 (6,313)
(Increase) decrease in accounts payable and accruals
and due to related parties 8,652 (30,980) (186,208)
-------- -------- --------
Net cash provided by (used in) operating activities 168,302 131,012 (211,451)
-------- -------- --------
INVESTING ACTIVITIES
Purchase of property, plant and equipment (1,299) (2,090) (400,832)
Liquidated damages received (paid) - 10,846 (6,556)
Recovery of advance to
Al Taweelah Shared Facilities Company LLC 1,669 1,669 1,799
-------- -------- --------
Net cash from (used in) investing activities 370 10,425 (405,589)
-------- -------- --------
FINANCING ACTIVITIES
Dividends paid (73,800) (79,400) -
Long term debt refinancing fees paid (5,173) - -
Repayment of loan from shareholders (12,000) - -
(Repayment) receipt of term loan (81,677) (71,467) 734,041
-------- -------- --------
Cash (used in) from financing activities (172,650) (150,867) 734,041
-------- -------- --------
(DECREASE) INCREASE IN CASH
AND CASH EQUIVALENTS (3,978) (9,430) 117,001
Cash and cash equivalents at the beginning of the year 124,278 133,708 16,707
-------- -------- --------
CASH AND CASH EQUIVALENTS
AT THE END OF THE YEAR 120,300 124,278 133,708
======== ======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for interest 117,034 92,694 68,374
Cash received during the year for interest 784 1,848 783
SUPPLEMENTAL DISCLOSURES OF
SIGNIFICANT NON-CASH TRANSACTIONS:
Disposal of property, plant and equipment 8 - 1,961 -
Transfer of property, plant and equipment to related party 8 & 10 - 112,623 -
The attached notes 1 to 21 form part of these financial statements.
F-186
EMIRATES CMS POWER COMPANY PJSC
STATEMENTS OF STOCKHOLDERS' EQUITY
Years ended 31 December 2003, 2002 and 2001
RETAINED ACCUMULATED
EARNINGS OTHER
SHARE (ACCUMULATED COMPREHENSIVE
CAPITAL LOSSES) INCOME TOTAL
AED `000 AED `000 AED `000 AED `000
Balance at 1 January 2001 - unaudited 413,240 3,958 - 417,198
Transition adjustment from adoption of SFAS 133 (note 18) - - 30,677 30,677
Net loss for the year - (87,226) - (87,226)
Reclassification to earnings of cash flow hedges (note 18) - - (4,098) (4,098)
-------- -------- -------- ---------
Balance at 31 December 2001 - unaudited 413,240 (83,268) 26,579 356,551
Net loss for the year - (74,844) - (74,844)
Dividends paid (note 15) - (79,400) - (79,400)
Reclassification to earnings of cash flow hedges (note 18) - - (3,955) (3,955)
-------- -------- -------- ---------
Balance at 31 December 2002 - unaudited 413,240 (237,512) 22,624 198,352
Net income for the year - 163,647 - 163,647
Dividends paid (note 15) - (73,800) - (73,800)
Reclassification to earnings of cash flow hedges (note 18) - - (3,791) (3,791)
-------- -------- -------- ---------
Balance at 31 December 2003 413,240 (147,665) 18,833 284,408
======== ======== ======== =========
The attached notes 1 to 21 form part of these financial statements.
F-187
EMIRATES CMS POWER COMPANY PJSC
NOTES TO THE FINANCIAL STATEMENTS
31 December 2003 and 2002
1 ACTIVITIES
Emirates CMS Power Company PJSC is a private joint stock company
registered and incorporated in the United Arab Emirates and is engaged in the
generation of electricity and the production of desalinated water for supply
into the Abu Dhabi grid. The Company is 60% owned by Emirates Power Company PJSC
a wholly owned subsidiary of Abu Dhabi Water & Electricity Authority (ADWEA),
and 40% owned by CMS Generation Taweelah Limited.
