UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2006
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ______________ TO _______________.
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Commission file number 1-31447
CENTERPOINT ENERGY, INC.
(Exact name of registrant as specified in its charter)
TEXAS 74-0694415
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1111 LOUISIANA
HOUSTON, TEXAS 77002 (713) 207-1111
(Address and zip code of (Registrant's telephone number,
principal executive offices) including area code)
----------
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is a large accelerated filer,
an accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check
one):
Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ]
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
As of August 1, 2006, CenterPoint Energy, Inc. had 311,766,506 shares of
common stock outstanding, excluding 166 shares held as treasury stock.
CENTERPOINT ENERGY, INC.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2006
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements...................................... 1
Condensed Statements of Consolidated Income
Three Months and Six Months Ended June 30, 2005 and 2006
(unaudited)................................................. 1
Condensed Consolidated Balance Sheets
December 31, 2005 and June 30, 2006 (unaudited)............. 2
Condensed Statements of Consolidated Cash Flows
Six Months Ended June 30, 2005 and 2006 (unaudited)......... 4
Notes to Unaudited Condensed Consolidated Financial
Statements.................................................. 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 26
Item 3. Quantitative and Qualitative Disclosures about Market
Risk................................................... 41
Item 4. Controls and Procedures................................... 42
PART II. OTHER INFORMATION
Item 1. Legal Proceedings........................................ 42
Item 1A. Risk Factors............................................. 42
Item 4 Submission of Matters to a Vote of Security Holders...... 42
Item 5. Other Information........................................ 43
Item 6. Exhibits................................................. 43
i
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
From time to time we make statements concerning our expectations, beliefs,
plans, objectives, goals, strategies, future events or performance and
underlying assumptions and other statements that are not historical facts. These
statements are "forward-looking statements" within the meaning of the Private
Securities Litigation Reform Act of 1995. Actual results may differ materially
from those expressed or implied by these statements. You can generally identify
our forward-looking statements by the words "anticipate," "believe," "continue,"
"could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective,"
"plan," "potential," "predict," "projection," "should," "will," or other similar
words.
We have based our forward-looking statements on our management's beliefs
and assumptions based on information available to our management at the time the
statements are made. We caution you that assumptions, beliefs, expectations,
intentions and projections about future events may and often do vary materially
from actual results. Therefore, we cannot assure you that actual results will
not differ materially from those expressed or implied by our forward-looking
statements.
The following are some of the factors that could cause actual results to
differ materially from those expressed or implied in forward-looking statements:
- the timing and amount of our recovery of the true-up components,
including, in particular, the results of appeals to the courts of
determinations on rulings obtained to date;
- state and federal legislative and regulatory actions or developments,
including deregulation, re-regulation, changes in or application of
laws or regulations applicable to other aspects of our business and
actions with respect to:
- allowed rates of return;
- rate structures;
- recovery of investments; and
- operation and construction of facilities;
- timely and appropriate rate actions and increases, allowing recovery
of costs and a reasonable return on investment;
- industrial, commercial and residential growth in our service territory
and changes in market demand and demographic patterns;
- the timing and extent of changes in commodity prices, particularly
natural gas;
- changes in interest rates or rates of inflation;
- weather variations and other natural phenomena;
- the timing and extent of changes in the supply of natural gas;
- the timing and extent of changes in natural gas basis differentials;
- commercial bank and financial market conditions, our access to
capital, the cost of such capital, and the results of our financing
and refinancing efforts, including availability of funds in the debt
capital markets;
- actions by rating agencies;
- effectiveness of our risk management activities;
- inability of various counterparties to meet their obligations to us;
- non-payment for our services due to financial distress of our
customers, including Reliant Energy, Inc. (formerly named Reliant
Resources, Inc.) (RRI);
ii
- the ability of RRI and its subsidiaries to satisfy their obligations
to us, including indemnity obligations, or in connection with the
contractual arrangements pursuant to which we are a guarantor;
- the outcome of litigation brought by or against us;
- our ability to control costs;
- the investment performance of our employee benefit plans;
- our potential business strategies, including acquisitions or
dispositions of assets or businesses, which cannot be assured to be
completed or to have the anticipated benefits to us; and
- other factors we discuss in "Risk Factors" in Item 1A of Part I of our
Annual Report on Form 10-K for the year ended December 31, 2005, which
is incorporated herein by reference.
You should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular
statement.
iii
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
--------------- ---------------
2005 2006 2005 2006
------ ------ ------ ------
REVENUES ...................................................................... $1,842 $1,843 $4,437 $4,920
------ ------ ------ ------
EXPENSES:
Natural gas ................................................................ 1,103 1,035 2,884 3,228
Operation and maintenance .................................................. 325 340 638 671
Depreciation and amortization .............................................. 136 153 266 293
Taxes other than income taxes .............................................. 92 95 187 202
------ ------ ------ ------
Total ................................................................... 1,656 1,623 3,975 4,394
------ ------ ------ ------
OPERATING INCOME .............................................................. 186 220 462 526
------ ------ ------ ------
OTHER INCOME (EXPENSE):
Gain (loss) on Time Warner investment ...................................... (18) 11 (59) (3)
Gain (loss) on indexed debt securities ..................................... 24 (11) 63 (1)
Interest and other finance charges ......................................... (180) (118) (353) (233)
Interest on transition bonds ............................................... (9) (33) (18) (66)
Return on true-up balance .................................................. 35 -- 69 --
Other, net ................................................................. 7 9 11 15
------ ------ ------ ------
Total ................................................................... (141) (142) (287) (288)
------ ------ ------ ------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM .. 45 78 175 238
Income tax (expense) benefit ............................................... (18) 116 (81) 44
------ ------ ------ ------
INCOME FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEM ................... 27 194 94 282
DISCONTINUED OPERATIONS:
Income (Loss) from Texas Genco, net of tax ................................. (3) -- 11 --
Loss on Disposal of Texas Genco, net of tax ................................ -- -- (14) --
------ ------ ------ ------
Total ................................................................... (3) -- (3) --
------ ------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEM .............................................. 24 194 91 282
EXTRAORDINARY ITEM, NET OF TAX ................................................ 30 -- 30 --
------ ------ ------ ------
NET INCOME .................................................................... $ 54 $ 194 $ 121 $ 282
====== ====== ====== ======
BASIC EARNINGS PER SHARE:
Income from Continuing Operations .......................................... $ 0.09 $ 0.62 $ 0.30 $ 0.91
Discontinued Operations, net of tax ........................................ (0.01) -- (0.01) --
Extraordinary Item, net of tax ............................................. 0.10 -- 0.10 --
------ ------ ------ ------
Net Income ................................................................. $ 0.18 $ 0.62 $ 0.39 $ 0.91
====== ====== ====== ======
DILUTED EARNINGS PER SHARE:
Income from Continuing Operations .......................................... $ 0.09 $ 0.61 $ 0.28 $ 0.89
Discontinued Operations, net of tax ........................................ (0.01) -- (0.01) --
Extraordinary Item, net of tax ............................................. 0.08 -- 0.08 --
------ ------ ------ ------
Net Income ................................................................. $ 0.16 $ 0.61 $ 0.35 $ 0.89
====== ====== ====== ======
See Notes to the Company's Interim Condensed Financial Statements
1
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS OF DOLLARS)
(UNAUDITED)
ASSETS
DECEMBER 31, JUNE 30,
2005 2006
------------ -----------
CURRENT ASSETS:
Cash and cash equivalents ....................... $ 74 $ 397
Investment in Time Warner common stock .......... 377 374
Accounts receivable, net ........................ 1,098 765
Accrued unbilled revenues ....................... 608 217
Natural gas inventory ........................... 294 205
Materials and supplies .......................... 88 93
Non-trading derivative assets ................... 131 107
Taxes receivable ................................ 53 --
Prepaid expenses and other current assets ....... 168 239
------------ -----------
Total current assets ......................... 2,891 2,397
------------ -----------
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment ................... 11,558 11,862
Less accumulated depreciation and amortization .. (3,066) (3,187)
------------ -----------
Property, plant and equipment, net ........... 8,492 8,675
------------ -----------
OTHER ASSETS:
Goodwill ........................................ 1,709 1,709
Other intangibles, net .......................... 56 55
Regulatory assets ............................... 2,955 2,890
Non-trading derivative assets ................... 104 79
Other ........................................... 909 904
------------ -----------
Total other assets ........................... 5,733 5,637
------------ -----------
TOTAL ASSETS .............................. $17,116 $16,709
============ ===========
See Notes to the Company's Interim Condensed Financial Statements
2
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS - (CONTINUED)
(MILLIONS OF DOLLARS)
(UNAUDITED)
LIABILITIES AND SHAREHOLDERS' EQUITY
DECEMBER 31, JUNE 30,
2005 2006
------------ -----------
CURRENT LIABILITIES:
Current portion of transition bond long-term debt ................. $ 73 $ 126
Current portion of other long-term debt ........................... 266 519
Indexed debt securities derivative ................................ 292 294
Accounts payable .................................................. 1,161 466
Taxes accrued ..................................................... 167 149
Interest accrued .................................................. 122 176
Non-trading derivative liabilities ................................ 43 103
Accumulated deferred income taxes, net ............................ 385 373
Other ............................................................. 505 370
------------ -----------
Total current liabilities ...................................... 3,014 2,576
------------ -----------
OTHER LIABILITIES:
Accumulated deferred income taxes, net ............................ 2,474 2,400
Unamortized investment tax credits ................................ 46 42
Non-trading derivative liabilities ................................ 35 89
Benefit obligations ............................................... 475 455