The Company has a management operation and maintenance agreement with
Taweelah A2 Operating Company, a related party, whereby the latter has
undertaken to manage the day-to-day operations and maintain the Company's plant.
The Company has entered into a power and water purchase agreement with Abu Dhabi
Water and Electricity Company (ADWEC), a related party, (a wholly-owned
subsidiary of ADWEA). Under the agreement, the Company undertakes to make
available, and ADWEC undertakes to purchase, the entire net capacity and output
of the plant until October 2021 in accordance with various agreed terms and
conditions. The output payments cover variable operation and maintenance costs
and fuel efficiency bonuses or penalty for actual output. Natural gas fuel is
supplied by ADWEC at no cost.
The Company's registered head office is P O Box 47688, Abu Dhabi, United
Arab Emirates. At 31 December 2003 and 2002 there were no staff employed by the
Company.
2 BASIS OF PRESENTATION
Although at 31 December 2003, the Company's current liabilities exceeded
its current assets by AED 187,991,000 (2002: AED 138,164,000) the financial
statements have been prepared on a going concern basis in view of the credit
facilities available from the bankers and the refinancing of the term loan
explained in note 13. Further, the negative fair value of derivatives amounting
to AED 242.6 million (2002: AED 298.4 million) included within current
liabilities (note 12) will not significantly affect the Company's cash flow in
the foreseeable future.
3 SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PREPARATION
The financial statements are prepared on the basis of U.S. generally
accepted accounting principles and applicable requirements of United Arab
Emirates Law and are presented in United Arab Emirates Dirhams (AED).
ESTIMATES AND ASSUMPTIONS
The preparation of financial statements in conformity with U.S. generally
accepted accounting principles requires management to make estimates and
assumptions that affect reported amounts and related disclosures. Actual results
could differ from those estimates.
REVENUE RECOGNITION
Revenue represents the sale of water desalination and electricity
generation services comprised of the available capacity and variable output to
Abu Dhabi Water and Electricity Company (a wholly owned subsidiary of ADWEA)
during the year. Revenues are recognised when services are provided. Unbilled
revenues are based on estimated quantities of potable water and kilowatts of
electricity delivered during the period but not yet billed. These estimates are
generally based on contract data and preliminary throughput and allocation
measurements.
F-188
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is stated at historical cost less
accumulated depreciation and any impairment in value. The Company capitalises
all construction-related direct labour and material costs as well as indirect
construction costs. Indirect construction costs include engineering and the cost
of funds during the construction phase. The cost of renewals and betterments
that extend the useful life of the property, plant and equipment are
capitalised. The cost of repairs, spare parts and major maintenance that do not
extend the useful life or increase the expected output of property, plant and
equipment, is expensed as incurred. The cost of spare parts held as essential
for the continuity of operations and which are designated as strategic spares
are depreciated on a straight-line basis over the estimated remaining operating
life of the plant and equipment to which they relate
Depreciation is calculated on a straight-line basis over the estimated
useful lives of the assets as follows:
Buildings 30 to 40 years
Plant and equipment (including plant spares) 3 to 40 years
LONG-LIVED ASSETS
Long-lived assets are reviewed for impairment in accordance with Statement
of Financial Accounting Standards No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets (SFAS 144) when events or changes in circumstances
indicate that the related carrying amount may not be recoverable. Impairment is
assessed by comparing an asset's net undiscounted cash flows expected to be
generated over its remaining useful life to the asset's net carrying value. If
impairment is indicated, the carrying amount of the asset is reduced to its
estimated fair value.
INTANGIBLE ASSETS
Intangible assets, which represent acquisition of connection rights, are
capitalised at cost. The carrying values of intangible assets are reviewed for
impairment when events or changes in circumstances indicate that the carrying
value may not be recoverable.
The connection rights cost is amortised on a straight line basis over the
38 year period, being the expected period of benefit, commencing 1 January 2002.
INVENTORIES
Inventories are valued at the lower of cost, determined on the basis of
weighted average costs and net realisable value. Costs are those expenses
incurred in bringing each item to its present location and condition.
ACCOUNTS RECEIVABLE
Accounts receivable are stated net of provisions for amounts estimated to
be non-collectible. An estimate for doubtful accounts is made when collection of
the full amount is no longer probable. Bad debts are written-off as incurred.
ACCOUNTS PAYABLE
Liabilities are recognised for amounts to be paid in the future for goods
or services received, whether billed by the supplier or not.
CASH AND CASH EQUIVALENTS
All highly liquid investments with an original maturity of three months or
less are considered cash equivalents.
F-189
TERM LOAN
The term loan is carried on the balance sheet at its principal amount.
Instalments due within one year are shown as a current liability. Interest is
charged as an expense as it accrues, with unpaid amounts included in "accruals".
TRANSLATION OF FOREIGN CURRENCIES AND FOREIGN EXCHANGE TRANSACTIONS
Transactions in foreign currencies are recorded at the rate ruling at the
date of the transaction. Monetary assets and liabilities denominated in foreign
currencies are retranslated at the rate of exchange ruling at the balance sheet
date. All differences are taken to the income statement.
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES
The Company adopted SFAS 133 "Accounting for Derivative Instruments and
Hedging Activities," as amended on 1 January 2001. SFAS 133 establishes new
accounting and disclosure requirements for most derivative instruments and
hedging transactions involving derivatives. SFAS 133 also requires formal
documentation procedures for hedging relationships and effectiveness testing
when hedge accounting is to be applied.
In accordance with the transition provisions of SFAS 133, in the year
ended 31 December 2001, the Company recorded a cumulative loss adjustment of AED
21.5 million in its income statement as a transition adjustment to reflect a
liability for the fair value of all derivatives that did not previously meet the
requirement for hedge accounting treatment prior to the adoption of SFAS 133. In
addition, the Company recorded a transition gain of AED 30.7 million to
accumulated other comprehensive income to recognise an asset for the fair value
of all derivatives accounted for as cash flow hedges prior to the adoption of
SFAS 133.
DERIVATIVES
The Company obtained long-term USD debt to fund the development and
construction of the plant. Interest payments associated with the debt are based
on LIBOR plus a spread. The Company uses derivative financial instruments to
manage the interest rate exposures associated with the debt. The Company's
objective is to offset gains and losses resulting from these exposures with
losses and gains on the derivative financial instruments thereby reducing
volatility in earnings and cash flows. In addition, the Company uses forward
foreign exchange contracts to hedge its risk associated with foreign currency
fluctuations relating to scheduled maintenance cost payments to an overseas
supplier.
The Company does not utilize derivative financial instruments with a level
of complexity or with a risk greater than the exposures to be managed nor does
it enter into or hold derivatives for trading purposes. The use of the
derivative financial instruments associated with the interest rate risk is
mandated by the debt agreement. All derivatives entered into by the Company are
subject to internal policies that provide guidelines for control, counterparty
risk and ongoing monitoring and reporting of such activities.
The fair value of all derivatives are reported on the balance sheet based
on prevailing market rates. Derivatives with positive market values (unrealised
gains) are included in other current assets and derivatives with negative market
values (unrealised losses) are included in other current liabilities in the
balance sheet.
Changes in fair value of derivatives qualifying as cash flow hedges are
recorded in accumulated other comprehensive income and recognised in the income
statement in the corresponding period to which the cash flows associated with
the underlying hedged item transpire. Changes in fair values of contracts
excluded from the assessment of hedge effectiveness together and those contracts
that have not been formally designated as hedges are recorded as a separate line
in the income statement in the period they arise.
ASSET RETIREMENT OBLIGATIONS (ARO)
SFAS No. 143, Accounting for Asset Retirement Obligations became effective
January 2003. It requires companies to record the fair value of the cost to
remove assets at the end of their useful life, if there is a legal obligation to
do so. The Company has legal obligations to remove assets at the end of their
useful lives and restore the land.