Regulatory liabilities ............................................ 728 822
Other ............................................................. 480 266
------------ -----------
Total other liabilities ........................................ 4,238 4,074
------------ -----------
LONG-TERM DEBT:
Transition bonds .................................................. 2,407 2,335
Other ............................................................. 6,161 6,220
------------ -----------
Total long-term debt ........................................... 8,568 8,555
------------ -----------
COMMITMENTS AND CONTINGENCIES (NOTE 11)
SHAREHOLDERS' EQUITY:
Common stock (310,324,739 shares and 311,630,055 shares outstanding
at December 31, 2005 and June 30, 2006, respectively) .......... 3 3
Additional paid-in capital ........................................ 2,931 2,949
Accumulated deficit ............................................... (1,600) (1,411)
Accumulated other comprehensive loss .............................. (38) (37)
------------ -----------
Total shareholders' equity ..................................... 1,296 1,504
------------ -----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY .................. $17,116 $16,709
============ ===========
See Notes to the Company's Interim Condensed Financial Statements
3
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(MILLIONS OF DOLLARS)
(UNAUDITED)
SIX MONTHS ENDED JUNE 30,
-------------------------
2005 2006
----- -----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................................................... $ 121 $ 282
Discontinued operations, net of tax .......................................... 3 --
Extraordinary item, net of tax ............................................... (30) --
----- -----
Income from continuing operations ............................................ 94 282
Adjustments to reconcile income from continuing operations to net cash
provided by operating activities:
Depreciation and amortization ............................................. 266 293
Amortization of deferred financing costs .................................. 40 28
Deferred income taxes ..................................................... 48 (105)
Tax and interest reserves reductions related to ZENS and ACES ............. -- (119)
Investment tax credit ..................................................... (4) (4)
Unrealized loss on Time Warner investment ................................. 59 3
Unrealized loss (gain) on indexed debt securities ......................... (63) 1
Write-down of natural gas inventory ....................................... -- 30
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net ......................... 559 743
Inventory .............................................................. 9 62
Taxes receivable ....................................................... (6) 53
Accounts payable ....................................................... (305) (697)
Fuel cost over (under) recovery/surcharge .............................. (47) 76
Non-trading derivatives, net ........................................... 1 13
Margin deposits, net ................................................... 7 (113)
Interest and taxes accrued ............................................. (483) 36
Net regulatory assets and liabilities .................................. (133) 54
Other current assets ................................................... 5 (86)
Other current liabilities .............................................. (18) (34)
Other assets ........................................................... 2 --
Other liabilities ...................................................... 18 (14)
Other, net ................................................................ 5 15
----- -----
Net cash provided by operating activities of continuing operations .. 54 517
Net cash used in operating activities of discontinued operations .... (38) --
----- -----
Net cash provided by operating activities ........................... 16 517
----- -----
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ......................................................... (310) (381)
Proceeds from sale of Texas Genco ............................................ 700 --
Decrease in restricted cash of Texas Genco ................................... 383 --
Purchase of minority interest in Texas Genco ................................. (383) --
Decrease in cash of Texas Genco .............................................. 23 --
Increase in restricted cash of transition bond companies ..................... -- (6)
Other, net ................................................................... (1) (9)
----- -----
Net cash provided by (used in) investing activities ................. 412 (396)
----- -----
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings, net ....................................... 75 --
Proceeds from issuance of long-term debt ..................................... -- 324
Long-term revolving credit facilities, net ................................... (119) (3)
Payments of long-term debt ................................................... (61) (28)
Debt issuance costs .......................................................... (6) (4)
Payment of common stock dividends ............................................ (83) (93)
Proceeds from issuance of common stock, net .................................. 8 6
Other ........................................................................ 1 --
----- -----
Net cash provided by (used in) financing activities ................. (185) 202
----- -----
NET INCREASE IN CASH AND CASH EQUIVALENTS ....................................... 243 323
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ................................ 165 74
----- -----
CASH AND CASH EQUIVALENTS AT END OF PERIOD ...................................... $ 408 $ 397
===== =====
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest, net of capitalized interest ........................................ $ 329 $ 226
Income taxes ................................................................. 457 112
See Notes to the Company's Interim Condensed Financial Statements
4
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(1) BACKGROUND AND BASIS OF PRESENTATION
General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of
CenterPoint Energy, Inc. are the condensed consolidated interim financial
statements and notes (Interim Condensed Financial Statements) of CenterPoint
Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy, or the
Company). The Interim Condensed Financial Statements are unaudited, omit certain
financial statement disclosures and should be read with the Annual Report on
Form 10-K of CenterPoint Energy for the year ended December 31, 2005
(CenterPoint Energy Form 10-K).
Background. CenterPoint Energy is a public utility holding company, created
on August 31, 2002 as part of a corporate restructuring of Reliant Energy,
Incorporated (Reliant Energy) that implemented certain requirements of the Texas
Electric Choice Plan (Texas electric restructuring law).
CenterPoint Energy was a registered public utility holding company under
the Public Utility Holding Company Act of 1935, as amended (1935 Act). The
Energy Policy Act of 2005 (Energy Act) repealed the 1935 Act effective February
8, 2006, and since that date the Company and its subsidiaries have no longer
been subject to restrictions imposed under the 1935 Act. The Energy Act includes
a new Public Utility Holding Company Act of 2005 (PUHCA 2005) which grants to
the Federal Energy Regulatory Commission (FERC) authority to require holding
companies and their subsidiaries to maintain certain books and records and make
them available for review by the FERC and state regulatory authorities in
certain circumstances. On December 8, 2005, the FERC issued rules implementing
PUHCA 2005. Pursuant to those rules, on June 14, 2006, the Company filed with
the FERC the required notification of its status as a public utility holding
company. On April 24, 2006, the FERC proposed additional rules regarding
maintenance of books and records by utility holding companies and additional
reporting and accounting requirements for centralized service companies that
make allocations to public utilities regulated by the FERC under the Federal
Power Act. Although the Company provides services to its subsidiaries through a
service company, CenterPoint Energy Service Company, LLC, its service company
would not be subject to the service company rules.
The Company's operating subsidiaries own and operate electric transmission
and distribution facilities, natural gas distribution facilities, interstate
pipelines and natural gas gathering, processing and treating facilities. As of
June 30, 2006, the Company's indirect wholly owned subsidiaries included:
- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which
engages in the electric transmission and distribution business in a
5,000-square mile area of the Texas Gulf Coast that includes Houston;
and
- CenterPoint Energy Resources Corp. (CERC Corp., and, together with its
subsidiaries, CERC), which owns gas distribution systems. The
operations of its local distribution companies are conducted through
two unincorporated divisions: Minnesota Gas and Southern Gas
Operations. Through wholly owned subsidiaries, CERC owns two
interstate natural gas pipelines and gas gathering systems, provides
various ancillary services, and offers variable and fixed-price
physical natural gas supplies primarily to commercial and industrial
customers and electric and gas utilities.
Basis of Presentation. The preparation of financial statements in
conformity with accounting principles generally accepted in the United States of
America 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.
The Company's Interim Condensed Financial Statements reflect all normal
recurring adjustments that are, in the opinion of management, necessary to
present fairly the financial position, results of operations and cash flows for
the respective periods. Amounts reported in the Company's Condensed Statements
of Consolidated Income are not necessarily indicative of amounts expected for a
full-year period due to the effects of, among other things, (a) seasonal
fluctuations in demand for energy and energy services, (b) changes in energy
commodity prices, (c) timing of maintenance and other expenditures and (d)
acquisitions and dispositions of businesses, assets and other
5
interests. In addition, certain amounts from the prior year have been
reclassified to conform to the Company's presentation of financial statements in
the current year. These reclassifications relate to a new reportable business
segment discussed in Note 13 and do not affect net income.
(2) DISCONTINUED OPERATIONS
In July 2004, the Company announced its agreement to sell its majority
owned subsidiary, Texas Genco Holdings, Inc. (Texas Genco), to Texas Genco LLC.
On December 15, 2004, Texas Genco completed the sale of its fossil generation
assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813
billion in cash. Following the sale, Texas Genco distributed $2.231 billion in
cash to the Company. Following that sale, Texas Genco's principal remaining
asset was its ownership interest in a nuclear generating facility. The final
step of the transaction, the merger of Texas Genco with a subsidiary of Texas
Genco LLC in exchange for an additional cash payment to the Company of $700
million, was completed on April 13, 2005, following receipt of approval from the
Nuclear Regulatory Commission (NRC).
The Company recorded an after-tax loss of $3 million for each of the three
and six month periods ended June 30, 2005 related to the operations of Texas
Genco. General corporate overhead, previously allocated to Texas Genco from the
Company, was less than $1 million for each of the three and six month periods
ended June 30, 2005. These amounts were not eliminated by the sale of Texas
Genco and have been excluded from income from discontinued operations and
reflected as general corporate overhead of the Company in income from continuing
operations in accordance with Statement of Financial Accounting Standards (SFAS)
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS
No. 144). The Interim Condensed Financial Statements present these operations as
discontinued operations in accordance with SFAS No. 144.
Revenues related to Texas Genco included in discontinued operations for the
three and six months ended June 30, 2005 were $5 million and $62 million,
respectively. Income from these discontinued operations for the three and six
months ended June 30, 2005 is reported net of income tax (benefit) expense of
$(2) million and $4 million, respectively.
(3) EMPLOYEE BENEFIT PLANS
The Company's net periodic cost includes the following components relating
to pension and postretirement benefits:
THREE MONTHS ENDED JUNE 30,
-----------------------------------------------------
2005 2006
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
(IN MILLIONS)
Service cost ........................... $ 8 $-- $ 9 $--
Interest cost .......................... 25 7 24 7
Expected return on plan assets ......... (35) (3) (36) (3)
Amortization of prior service cost ..... (1) 1 (2) 1
Amortization of net loss ............... 10 -- 13 --
Amortization of transition obligation .. -- 2 -- 2
---- --- ---- ---
Net periodic cost ...................... $ 7 $ 7 $ 8 $ 7
==== === ==== ===
SIX MONTHS ENDED JUNE 30,
-----------------------------------------------------
2005 2006
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
(IN MILLIONS)
Service cost ........................... $ 17 $ 1 $ 18 $ 1
Interest cost .......................... 48 14 48 13
Expected return on plan assets ......... (69) (6) (71) (6)
Amortization of prior service cost ..... (3) 1 (4) 1
Amortization of net loss ............... 22 -- 24 --
Amortization of transition obligation .. -- 4 -- 4
Benefit enhancement .................... -- -- 8 1
---- --- ---- ---
Net periodic cost ...................... $ 15 $14 $ 23 $14
==== === ==== ===
6
The Company expects to contribute approximately $26 million to its
postretirement benefits plan in 2006, of which $13 million had been contributed
as of June 30, 2006.
Contributions to the pension plan are not required in 2006. In addition to
the Company's non-contributory pension plan, the Company maintains a
non-qualified benefit restoration plan. The net periodic cost associated with
this plan for the three-month periods ended June 30, 2005 and 2006 was $2
million and $1 million, respectively, and $3 million for each of the six-month
periods ended June 30, 2005 and 2006.
On January 5, 2006, the Company offered a Voluntary Early Retirement
Program (VERP) to approximately 200 employees who were age 55 or older with at
least five years of service as of February 28, 2006. The election period was
from January 5, 2006 through February 28, 2006. For those electing to accept the
VERP, three years of age and service was added to their qualified pension plan
benefit and three years of service was added to their postretirement benefit. An
additional pension and postretirement expense of approximately $9 million was
recorded in the first quarter of 2006 and is reflected in the table above as a
benefit enhancement.
(4) NEW ACCOUNTING PRONOUNCEMENTS
In July 2006, the Financial Accounting Standards Board (FASB) issued FASB
Interpretation (FIN) No. 48, "Accounting for Uncertainty in Income Taxes - An
Interpretation of FASB Statement No. 109" (FIN 48). FIN 48 clarifies the
accounting for uncertainty in income taxes recognized in an enterprise's
financial statements in accordance with FASB Statement No. 109, "Accounting for
Income Taxes." FIN 48 prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return. The new FASB
interpretation also provides guidance on derecognition, classification, interest
and penalties, accounting in interim periods, disclosure, and transition. The
provisions of FIN 48 are effective for fiscal years beginning after December 15,
2006. The Company expects to adopt FIN 48 in the first quarter of 2007 and is
currently evaluating the impact the adoption will have on the Company's
financial position.
(5) REGULATORY MATTERS
(A) RECOVERY OF TRUE-UP BALANCE
In March 2004, CenterPoint Houston filed its true-up application with the
Public Utility Commission of Texas (Texas Utility Commission), requesting
recovery of $3.7 billion, excluding interest, as allowed under the Texas
electric restructuring law. In December 2004, the Texas Utility Commission
issued its final order (True-Up Order) allowing CenterPoint Houston to recover a
true-up balance of approximately $2.3 billion, which included interest through
August 31, 2004, and providing for adjustment of the amount to be recovered to
include interest on the balance until recovery, the principal portion of
additional excess mitigation credits returned to customers after August 31, 2004
and certain other matters. CenterPoint Houston and other parties filed appeals
of the True-Up Order to a district court in Travis County, Texas. In August
2005, the court issued its final judgment on the various appeals. In its
judgment, the court affirmed most aspects of the True-Up Order, but reversed two
of the Texas Utility Commission's rulings. The judgment would have the effect of
restoring approximately $650 million, plus interest, of the $1.7 billion the
Texas Utility Commission had disallowed from CenterPoint Houston's initial
request. CenterPoint Houston and other parties appealed the district court
decisions. Briefs have been filed with the 3rd Court of Appeals in Austin, and
oral argument has been scheduled for September 27, 2006. No amounts related to
the district court's judgment have been recorded in the consolidated financial
statements.
Among the issues raised in CenterPoint Houston's appeal of the True-Up
Order is the Texas Utility Commission's reduction of CenterPoint Houston's
stranded cost recovery by approximately $146 million for the present value of
certain deferred tax benefits associated with its former electric generation
assets. Such reduction was considered in the Company's recording of an after-tax
extraordinary loss of $977 million in the last half of 2004. The Company
believes that the Texas Utility Commission based its order on proposed
regulations issued by the Internal Revenue Service (IRS) in March 2003 related
to those tax benefits. Those proposed regulations would have allowed utilities
owning assets that were deregulated before March 4, 2003 to make a retroactive
election to pass the benefits of Accumulated Deferred Investment Tax Credits
(ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers.
However, in December 2005, the IRS withdrew those proposed normalization
7
regulations and issued new proposed regulations that do not include the
provision allowing a retroactive election to pass the tax benefits back to
customers. In a recent Private Letter Ruling issued to a Texas utility on facts
similar to CenterPoint Houston's, the IRS, without referencing its proposed
regulations, ruled that a normalization violation would occur if ADITC and EDFIT
were required to be returned to customers. Based on that ruling and the proposed
regulations, if the Texas Utility Commission's order on this issue is not
reversed on appeal or the amount of the tax benefits is not otherwise restored
by the Texas Utility Commission, the IRS is likely to consider that a
normalization violation has occurred. If so, the IRS could require the Company
to pay an amount equal to CenterPoint Houston's unamortized ADITC balance as of
the date that the normalization violation was deemed to have occurred. In
addition, if a normalization violation is deemed to have occurred, the IRS could
also deny CenterPoint Houston the ability to elect accelerated tax depreciation
benefits. If a normalization violation should ultimately be found to exist, it
could have an adverse impact on the Company's results of operations, financial
condition and cash flows. However, the Company and CenterPoint Houston are
vigorously pursuing the appeal of this issue and will seek other relief from the
Texas Utility Commission to avoid a normalization violation. The Texas Utility
Commission has not previously required a company subject to its jurisdiction to
take action that would result in a normalization violation.
There are two ways for CenterPoint Houston to recover the true-up balance:
by issuing transition bonds to securitize the amounts due and/or by implementing
a competition transition charge (CTC). Pursuant to a financing order issued by
the Texas Utility Commission in March 2005 and affirmed in all respects in
August 2005 by the same Travis County District Court considering the appeal of
the True-Up Order, in December 2005, a subsidiary of CenterPoint Houston issued
$1.85 billion in transition bonds with interest rates ranging from 4.84 percent
to 5.30 percent and final maturity dates ranging from February 2011 to August
2020. Through issuance of the transition bonds, CenterPoint Houston recovered
approximately $1.7 billion of the true-up balance determined in the True-Up
Order plus interest through the date on which the bonds were issued.
In July 2005, CenterPoint Houston received an order from the Texas Utility
Commission allowing it to implement a CTC which will collect approximately $596
million over 14 years plus interest at an annual rate of 11.075 percent (CTC
Order). The CTC Order authorizes CenterPoint Houston to impose a charge on
retail electric providers (REPs) to recover the portion of the true-up balance
not covered by the financing order. The CTC Order also allows CenterPoint
Houston to collect approximately $24 million of rate case expenses over three
years without a return through a separate tariff rider (Rider RCE). CenterPoint
Houston implemented the CTC and Rider RCE effective September 13, 2005 and began
recovering approximately $620 million. Effective September 13, 2005, the return
on the CTC portion of the true-up balance is included in CenterPoint Houston's
tariff-based revenues. During the three and six months ended June 30, 2006,
CenterPoint Houston recognized approximately $18 million and $35 million,
respectively, in CTC operating income. As of June 30, 2006, the Company had not
recorded an allowed equity return of $241 million on its true-up balance because
such return is being recognized as it is recovered in the future.
Certain parties appealed the CTC Order to the 98th District Court in Travis
County. In May 2006, the district court issued an order reversing the CTC Order
in three respects. First, the court ruled that the Texas Utility Commission had
improperly relied on provisions of its rule dealing with the interest rate
applicable to CTC amounts. The district court reached that conclusion on the
grounds that the Texas Supreme Court had previously invalidated that entire
section of the rule. Second, the district court reversed the Texas Utility
Commission's ruling that allows CenterPoint Houston to recover through the CTC
the costs (approximately $5 million) for a panel appointed by the Texas Utility
Commission in connection with the valuation of the Company's electric generation
assets. Finally, the district court accepted the contention of one party that
the CTC should not be allocated to retail customers who have switched to new
on-site generation. The Company and CenterPoint Houston disagree with the
district court's conclusions and in May 2006 appealed this decision to the court
of appeals and, if required, plans to seek further review from the Texas Supreme
Court. CenterPoint Houston's brief is due to be filed in the court of appeals in
August 2006. Pending completion of judicial review and any action required by
the Texas Utility Commission following a remand from the courts, the CTC remains
in effect. The 11.075 percent interest rate in question was applicable from the
implementation of the CTC Order on September 13, 2005 until August 1, 2006, the
effective date of the implementation of a new CTC in compliance with the new
rule discussed below. The ultimate outcome of this matter cannot be predicted at
this time. However, the Company does not expect the disposition of this matter
to have a material adverse effect on the Company's or CenterPoint Houston's
financial condition, results of operations or cash flows.