F-190
The fair value of ARO liabilities has been calculated using an expected
present value technique. This technique reflects assumptions, such as costs,
inflation and profit margin that third parties would consider to assume the
settlement of the obligation. Fair value, to the extent possible, should include
a market risk premium for unforeseeable circumstances. No market risk premium
was included in our ARO fair value estimate since a reasonable estimate could
not be made. If a five percent market risk premium were assumed, our ARO
liability would be AED 16.2 million.
In 2003, the Company recorded an ARO liability for the restoration of land
and an AED 1.2 million, cumulative effect of change in accounting for accretion
and depreciation expense for ARO liabilities incurred prior to 2003. As the
plant began operation in August 2001, the pro forma effect on results of
operations would not have been material for the year ended 31 December 2002.
The following table presents the reconciliation of the beginning and
ending carrying value of the ARO:
AED `000
Proforma ARO liability - At 1 January 2002 13,710
======
ARO liability - At 1 January 2003 14,531
Liabilities incurred -
Liabilities settled -
Accretion expense 872
Revisions in estimated cash flow -
------
ARO liability - At 31 December 2003 15,403
======
4 PREPAYMENTS AND OTHER CURRENT ASSETS
UNAUDITED
2003 2002
AED `000 AED `000
Positive fair value of derivatives (note 18) 15,234 6,737
Other receivables 313 252
Prepaid expenses 9,527 3,944
------ ------
25,074 10,933
====== ======
5 AMOUNTS DUE FROM RELATED PARTY
UNAUDITED
2003 2002
AED `000 AED `000
Abu Dhabi Water and Electricity Company 38,799 37,986
====== ======
6 ADVANCE TO AL TAWEELAH SHARED FACILITIES COMPANY LLC (TSFC)
This represents an advance made to TSFC by the Company in proportion to
its 18% (2002: 18%) shareholding in TSFC against future use of their facilities.
Amount receivable within one year has been included under current assets.
F-191
7 INVENTORIES
UNAUDITED
2003 2002
AED `000 AED `000
Fuel 26,975 26,975
Spare parts and consumables 139,759 133,272
------- -------
166,734 160,247
======= =======
8 PROPERTY, PLANT AND EQUIPMENT, NET
The components of property, plant and equipment are as follows:
UNAUDITED
2003 2002
AED `000 AED `000
Buildings 205,114 204,823
Plant and equipment 2,193,309 2,178,384
Plant spares 6,656 6,656
--------- ---------
2,405,079 2,389,863
Less: accumulated depreciation (162,867) (98,711)
--------- ---------
2,242,212 2,291,152
========= =========
The activities of the Company are carried out from premises and equipment
constructed on land leased from ADWEA. The initial term of the lease is 25 years
and a nominal rental is payable by the Company. Leasehold land is carried in the
books at nil value.
During 2002, plant and equipment of net book value AED 112,623,000 was
transferred to a related party for the right to connection to the transmission
system (see note 10).
During 2002, property, plant and equipment amounting to AED 1,961,000 in
respect of an open discharge channel was transferred to TSFC in accordance with
an agreement dated May 2002. Under the agreement, the Company has received
additional shares in TSFC, amounting to AED 8,000 (see note 9) and a promissory
note from TSFC for the balance of the transfer value of the open discharge
channel, amounting to AED 1,953,000 to be treated as an additional advance to
TSFC (note 6).
9 INVESTMENT
UNAUDITED
2003 2002
AED `000 AED `000
Unquoted investment
Cost:
At 1 January 178 170
Additions - 8
--- ---
At 31 December 178 178
=== ===
F-192
The investment represents the 18% (2002: 18%) equity interest acquired by
the Company in TSFC. TSFC is a closely held private company which maintains
shared utility facilities for the supply and discharge of sea water and provides
other related services to the Company and other operators at the Taweelah
complex.
The fair value of the investment is not materially different from its
carrying amount.