8
In January 2006, the Texas Utility Commission staff (Staff) proposed that the
Texas Utility Commission adopt new rules governing the carrying charges on
unrecovered true-up balances. In June 2006, the Texas Utility Commission adopted
the revised rule as recommended by the Staff. The rule, which applies to
CenterPoint Houston, reduces carrying costs on the unrecovered CTC balance
prospectively from 11.075 percent to a weighted average cost of capital of 8.06
percent. The annualized impact on operating income is expected to be
approximately $18 million per year for the first year with lesser impacts in
subsequent years. On July 17, 2006, CenterPoint Houston made a compliance filing
necessary to implement the rule changes effective August 1, 2006 per the
settlement agreement discussed in Note 5(d) below.
(B) FINAL FUEL RECONCILIATION
The results of the Texas Utility Commission's final decision related to
CenterPoint Houston's final fuel reconciliation are a component of the True-Up
Order. CenterPoint Houston has appealed certain portions of the True-Up Order
involving a disallowance of approximately $67 million relating to the final fuel
reconciliation in 2003 plus interest of $10 million. A judgment was entered by a
Travis County court in May 2005 affirming the Texas Utility Commission's
decision. CenterPoint Houston filed an appeal to the 3rd Court of Appeals in
Austin in June 2005, and in April 2006, the 3rd Court of Appeals issued an order
affirming the Texas Utility Commission's decision. CenterPoint Houston has until
August 16, 2006 to file an appeal with the Texas Supreme Court.
(C) REMAND OF 2001 UNBUNDLED COST OF SERVICE (UCOS) ORDER
The 3rd Court of Appeals in Austin remanded to the Texas Utility Commission
an issue that was decided by the Texas Utility Commission in CenterPoint
Houston's 2001 UCOS proceeding. In its remand order, the court ruled that the
Texas Utility Commission had failed to adequately explain its basis for its
determination of certain projected transmission capital expenditures. The Court
of Appeals ordered the Texas Utility Commission to reconsider that determination
on the basis of the record that existed at the time of the Texas Utility
Commission's original order. In April 2006, the Texas Utility Commission opined
orally that the rate base should be reduced by $57 million and instructed its
Staff to quantify the effect on CenterPoint Houston's rates. In the settlement
of the CenterPoint Houston rate proceeding described in Note 5(d) below, the
parties to the remand proceeding have agreed to settle all issues that could be
raised in the remand. Under the terms of that settlement, CenterPoint Houston
will add riders to its tariff rates under which it will provide rate credits to
retail and wholesale customers for a total of approximately $8 million per year
until a total of $32 million has been credited to customers under those tariff
riders. CenterPoint Houston reduced revenues and established a corresponding
regulatory liability for $32 million in the second quarter of 2006 to reflect
this obligation.
(D) RATE CASES
NATURAL GAS DISTRIBUTION
SOUTHERN GAS OPERATIONS
Mississippi. In February 2006, the Mississippi Public Service Commission
(MPSC) approved a $1 million annual increase in miscellaneous service charges
for Southern Gas Operations, and in March 2006, the MPSC approved a Rate
Regulation Adjustment resulting in a $2 million annual increase in general
service rates. In June 2006, the MPSC approved a January 2006 application for a
one-time recovery of approximately $2 million of costs related to Hurricane
Katrina.
Texas. In April 2005, the Railroad Commission of Texas (Railroad
Commission) established new gas tariffs that increased Southern Gas Operations'
base rate and service revenues by a combined $2 million annually in the
unincorporated environs of its Beaumont/East Texas and South Texas Divisions. In
June and August 2005, Southern Gas Operations filed requests to implement these
same rates within the incorporated cities located in the two
9
divisions. The proposed rates were approved or became effective by operation of
law in all but five of these cities, which cities denied the rate change
requests. Southern Gas Operations appealed the actions of these five cities to
the Railroad Commission. Additionally, 19 cities where new rates had already
gone into effect subsequently challenged the jurisdictional and statutory basis
for implementation of those rates. Southern Gas Operations petitioned the
Railroad Commission for an order declaring that the new rates had been properly
established within these 19 cities.
During the second quarter of 2006, Southern Gas Operations reached
settlement agreements with the last of the cities that were parties to the
Railroad Commission proceedings.
Once all settlement rates are implemented in all jurisdictions including
unincorporated areas, Southern Gas Operations' base rates and miscellaneous
service charges are expected to increase by a total of $17 million annually over
the pre-April 2005 levels. Approximately $4 million of this increase was
reflected in the Company's 2005 revenues. The Company expects approximately $16
million will be reflected in revenues in 2006, and the total $17 million will be
reflected in revenues in 2007. Approximately $3 million of expenditures related
to these rate cases was charged to expense during the second quarter of 2006.
The settlements also provide that these new rates will not change over the next
three to five years.
MINNESOTA GAS
In April 2006, Minnesota Gas revised its gas cost filing for the twelve
months ended June 30, 2005, which had not yet been approved by the Minnesota
Public Utilities Commission (MPUC). Minnesota Gas refined its unbilled revenue
estimate to more accurately reflect the effect of lost and unaccounted for gas.
As a result, Minnesota Gas determined that its gas costs for the years ended
June 30, 2001 through June 30, 2005 were understated. Minnesota Gas' revised gas
cost filing requested approximately $9 million in additional recovery for the
twelve months ended June 30, 2005. The amended filing also requested recovery of
approximately $13 million related to the period from July 1, 2000 through June
30, 2004 and a waiver from the MPUC rules allowing recovery of such costs, since
the gas costs for those years had been previously approved. The filing proposes
recovery of the 2001-2004 costs over a 3-year period beginning in 2007.
In November 2005, Minnesota Gas filed a request with the MPUC to increase
annual rates by approximately $41 million. In December 2005, the MPUC approved
an interim rate increase of approximately $35 million that was implemented
January 1, 2006. Any excess of amounts collected under the interim rates over
the amounts approved in final rates is subject to refund to customers. Hearings
were held in April and June 2006 and a decision by the MPUC is expected in late
2006.
In December 2004, the MPUC opened an investigation to determine whether
Minnesota Gas' practices regarding restoring natural gas service during the
period between October 15 and April 15 (Cold Weather Period) are in compliance
with the MPUC's Cold Weather Rule (CWR), which governs disconnection and
reconnection of customers during the Cold Weather Period. In June 2005, the
Minnesota Office of the Attorney General (OAG) issued its report alleging
Minnesota Gas had violated the CWR and recommended a $5 million penalty. In
addition, in June 2005, CERC was named in a suit filed in the United States
District Court, District of Minnesota on behalf of a purported class of
customers who allege that Minnesota Gas' conduct under the CWR was in violation
of the law. On March 28, 2006 the court gave preliminary approval to a $13.5
million settlement which, if ultimately approved by the court following a
hearing, will resolve all but one small claim against Minnesota Gas which have
or could have been asserted by residential natural gas customers in the CWR
class action. A further hearing by the court to consider approval of this
settlement is expected during the third quarter of 2006. If also approved by the
MPUC, the settlement will resolve the claims made by the OAG. During the fourth
quarter 2005, CERC established a litigation reserve to cover the anticipated
settlement costs under the terms of this settlement.
ELECTRIC TRANSMISSION & DISTRIBUTION
The Texas Utility Commission requires each electric utility to file an
annual Earnings Report providing certain information to enable the Texas Utility
Commission to monitor the electric utilities' earnings and financial condition
within the state. In May 2005, CenterPoint Houston filed its Earnings Report for
the calendar year ended December 31, 2004. CenterPoint Houston's Earnings Report
shows that it earned less than its authorized rate of return on equity in 2004.
10
In October 2005, the Staff filed a memorandum summarizing its review of the
Earnings Reports filed by electric utilities. Based on its review, the Staff
concluded that continuation of CenterPoint Houston's rates could result in
excess retail transmission and distribution revenues of as much as $105 million
and excess wholesale transmission revenues of as much as $31 million annually
and recommended that the Texas Utility Commission initiate a review of the
reasonableness of existing rates.
In December 2005, the Texas Utility Commission considered the Staff report
and agreed to initiate a rate proceeding concerning the reasonableness of
CenterPoint Houston's existing rates for transmission and distribution service
and to require CenterPoint Houston to make a filing by April 15, 2006 to justify
or change those rates. In April 2006, CenterPoint Houston filed cost data and
other information that supported the current rates.
On July 31, 2006, CenterPoint Houston entered into a settlement agreement
with the parties to the proceeding that would resolve the issues raised in this
matter. Under the terms of the agreement, CenterPoint Houston's base rate
revenues will be reduced by a net of approximately $58 million per year. Also,
CenterPoint Houston will commit to increase its energy efficiency expenditures
by an additional $10 million per year over the $13 million included in existing
rates. The expenditures will be made to benefit both residential and commercial
customers. CenterPoint Houston also will fund $10 million per year for programs
providing financial assistance to qualified low-income customers in its service
territory.
The agreement provides for a rate freeze until June 30, 2010 under which
CenterPoint Houston will not seek to increase its base rates and the other
parties will not petition to decrease those rates. The rate freeze is subject to
adjustments for changes related to certain transmission costs, implementation of
the Texas Utility Commission's recently-adopted change to its CTC rule and
certain other changes. The rate freeze does not apply to changes required to
reflect the result of currently pending appeals of the True-Up Order, the
pending appeal of the Texas Utility Commission's order regarding CenterPoint
Houston's final fuel reconciliation, the appeal of the order implementing
CenterPoint Houston's CTC or the implementation of transition charges associated
with current and future securitizations. In addition, CenterPoint Houston will
not be required to file annual earnings reports for the calendar years 2006
through 2008, but will file an earnings report for 2009 no later than March 1,
2010. CenterPoint Houston must make a new base rate filing not later than June
30, 2010, based on a test year ended December 31, 2009, unless the Texas Utility
Commission staff and certain cities with original jurisdiction notify
CenterPoint Houston that such a filing is unnecessary.
The agreement does not provide for an increased storm reserve, but will
permit CenterPoint Houston to amortize its expenditures related to Hurricane
Rita of approximately $4 million per year over a seven-year period and to
amortize regulatory expenses of approximately $2 million per year over a
four-year period, both beginning in the month following the final order. The
agreement will result in a determination that franchise fees payable by
CenterPoint Houston under new franchise agreements with the City of Houston and
certain other municipalities in CenterPoint Houston's service area are deemed
reasonable and necessary, and other revised tariffs proposed in CenterPoint
Houston's filing package will go into effect along with the revised base rates.
The agreement also resolves all issues that could be raised in the Texas
Utility Commission's proceeding to review its decision in CenterPoint Houston's
2001 UCOS case. See Note 5(c) above.
CenterPoint Houston filed the Stipulation and Agreement with the Texas
Utility Commission. Assuming a favorable recommendation on the agreement is
issued by the administrative law judges, the agreement is expected to be
considered by the Texas Utility Commission later this year.
11
(E) CITY OF TYLER, TEXAS DISPUTE
In July 2002, the City of Tyler, Texas, asserted that Southern Gas
Operations had overcharged residential and small commercial customers in that
city for gas costs under supply agreements in effect since 1992. That dispute
was referred to the Railroad Commission by agreement of the parties for a
determination of whether Southern Gas Operations has properly charged and
collected for gas service to its residential and commercial customers in its
Tyler distribution system in accordance with lawful filed tariffs during the
period beginning November 1, 1992, and ending October 31, 2002. In May 2005,
the Railroad Commission issued a final order finding that the Company had
complied with its tariffs, acted prudently in entering into its gas supply
contracts, and prudently managed those contracts. The City of Tyler appealed
this order to a Travis County District Court, but in April 2006, Southern Gas
Operations and the City of Tyler reached a settlement regarding the rates in the
City of Tyler and other aspects of the dispute between them. As contemplated by
that settlement, the City of Tyler's appeal to the district court was dismissed
on July 31, 2006, and the Railroad Commission's final order and findings are no
longer subject to further review or modification.
(6) DERIVATIVE INSTRUMENTS
The Company is exposed to various market risks. These risks arise from
transactions entered into in the normal course of business. The Company utilizes
derivative financial instruments such as physical forward contracts, swaps and
options (Energy Derivatives) to mitigate the impact of changes in its natural
gas businesses on its operating results and cash flows.
Cash Flow Hedges. During each of the six month periods ended June 30, 2005
and 2006, hedge ineffectiveness resulted in a gain of less than $1 million from
derivatives that qualify for and are designated as cash flow hedges. No
component of the derivative instruments' gain or loss was excluded from the
assessment of effectiveness. If it becomes probable that an anticipated
transaction will not occur, the Company realizes in net income the deferred
gains and losses previously recognized in accumulated other comprehensive loss.
Once the anticipated transaction occurs, the accumulated deferred gain or loss
recognized in accumulated other comprehensive loss is reclassified and included
in the Company's Condensed Statements of Consolidated Income under the
"Expenses" caption "Natural gas." Cash flows resulting from these transactions
in non-trading energy derivatives are included in the Condensed Statements of
Consolidated Cash Flows in the same category as the item being hedged. As of
June 30, 2006, the Company expects $1 million ($0.6 million after-tax) in
accumulated other comprehensive loss to be reclassified as an increase in
Natural gas expense during the next twelve months.
The maximum length of time the Company is hedging its exposure to the
variability in future cash flows using financial instruments is primarily two
years with a limited amount of exposure up to ten years. The Company's policy is
not to exceed ten years in hedging its exposure.
Other Derivative Financial Instruments. The Company enters into certain
derivative financial instruments to manage physical commodity price risks that
do not qualify or are not designated as cash flow or fair value hedges under
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
(SFAS No. 133). While the Company utilizes these financial instruments to manage
physical commodity price risks, it does not engage in proprietary or speculative
commodity trading. During the three months ended June 30, 2005 and 2006, the
Company recognized net gains of $4 million and net losses of less than $1
million, respectively, on these derivative financial instruments which are
included in the Condensed Statements of Consolidated Income under the "Expenses"
caption "Natural gas." During the six months ended June 30, 2005 and 2006, the
Company recognized net gains of $6 million and net losses of $8 million,
respectively.
Interest Rate Swaps. During 2002, the Company settled forward-starting
interest rate swaps having an aggregate notional amount of $1.5 billion at a
cost of $156 million, which was recorded in other comprehensive loss and is
being amortized into interest expense over the five-year life of the designated
fixed-rate debt. Amortization of amounts deferred in accumulated other
comprehensive loss for each of the six-month periods ended June 30, 2005 and
2006 was $15 million. As of June 30, 2006, the Company expects $31 million ($20
million after-tax) in accumulated other comprehensive loss to be amortized
during the next twelve months.
12
(7) GOODWILL AND INTANGIBLES
Goodwill as of December 31, 2005 and June 30, 2006 by reportable business
segment is as follows (in millions):
Natural Gas Distribution............................................... $ 746
Pipelines and Field Services........................................... 604
Competitive Natural Gas Sales and Services............................. 339
Other Operations....................................................... 20
------
Total............................................................... $1,709
======
The components of the Company's other intangible assets consist of the
following:
DECEMBER 31, 2005 JUNE 30, 2006
----------------------- -----------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)
Land Use Rights............. $55 $(14) $55 $(14)
Other....................... 22 (7) 22 (8)
--- ---- --- -----
Total.................... $77 $(21) $77 $(22)
=== ==== === =====
Amortization expense for other intangibles during each of the three-month
periods ended June 30, 2005 and 2006 was less than $1 million. Amortization
expense for other intangibles during each of the six-month periods ended June
30, 2005 and 2006 was $1 million. Estimated amortization expense for the
remainder of 2006 and the five succeeding fiscal years is as follows (in
millions):
2006........................ $ 1
2007........................ 3
2008........................ 3
2009........................ 3
2010........................ 2
2011........................ 2
---
Total.................... $14
===
(8) COMPREHENSIVE INCOME
The following table summarizes the components of total comprehensive income
(net of tax):
FOR THE THREE MONTHS ENDED FOR THE SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- ------------------------
2005 2006 2005 2006
---- ---- ---- ----
(IN MILLIONS)
Net income .................................................. $54 $194 $121 $282
--- ---- ---- ----
Other comprehensive income:
Net deferred gain (loss) from cash flow hedges ........... 1 (2) 10 (5)
Reclassification of deferred loss from cash
flow hedges realized in net income .................... 2 9 8 6
Other comprehensive income from discontinued operations .. 4 -- 4 --
--- ---- ---- ----
Other comprehensive income .................................. 7 7 22 1
--- ---- ---- ----
Comprehensive income ........................................ $61 $201 $143 $283
=== ==== ==== ====
13
The following table summarizes the components of accumulated other
comprehensive loss:
DECEMBER 31, JUNE 30,
2005 2006
------------ --------
(IN MILLIONS)
Minimum pension liability adjustment......................... $(15) $(15)
Net deferred loss from cash flow hedges...................... (23) (22)
---- ----
Total accumulated other comprehensive loss .................. $(38) $(37)
==== ====
(9) CAPITAL STOCK
CenterPoint Energy has 1,020,000,000 authorized shares of capital stock,
comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000
shares of $0.01 par value preferred stock. At December 31, 2005, 310,324,905
shares of CenterPoint Energy common stock were issued and 310,324,739 shares of
CenterPoint Energy common stock were outstanding. At June 30, 2006, 311,630,221
shares of CenterPoint Energy common stock were issued and 311,630,055 shares of
CenterPoint Energy common stock were outstanding. Outstanding common shares
exclude 166 treasury shares at both December 31, 2005 and June 30, 2006.
(10) LONG-TERM DEBT AND RECEIVABLES FACILITY
(A) LONG-TERM DEBT
Senior Notes. In May 2006, CERC Corp. issued $325 million aggregate
principal amount of senior notes due in May 2016 with an interest rate of 6.15%.
The proceeds from the sale of the senior notes will be used for general
corporate purposes, including repayment or refinancing of debt (including $145
million of CERC's 8.90% debentures due December 15, 2006), capital expenditures
and working capital.
Revolving Credit Facilities. In March 2006, the Company, CenterPoint
Houston and CERC Corp., entered into amended and restated bank credit
facilities. The Company replaced its $1 billion five-year revolving credit
facility with a $1.2 billion five-year revolving credit facility. The facility
has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 60 basis
points based on the Company's current credit ratings, as compared to LIBOR plus
87.5 basis points for borrowings under the facility it replaced. The facility
contains covenants, including a debt to earnings before interest, taxes,
depreciation and amortization covenant.
CenterPoint Houston replaced its $200 million five-year revolving credit
facility with a $300 million five-year revolving credit facility. The facility
has a first drawn cost of LIBOR plus 45 basis points based on CenterPoint
Houston's current credit ratings, as compared to LIBOR plus 75 basis points for
borrowings under the facility it replaced. The facility contains covenants,
including a debt, excluding transition bonds, to total capitalization covenant
of 65%.
CERC Corp. replaced its $400 million five-year revolving credit facility
with a $550 million five-year revolving credit facility. The facility has a
first drawn cost of LIBOR plus 45 basis points based on CERC Corp.'s current
credit ratings, as compared to LIBOR plus 55 basis points for borrowings under
the facility it replaced. The facility contains covenants, including a debt to
total capitalization covenant of 65%.