10 INTANGIBLE ASSET
UNAUDITED
2003 2002
AED `000 AED `000
Cost:
At 1 January 112,623 -
Additions - 112,623
------- -------
At 31 December 112,623 112,623
------- -------
Amortisation:
At 1 January 2,940 -
Charge for the year 2,963 2,940
------- -------
At 31 December 5,903 2,940
------- -------
Net book amount 106,720 109,683
======= =======
The intangible asset arose from the transfer during the year ended 31
December 2002 of plant and equipment to a related party in accordance with an
agreement dated August 2000 and represents the acquisition cost of the Company's
right of connection to the transmission system at the connection site for a
period of 38 years (note 8). Accordingly, the connection rights cost is being
amortised on a straight-line basis over the 38 year period, being the expected
period of benefit, commencing 1 January 2002.
11 AMOUNT DUE TO RELATED PARTIES
UNAUDITED
2003 2002
AED `000 AED `000
Al Taweelah Shared Facilities Company 225 282
Taweelah A2 Operating Company 1,923 2,142
CMS Resource Development Company 1,329 -
----- -----
3,477 2,424
===== =====
12 ACCRUALS AND OTHER LIABILITIES
UNAUDITED
2003 2002
AED `000 AED `000
Accrual for spare parts 34,659 37,217
Accrued interest expense 42,439 35,952
Negative fair value of derivatives (note 18) 257,796 305,166
Other payables 11,796 10,011
------- -------
346,690 388,346
======= =======
F-193
13 LONG TERM DEBT
During 1999 the Company obtained a loan facility from a syndicate of banks
led by Barclays Capital Bank amounting to US $596,000,000 (AED 2,188,810,000)
out of which US $556,000,000 (AED 2,041,910,000) was fully drawn by 31 December
2001 to finance the construction of the Plant. The loan carries interest at a
variable rate of LIBOR plus a premium of between 0.8% and 1.5% per annum for the
remainder period of the term loan. The loan also carried a commitment fee of
0.35% per annum of the undrawn amount.
During the year ended 31 December 2003, the fourth and fifth instalments
amounting to AED 81.7 million (2002: AED 71.5 million) were paid, with the
remaining balance repayable in half yearly instalments until December 2013 in
accordance with an agreed upon instalment schedule. The term loan is secured by
a number of security documents including a commercial mortgage over all tangible
and intangible assets of the Company, a pledge of the shares in the Company by
both shareholders and a pledge of the equity interest in TSFC. The term loan is
also subject to various covenants as stipulated in the loan facility agreement.
Under the terms of its loan facility agreement, the Company is required to
enter into interest rate swap agreements to hedge its interest cost exposure
against fluctuations in interest rates (note 18).
On 15 March 2004, the Company obtained a US $391 million (AED 1,436
million) conventional loan facility and US $150 million (AED 551 million)
Islamic loan facility (the "new facilities") from a syndicate of international
and UAE based banks to refinance the term loan and repay up to US $35 million
(AED 129 million) of the loans from shareholders (note 14). As the existing term
loan is to be refinanced by the new facilities, the amounts due in less than one
year have been calculated in accordance with the repayment schedules of the new
facilities. Under the new facilities 2.951% (US $15,965 thousand (AED 58,631
thousand)) is repayable in 2004 and this amount has been disclosed as being due
in less than one year (current liability), with the remaining balance repayable
in half yearly instalments until December 2020.
Amounts repayable over the next five years are as follows:
US $'000
2004 15,965
2005 22,285
2006 21,191
2007 21,250
2008 21,835
14 LOAN FROM SHAREHOLDERS
UNAUDITED
2003 2002
AED `000 AED `000
Emirates Power Company PJSC 156,000 163,200
CMS Generation Taweelah Limited 104,000 108,800
------- -------
260,000 272,000
======= =======
Non-current liabilities 131,000 272,000
Current liabilities 129,000 -
------- -------
260,000 272,000
======= =======
The above loans are free of interest and are unsecured. Though the terms
of repayment have not been specified for these loans, they are subject to terms
of repayment as resolved by the Board of Directors.
F-194
The Board of Directors anticipates that the Company will make a
shareholder loan repayment of approximately AED 129 million in 2004.