Under each of the credit facilities, an additional utilization fee of 10
basis points applies to borrowings any time more than 50% of the facility is
utilized, and the spread to LIBOR fluctuates based on the borrower's credit
rating. Borrowings under each of the facilities are subject to customary terms
and conditions. However, there is no requirement that the Company, CenterPoint
Houston or CERC Corp. make representations prior to borrowings as to the absence
of material adverse changes or litigation that could be expected to have a
material adverse effect. Borrowings under each of the credit facilities are
subject to acceleration upon the occurrence of events of default that the
Company, CenterPoint Houston or CERC Corp. consider customary.
As of June 30, 2006, the Company had no borrowings and approximately $28
million of outstanding letters of credit under its $1.2 billion credit facility,
CenterPoint Houston had no borrowings and approximately $4 million of
outstanding letters of credit under its $300 million credit facility and CERC
Corp. had no borrowings under its $550 million credit facility. Additionally,
the Company, CenterPoint Houston and CERC Corp. were in compliance with all
covenants as of June 30, 2006.
14
Convertible Debt. On May 19, 2003, the Company issued $575 million
aggregate principal amount of convertible senior notes due May 15, 2023 with an
interest rate of 3.75%. Holders may convert each of their notes into shares of
CenterPoint Energy common stock at a conversion rate of 87.4094 shares of common
stock per $1,000 principal amount of notes at any time prior to maturity, under
the following circumstances: (1) if the last reported sale price of CenterPoint
Energy common stock for at least 20 trading days during the period of 30
consecutive trading days ending on the last trading day of the previous calendar
quarter is greater than or equal to 120% or, following May 15, 2008, 110% of the
conversion price per share of CenterPoint Energy common stock on such last
trading day, (2) if the notes have been called for redemption, (3) during any
period in which the credit ratings assigned to the notes by both Moody's
Investors Service, Inc. (Moody's) and Standard & Poor's Ratings Services (S&P),
a division of The McGraw-Hill Companies, are lower than Ba2 and BB,
respectively, or the notes are no longer rated by at least one of these ratings
services or their successors, or (4) upon the occurrence of specified corporate
transactions, including the distribution to all holders of CenterPoint Energy
common stock of certain rights entitling them to purchase shares of CenterPoint
Energy common stock at less than the last reported sale price of a share of
CenterPoint Energy common stock on the trading day prior to the declaration date
of the distribution or the distribution to all holders of CenterPoint Energy
common stock of the Company's assets, debt securities or certain rights to
purchase the Company's securities, which distribution has a per share value
exceeding 15% of the last reported sale price of a share of CenterPoint Energy
common stock on the trading day immediately preceding the declaration date for
such distribution. The notes originally had a conversion rate of 86.3558 shares
of common stock per $1,000 principal amount of notes. However, effective
February 16, 2006, the conversion rate increased to 87.4094 in accordance with
the terms of the notes due to an increase in the amount of the dividend per
common share paid by the Company in the first quarter of 2006.
Holders have the right to require the Company to purchase all or any
portion of the notes for cash on May 15, 2008, May 15, 2013 and May 15, 2018 for
a purchase price equal to 100% of the principal amount of the notes. The
convertible senior notes also have a contingent interest feature requiring
contingent interest to be paid to holders of notes commencing on or after May
15, 2008, in the event that the average trading price of a note for the
applicable five-trading-day period equals or exceeds 120% of the principal
amount of the note as of the day immediately preceding the first day of the
applicable six-month interest period. For any six-month period, contingent
interest will be equal to 0.25% of the average trading price of the note for the
applicable five-trading-day period.
In August 2005, the Company accepted for exchange approximately $572
million aggregate principal amount of its 3.75% convertible senior notes due
2023 (Old Notes) for an equal amount of its new 3.75% convertible senior notes
due 2023 (New Notes). Old Notes of approximately $3 million remain outstanding.
Under the terms of the New Notes, which are substantially similar to the Old
Notes, settlement of the principal portion will be made in cash rather than
stock.
On December 17, 2003, the Company issued $255 million aggregate principal
amount of convertible senior notes due January 15, 2024 with an interest rate of
2.875%. Holders may convert each of their notes into shares of CenterPoint
Energy common stock at a conversion rate of 79.0165 shares of common stock per
$1,000 principal amount of notes at any time prior to maturity, under the
following circumstances: (1) if the last reported sale price of CenterPoint
Energy common stock for at least 20 trading days during the period of 30
consecutive trading days ending on the last trading day of the previous calendar
quarter is greater than or equal to 120% of the conversion price per share of
CenterPoint Energy common stock on such last trading day, (2) if the notes have
been called for redemption, (3) during any period in which the credit ratings
assigned to the notes by both Moody's and S&P are lower than Ba2 and BB,
respectively, or the notes are no longer rated by at least one of these ratings
services or their successors, or (4) upon the occurrence of specified corporate
transactions, including the distribution to all holders of CenterPoint Energy
common stock of certain rights entitling them to purchase shares of CenterPoint
Energy common stock at less than the last reported sale price of a share of
CenterPoint Energy common stock on the trading day prior to the declaration date
of the distribution or the distribution to all holders of CenterPoint Energy
common stock of the Company's assets, debt securities or certain rights to
purchase the Company's securities, which distribution has a per share value
exceeding 15% of the last reported sale price of a share of CenterPoint Energy
common stock on the trading day immediately preceding the declaration date for
such distribution. The notes originally had a conversion rate of 78.0640 shares
of common stock per $1,000 principal amount of notes. However, effective
February 16, 2006, the conversion rate increased to 79.0165 in accordance with
the terms of the notes due to an increase in the amount of the dividend per
common share paid by the Company in the first quarter of 2006.
15
Under the original terms of these convertible senior notes, CenterPoint
Energy could elect to satisfy part or all of its conversion obligation by
delivering cash in lieu of shares of CenterPoint Energy. On December 13, 2004,
the Company entered into a supplemental indenture with respect to these
convertible senior notes in order to eliminate its right to settle the
conversion of the notes solely in shares of its common stock. Holders have the
right to require the Company to purchase all or any portion of the notes for
cash on January 15, 2007, January 15, 2012 and January 15, 2017 for a purchase
price equal to 100% of the principal amount of the notes. As of June 30, 2006,
these notes were classified as current portion of other long-term debt in the
Condensed Consolidated Balance Sheets. The convertible senior notes also have a
contingent interest feature requiring contingent interest to be paid to holders
of notes commencing on or after January 15, 2007, in the event that the average
trading price of a note for the applicable five-trading-day period equals or
exceeds 120% of the principal amount of the note as of the day immediately
preceding the first day of the applicable six-month interest period. For any
six-month period, contingent interest will be equal to 0.25% of the average
trading price of the note for the applicable five-trading-day period.
Junior Subordinated Debentures (Trust Preferred Securities). In February
1997, a Delaware statutory business trust created by CenterPoint Energy (HL&P
Capital Trust II) issued to the public $100 million aggregate amount of capital
securities. The trust used the proceeds of the offering to purchase junior
subordinated debentures issued by CenterPoint Energy having an interest rate and
maturity date that correspond to the distribution rate and the mandatory
redemption date of the capital securities. The amount of outstanding junior
subordinated debentures discussed above was included in long-term debt as of
December 31, 2005 and June 30, 2006.
The junior subordinated debentures are the trust's sole assets and their
entire operations. CenterPoint Energy considers its obligations under the
Amended and Restated Declaration of Trust, Indenture, Guaranty Agreement and,
where applicable, Agreement as to Expenses and Liabilities, relating to the
capital securities, taken together, to constitute a full and unconditional
guarantee by CenterPoint Energy of the trust's obligations with respect to the
capital securities.
The capital securities are mandatorily redeemable upon the repayment of the
related series of junior subordinated debentures at their stated maturity or
earlier redemption. Subject to some limitations, CenterPoint Energy has the
option of deferring payments of interest on the junior subordinated debentures.
During any deferral or event of default, CenterPoint Energy may not pay
dividends on its capital stock. As of June 30, 2006, no interest payments on the
junior subordinated debentures had been deferred.
The outstanding aggregate liquidation amount, distribution rate and
mandatory redemption date of the capital securities of the trust described above
and the identity and similar terms of the related series of junior subordinated
debentures are as follows:
AGGREGATE LIQUIDATION
AMOUNTS AS OF DISTRIBUTION MANDATORY
------------------------ RATE/ REDEMPTION
DECEMBER 31, JUNE 30, INTEREST DATE/
TRUST 2005 2006 RATE MATURITY DATE JUNIOR SUBORDINATED DEBENTURES
----- ------------ --------- ------------ ------------- ------------------------------
(IN MILLIONS)
HL&P Capital Trust II.................... $100 $100 8.257% February 2037 8.257% Junior Subordinated
Deferrable Interest Debentures
Series B
(B) RECEIVABLES FACILITY
In January 2006, CERC's $250 million receivables facility was extended to
January 2007. As of June 30, 2006, no amounts were funded under CERC's
receivables facility. The facility was temporarily increased to $375 million for
the period from January 2006 to June 2006.
Funding under the receivables facility averaged $181 million and $121
million for the six months ended June 30, 2005 and 2006, respectively. Sales of
receivables were approximately $424 million and $209 million for the three
months ended June 30, 2005 and 2006, respectively, and $944 million and $555
million for the six months ended June 30, 2005 and 2006, respectively.