Accordingly, this amount has been included under current liabilities.
15 SHARE CAPITAL AND STOCKHOLDERS' EQUITY
AUTHORISED, ISSUED AND FULLY PAID
UNAUDITED
2003 2002
AED `000 AED `000
Ordinary Shares of AED 10 each 413,240 413,240
======= =======
The Company maintain its statutory accounting records in accordance with
International Financial Reporting Standards (IFRS). U.A.E. Commercial Companies
Law of 1984 (as amended) and the Company's Articles of Association require 10%
of the net profit for the year, based on net income derived from the statutory
financial statements prepared in accordance with IFRS, to be transferred to a
statutory reserve. The reserve is not available for distribution. Included in
(accumulated losses) retained earnings is an amount of AED 27,029,000 (2002: AED
16,603,000) in respect of the required statutory reserve, which is not available
for distribution.
The Board of Directors recommendation for the distribution of dividends
and the ratification and approval of the Shareholders of the dividends were
based on the statutory financial statements. Included in the dividends paid
during the year ended 31 December 2003, are interim dividends of AED 0.56 (2002:
AED 1.07) per share of AED 23,000,000 (2002: AED 44,400,000) which were declared
and approved by the Board of Directors and paid during the year.
The shareholders have subsequently ratified and approved the interim
dividends paid at the Annual General Meeting.
16 RELATED PARTY TRANSACTIONS
These represent transactions with related parties, ie. other subsidiaries
of Abu Dhabi Power Corporation and Abu Dhabi Water and Electricity Authority and
other subsidiaries of CMS Energy Corporation, shareholders and senior management
of the Company, and companies of which they are principal owners. Pricing
policies and terms of these transactions are approved by the Company's senior
management.
Significant transactions with related parties included in the income
statement are as follows:
UNAUDITED UNAUDITED
2003 2002 2001
AED `000 AED `000 AED `000
Revenue from available capacity and supply of water and
electricity to Abu Dhabi Water & Electricity Company 363,564 370,686 196,091
Al Taweelah Shared Facilities Company LLC (TSFC) service charge 1,586 2,067 2,767
Other charges from TSFC 1,668 1,670 1,799
Charges by Taweelah A2 Operating Company analysed as follows:
Management fee 4,261 4,319 1,755
Manpower support services 10,852 9,673 8,991
Reimbursement of other third party costs paid on behalf of the Company 614 1,429 722
Charges by CMS Generation analysed as follows:
Manpower support service 1,979 3,193 2,677
Amounts due from and to related parties are disclosed in notes 5, 6, 11
and 14 to the financial statements.
F-195
17 FAIR VALUE OF FINANCIAL INSTRUMENTS
With the exception of the loan from shareholders the fair value of the
Company's financial instruments approximates their carrying amounts.
It is not practicable to determine the fair value of the loan from
shareholders with sufficient accuracy. Information on the principal
characteristics of the loan is presented in note 14 to the financial statements.
18 DERIVATIVES
In order to reduce its exposure to interest rates fluctuations on the term
loan, the Company has entered into an interest rate arrangement with a
counter-party bank for a notional amount that matches the outstanding term loan.
The notional amount outstanding at 31 December 2003 was AED 1,828 million (2002:
AED 1,910 million). In addition, the Company uses forward foreign exchange
contracts to hedge its risk associated with foreign currency fluctuations
relating to scheduled maintenance cost payments to an overseas supplier. The
outstanding forward foreign exchange commitment at the year end amounted to
approximately AED 42 million (2002: AED 62 million).
The derivative instruments had a negative fair value of AED 258 million
(2002: negative fair value of AED 305 million) which is included within other
current liabilities (note 12) and a positive fair value of AED 15 million (2002:
positive fair value of AED 7 million) which is included within other current
assets (note 4). As a result of the debt refinancing arrangements concluded by
the Company in March 2004 as explained in note 13, the existing derivatives have
extinguished and new interest rate swap contracts have been entered into as part
of the debt refinancing arrangements. Consequently, the Company expects to
reclassify the remaining transition amount recorded in accumulated other
comprehensive income into earnings in the year 2004.