16
(11) COMMITMENTS AND CONTINGENCIES
(A) NATURAL GAS SUPPLY COMMITMENTS
Natural gas supply commitments include natural gas contracts related to the
Company's natural gas distribution and competitive natural gas sales and
services operations, which have various quantity requirements and durations that
are not classified as non-trading derivatives assets and liabilities in the
Company's Consolidated Balance Sheets as of December 31, 2005 and June 30, 2006
as these contracts meet the SFAS No. 133 exception to be classified as "normal
purchases contracts" or do not meet the definition of a derivative. Natural gas
supply commitments also include natural gas transportation contracts which do
not meet the definition of a derivative. Minimum payment obligations for natural
gas supply contracts are approximately $367 million for the remaining six months
in 2006, $627 million in 2007, $174 million in 2008, $118 million in 2009, $118
million in 2010 and $721 million in 2011 and thereafter.
(B) CAPITAL COMMITMENTS
In October 2005, CenterPoint Energy Gas Transmission Company (CEGT), a
wholly owned subsidiary of CERC Corp., signed a 10-year firm transportation
agreement with XTO Energy (XTO) to transport 600 million cubic feet (MMcf) per
day of natural gas from Carthage, Texas to CEGT's Perryville hub in Northeast
Louisiana. To accommodate this transaction, CEGT filed a certificate application
with the FERC in March 2006 to build a 172 mile, 42-inch diameter pipeline, and
related compression facilities at an estimated cost of $425 million. The
capacity of the pipeline under this filing will be 1.275 billion cubic feet
(Bcf) per day. CEGT has signed firm contracts for substantially the full
capacity of the pipeline. Based on strong interest expressed in an open season
earlier this year, and subject to FERC approval, CERC expects to expand capacity
of the pipeline to 1.5 Bcf per day. During the four-year period subsequent to
the in-service date of the pipeline, XTO can request, and subject to mutual
negotiations that meet specific financial parameters, CEGT would construct a 67
mile extension from CEGT's Perryville hub to an interconnect with Texas Eastern
Gas Transmission at Union Church, Mississippi.
(C) LEGAL, ENVIRONMENTAL AND OTHER REGULATORY MATTERS
LEGAL MATTERS
RRI Indemnified Litigation
The Company, CenterPoint Houston or their predecessor, Reliant Energy, and
certain of their former subsidiaries are named as defendants in several lawsuits
described below. Under a master separation agreement between the Company and
Reliant Energy, Inc. (formerly Reliant Resources, Inc.) (RRI), the Company and
its subsidiaries are entitled to be indemnified by RRI for any losses, including
attorneys' fees and other costs, arising out of the lawsuits described below
under Electricity and Gas Market Manipulation Cases and Other Class Action
Lawsuits. Pursuant to the indemnification obligation, RRI is defending the
Company and its subsidiaries to the extent named in these lawsuits. The ultimate
outcome of these matters cannot be predicted at this time.
Electricity and Gas Market Manipulation Cases. A large number of lawsuits
have been filed against numerous market participants and remain pending in
federal court in California, Colorado and Nevada and in state court in
California and Nevada in connection with the operation of the electricity and
natural gas markets in California and certain other western states in 2000-2001,
a time of power shortages and significant increases in prices. These lawsuits,
many of which have been filed as class actions, are based on a number of legal
theories, including violation of state and federal antitrust laws, laws against
unfair and unlawful business practices, the federal Racketeer Influenced Corrupt
Organization Act, false claims statutes and similar theories and breaches of
contracts to supply power to governmental entities. Plaintiffs in these
lawsuits, which include state officials and governmental entities as well as
private litigants, are seeking a variety of forms of relief, including recovery
of compensatory damages (in some cases in excess of $1 billion), a trebling of
compensatory damages and punitive damages, injunctive relief, restitution,
interest due, disgorgement, civil penalties and fines, costs of suit, attorneys'
fees and divestiture of assets. The Company's former subsidiary, RRI, was a
participant in the California markets, owning generating plants in the state and
participating in both electricity and natural gas trading in that state and in
western power markets generally.
17
The Company and/or Reliant Energy have been named in approximately 30 of
these lawsuits, which were instituted between 2001 and 2006 and are pending in
California state court in San Diego County, in Nevada state court in Clark
County, in federal district court in Colorado, Nevada and the Northern District
of California and before the Ninth Circuit Court of Appeals. However, the
Company, CenterPoint Houston and Reliant Energy were not participants in the
electricity or natural gas markets in California. The Company and Reliant Energy
have been dismissed from certain of the lawsuits, either voluntarily by the
plaintiffs or by order of the court, and the Company believes it is not a proper
defendant in the remaining cases and will continue to seek dismissal from such
remaining cases.
To date, several of the electricity complaints have been dismissed, and
several of the dismissals have been affirmed by appellate courts. Others have
been resolved by the settlement described in the following paragraph. Four of
the gas complaints have also been dismissed based on defendants' claims of
federal preemption and the filed rate doctrine, and these dismissals have been
appealed. In June 2005, a San Diego state court refused to dismiss other gas
complaints on the same basis. The other gas cases remain in the early procedural
stages.
On August 12, 2005, RRI reached a settlement with the FERC enforcement
staff, the states of California, Washington and Oregon, California's three
largest investor-owned utilities, classes of consumers from California and other
western states, and a number of California city and county government entities
that resolves their claims against RRI related to the operation of the
electricity markets in California and certain other western states in 2000-2001.
The settlement also resolves the claims of the three states and the
investor-owned utilities related to the 2000-2001 natural gas markets. The
settlement has been approved by the FERC, by the California Public Utilities
Commission, and by the courts in which the class action cases are pending. Two
parties have appealed the courts' approval of the settlement to the Ninth
Circuit Court of Appeals. A party in the FERC proceedings filed a motion for
rehearing of the FERC's order approving the settlement, which the FERC denied in
May 2006. That party has filed for review of the FERC's orders in the Ninth
Circuit Court of Appeals. The Company is not a party to the settlement, but may
rely on the settlement as a defense to any claims brought against it related to
the time when the Company was an affiliate of RRI. The terms of the settlement
do not require payment by the Company.
Other Class Action Lawsuits. In May 2002, three class action lawsuits were
filed in federal district court in Houston on behalf of participants in various
employee benefits plans sponsored by the Company. Two of the lawsuits were
dismissed without prejudice. In the remaining lawsuit, the Company and certain
current and former members of its benefits committee are defendants. That
lawsuit alleged that the defendants breached their fiduciary duties to various
employee benefits plans, directly or indirectly sponsored by the Company, in
violation of the Employee Retirement Income Security Act of 1974 by permitting
the plans to purchase or hold securities issued by the Company when it was
imprudent to do so, including after the prices for such securities became
artificially inflated because of alleged securities fraud engaged in by the
defendants. The complaint sought monetary damages for losses suffered on behalf
of the plans and a putative class of plan participants whose accounts held
CenterPoint Energy or RRI securities, as well as restitution. In January 2006,
the federal district judge granted a motion for summary judgment filed by the
Company and the individual defendants. The plaintiffs have filed an appeal of
the ruling to the Fifth Circuit Court of Appeals. The Company believes that this
lawsuit is without merit and will continue to vigorously defend the case.
However, the ultimate outcome of this matter cannot be predicted at this time.
Other Legal Matters
Natural Gas Measurement Lawsuits. CERC Corp. and certain of its
subsidiaries are defendants in a suit filed in 1997 under the Federal False
Claims Act alleging mismeasurement of natural gas produced from federal and
Indian lands. The suit seeks undisclosed damages, along with statutory
penalties, interest, costs, and fees. The complaint is part of a larger series
of complaints filed against 77 natural gas pipelines and their subsidiaries and
affiliates. An earlier single action making substantially similar allegations
against the pipelines was dismissed by the federal district court for the
District of Columbia on grounds of improper joinder and lack of jurisdiction. As
a result, the various individual complaints were filed in numerous courts
throughout the country. This case has been consolidated, together with the other
similar False Claims Act cases, in the federal district court in Cheyenne,
Wyoming.
18
In addition, CERC Corp. and certain of its subsidiaries are defendants in
two mismeasurement lawsuits brought against approximately 245 pipeline companies
and their affiliates pending in state court in Stevens County, Kansas. In one
case (originally filed in May 1999 and amended four times), the plaintiffs
purport to represent a class of royalty owners who allege that the defendants
have engaged in systematic mismeasurement of the volume of natural gas for more
than 25 years. The plaintiffs amended their petition in this suit in July 2003
in response to an order from the judge denying certification of the plaintiffs'
alleged class. In the amendment the plaintiffs dismissed their claims against
certain defendants (including two CERC subsidiaries), limited the scope of the
class of plaintiffs they purport to represent and eliminated previously asserted
claims based on mismeasurement of the Btu content of the gas. The same
plaintiffs then filed a second lawsuit, again as representatives of a class of
royalty owners, in which they assert their claims that the defendants have
engaged in systematic mismeasurement of the Btu content of natural gas for more
than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along
with statutory penalties, treble damages, interest, costs and fees. CERC and its
subsidiaries believe that there has been no systematic mismeasurement of gas and
that the suits are without merit. CERC does not expect the ultimate outcome to
have a material impact on the financial condition, results of operations or cash
flows of either the Company or CERC.