19 RISK MANAGEMENT
INTEREST RATE RISK
The Company is exposed to interest rate risk on its interest bearing
liabilities (term loan). Whilst current interest are low, management has sought
to limit the exposure of the Company to any adverse future movements in interest
rates by entering into interest rate arrangements (derivative instruments see
note 19). Management is therefore of the opinion that the Company's exposure to
interest rate risk is limited.
CONCENTRATION OF CREDIT RISK
The Company sells its products to one related party. It seeks to limits
its credit risk with respect to this customer by monitoring outstanding
receivables.
LIQUIDITY RISK
The Company limits its liquidity by monitoring its current financial
position in conjunction with its cash flow forecasts on a regular basis to
ensure funds are available to meet its commitments for liabilities as they fall
due. The Company's terms of sale require amounts to be paid within 30 days of
the date of sale. Trade payables are normally settled within 30 days of the date
of purchase.
CURRENCY RISK
The Company uses forward currency contracts to eliminate currency
exposures on its fixed Euro plant maintenance payments. The majority of other
transactions are in UAE Dirhams, which are pegged to the US Dollar. Management
is therefore of the opinion that the Company's exposure to currency risk is
limited.
F-196
20 ADMINISTRATIVE AND OTHER OPERATING EXPENSES
UNAUDITED UNAUDITED
2003 2002 2001
AED `000 AED `000 AED `000
Management fees 4,261 4,319 1,755
Other 3,826 3,606 3,066
----- ----- -----
8,087 7,925 4,821
===== ===== =====
21 INCOME TAX
The Company is not subject to income or other similar taxes in the United
Arab Emirates and, accordingly, no income tax has been reflected in these
financial statements.
F-197
NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS IN CONNECTION WITH THE OFFERING MADE HEREBY, AND, IF GIVEN OR MADE,
SUCH INFORMATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY CMS
ENERGY, THE INITIAL PURCHASERS OR ANY OTHER PERSON. THIS PROSPECTUS DOES NOT
CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF ANY OFFER TO BUY THE NEW NOTES
BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT
AUTHORIZED, OR IN WHICH THE PERSON MAKING THE OFFER OR SOLICITATION IS NOT
QUALIFIED TO DO SO, OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER
OR SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL CREATE ANY IMPLICATION THAT THE INFORMATION CONTAINED HEREIN IS
CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF.
TABLE OF CONTENTS
PAGE
Important Notice about Information in this Prospectus...... 1
Where You Can Find More Information........................ 1
Forward-Looking Statements and Information................. 2
Summary.................................................... 4
Risk Factors............................................... 14
Use of Proceeds............................................ 24
Ratio of Earnings to Fixed Charges......................... 24
Description of the New Notes............................... 24
Ratings.................................................... 43
The Exchange Offer......................................... 43
Management's Discussion and Analysis of
Financial Condition and Results of Operations
for the Six Months Ended June 30, 2004.................... 52
Management's Discussion and Analysis of
Financial Condition and Results of Operations
for the Fiscal Year Ended December 31, 2003............ 87
Our Business............................................... 120
Legal Proceedings.......................................... 131
Our Management............................................. 134
Affiliate Relationships and Transactions................... 141
Certain United States Federal Income Tax Consequences ..... 141
Plan of Distribution....................................... 144
Legal Opinions............................................. 144
Experts.................................................... 144
Glossary................................................... 146
Index to Consolidated Financial Statements................. F-1
OFFER TO EXCHANGE
7.75% SENIOR NOTES DUE 2010
WHICH HAVE BEEN REGISTERED
UNDER THE SECURITIES ACT OF 1933,
AS AMENDED
FOR ANY AND ALL OF THE
OUTSTANDING
7.75% SENIOR NOTES DUE 2010
[CMS ENERGY LOGO]