Gas Cost Recovery Litigation. In October 2002, a suit was filed in state
district court in Wharton County, Texas against the Company, CERC, Entex Gas
Marketing Company, and certain non-affiliated companies alleging fraud,
violations of the Texas Deceptive Trade Practices Act, violations of the Texas
Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and
Antitrust Act with respect to rates charged to certain consumers of natural gas
in the State of Texas. Subsequently, the plaintiffs added as defendants
CenterPoint Energy Marketing Inc., CEGT, United Gas, Inc., Louisiana Unit Gas
Transmission Company, CenterPoint Energy Pipeline Services, Inc., and
CenterPoint Energy Trading and Transportation Group, Inc., all of which are
subsidiaries of the Company. The plaintiffs alleged that defendants inflated the
prices charged to certain consumers of natural gas. In February 2003, a similar
suit was filed in state court in Caddo Parish, Louisiana against CERC with
respect to rates charged to a purported class of certain consumers of natural
gas and gas service in the State of Louisiana. In February 2004, another suit
was filed in state court in Calcasieu Parish, Louisiana against CERC seeking to
recover alleged overcharges for gas or gas services allegedly provided by
Southern Gas Operations to a purported class of certain consumers of natural gas
and gas service without advance approval by the Louisiana Public Service
Commission (LPSC). In October 2004, a similar case was filed in district court
in Miller County, Arkansas against the Company, CERC, Entex Gas Marketing
Company, CEGT, CenterPoint Energy Field Services, CenterPoint Energy Pipeline
Services, Inc., CenterPoint Energy - Mississippi River Transmission Corp.
(CEMRT) and other non-affiliated companies alleging fraud, unjust enrichment and
civil conspiracy with respect to rates charged to certain consumers of natural
gas in at least the states of Arkansas, Louisiana, Mississippi, Oklahoma and
Texas. Subsequently, the plaintiffs dropped as defendants CEGT and CEMRT. At the
time of the filing of each of the Caddo and Calcasieu Parish cases, the
plaintiffs in those cases filed petitions with the LPSC relating to the same
alleged rate overcharges. The Caddo and Calcasieu Parish cases have been stayed
pending the resolution of the respective proceedings by the LPSC. The plaintiffs
in the Miller County case seek class certification, but the proposed class has
not been certified. In February 2005, the Wharton County case was removed to
federal district court in Houston, Texas, and in March 2005, the plaintiffs
voluntarily moved to dismiss the case and agreed not to refile the claims
asserted unless the Miller County case is not certified as a class action or is
later decertified. The range of relief sought by the plaintiffs in these cases
includes injunctive and declaratory relief, restitution for the alleged
overcharges, exemplary damages or trebling of actual damages, civil penalties
and attorney's fees. In these cases, the Company, CERC and their affiliates deny
that they have overcharged any of their customers for natural gas and believe
that the amounts recovered for purchased gas have been in accordance with what
is permitted by state and municipal regulatory authorities. The allegations in
these cases are similar to those asserted in the City of Tyler proceeding, as
described in Note 5(e). The Company and CERC do not expect the outcome of these
matters to have a material impact on the financial condition, results of
operations or cash flows of either the Company or CERC.
Pipeline Safety Compliance. Pursuant to an order from the Minnesota Office
of Pipeline Safety, CERC substantially completed removal of certain
non-code-compliant components from a portion of its distribution system by
December 2, 2005. The components were installed by a predecessor company, which
was not affiliated with CERC during the period in which the components were
installed. In November 2005, Minnesota Gas filed a request with the MPUC to
recover the capitalized expenditures (approximately $39 million) and related
expenses, together with a return on the capitalized portion through rates as
part of its existing rate case as further discussed in Note 5(d).
19
Minnesota Cold Weather Rule. For a discussion of this matter, see Note 5(d)
above.
ENVIRONMENTAL MATTERS
Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are
among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish
and Bossier Parish, Louisiana. The suits allege that, at some unspecified date
prior to 1985, the defendants allowed or caused hydrocarbon or chemical
contamination of the Wilcox Aquifer, which lies beneath property owned or leased
by certain of the defendants and which is the sole or primary drinking water
aquifer in the area. The primary source of the contamination is alleged by the
plaintiffs to be a gas processing facility in Haughton, Bossier Parish,
Louisiana known as the "Sligo Facility," which was formerly operated by a
predecessor in interest of CERC Corp. This facility was purportedly used for
gathering natural gas from surrounding wells, separating liquid hydrocarbons
from the natural gas for marketing, and transmission of natural gas for
distribution.
Beginning about 1985, the predecessors of certain CERC Corp. defendants
engaged in a voluntary remediation of any subsurface contamination of the
groundwater below the property they owned or leased. This work has been done in
conjunction with and under the direction of the Louisiana Department of
Environmental Quality. The plaintiffs seek monetary damages for alleged damage
to the aquifer underlying their property, including the cost of restoring their
property to its original condition and damages for diminution of value of their
property. In addition, plaintiffs seek damages for trespass, punitive, and
exemplary damages. The Company does not expect the ultimate cost associated with
resolving this matter to have a material impact on the financial condition,
results of operations or cash flows of either the Company or CERC.
Manufactured Gas Plant Sites. CERC and its predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed
remediation on two sites, other than ongoing monitoring and water treatment.
There are five remaining sites in CERC's Minnesota service territory. CERC
believes that it has no liability with respect to two of these sites.
At June 30, 2006, CERC had accrued $14 million for remediation of these
Minnesota sites. At June 30, 2006, the estimated range of possible remediation
costs for these sites was $4 million to $35 million based on remediation
continuing for 30 to 50 years. The cost estimates are based on studies of a site
or industry average costs for remediation of sites of similar size. The actual
remediation costs will be dependent upon the number of sites to be remediated,
the participation of other potentially responsible parties (PRP), if any, and
the remediation methods used. CERC has utilized an environmental expense tracker
mechanism in its rates in Minnesota to recover estimated costs in excess of
insurance recovery. As of June 30, 2006, CERC has collected $13 million from
insurance companies and rate payers to be used for future environmental
remediation.
In addition to the Minnesota sites, the United States Environmental
Protection Agency and other regulators have investigated MGP sites that were
owned or operated by CERC or may have been owned by one of its former
affiliates. CERC has been named as a defendant in two lawsuits, one filed in
United States District Court, District of Maine and the other filed in Middle
District of Florida, Jacksonville Division, under which contribution is sought
by private parties for the cost to remediate former MGP sites based on the
previous ownership of such sites by former affiliates of CERC or its divisions.
CERC has also been identified as a PRP by the State of Maine for a site that is
the subject of one of the lawsuits. In March 2005, the federal district court
considering the suit for contribution in Florida granted CERC's motion to
dismiss on the grounds that CERC was not an "operator" of the site as had been
20
alleged. The plaintiff in that case has filed an appeal of the court's dismissal
of CERC. In June 2006 the federal district court in Maine that is considering
the other suit ruled that the current owner of the site is responsible for site
remediation but that an additional evidentiary hearing is required to determine
if other potentially responsible parties, including CERC, would have to
contribute to that remediation. The Company is investigating details regarding
these sites and the range of environmental expenditures for potential
remediation. However, CERC believes it is not liable as a former owner or
operator of those sites under the Comprehensive Environmental, Response,
Compensation and Liability Act of 1980, as amended, and applicable state
statutes, and is vigorously contesting those suits and its designation as a PRP.
Mercury Contamination. The Company's pipeline and distribution operations
have in the past employed elemental mercury in measuring and regulating
equipment. It is possible that small amounts of mercury may have been spilled in
the course of normal maintenance and replacement operations and that these
spills may have contaminated the immediate area with elemental mercury. The
Company has found this type of contamination at some sites in the past, and the
Company has conducted remediation at these sites. It is possible that other
contaminated sites may exist and that remediation costs may be incurred for
these sites. Although the total amount of these costs is not known at this time,
based on the Company's experience and that of others in the natural gas industry
to date and on the current regulations regarding remediation of these sites, the
Company believes that the costs of any remediation of these sites will not be
material to the Company's financial condition, results of operations or cash
flows.
Asbestos. Some facilities owned by the Company contain or have contained
asbestos insulation and other asbestos-containing materials. The Company or its
subsidiaries have been named, along with numerous others, as a defendant in
lawsuits filed by a number of individuals who claim injury due to exposure to
asbestos. Some of the claimants have worked at locations owned by the Company,
but most existing claims relate to facilities previously owned by the Company or
its subsidiaries. The Company anticipates that additional claims like those
received may be asserted in the future. In 2004, the Company sold its generating
business, to which most of these claims relate, to Texas Genco LLC, which is now
known as NRG Texas LP (NRG). Under the terms of the arrangements regarding
separation of the generating business from the Company and its sale to Texas
Genco LLC, ultimate financial responsibility for uninsured losses from claims
relating to the generating business has been assumed by Texas Genco LLC and its
successor, but the Company has agreed to continue to defend such claims to the
extent they are covered by insurance maintained by the Company, subject to
reimbursement of the costs of such defense from the purchaser. Although their
ultimate outcome cannot be predicted at this time, the Company intends to
continue vigorously contesting claims that it does not consider to have merit
and does not expect, based on its experience to date, these matters, either
individually or in the aggregate, to have a material adverse effect on the
Company's financial condition, results of operations or cash flows.
Other Environmental. From time to time the Company has received notices
from regulatory authorities or others regarding its status as a PRP in
connection with sites found to require remediation due to the presence of
environmental contaminants. In addition, the Company has been named from time to
time as a defendant in litigation related to such sites. Although the ultimate
outcome of such matters cannot be predicted at this time, the Company does not
expect, based on its experience to date, these matters, either individually or
in the aggregate, to have a material adverse effect on the Company's financial
condition, results of operations or cash flows.
OTHER PROCEEDINGS
The Company is involved in other legal, environmental, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding matters arising in the ordinary course of business. Some of
these proceedings involve substantial amounts. The Company regularly analyzes
current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. The Company does not
expect the disposition of these matters to have a material adverse effect on the
Company's financial condition, results of operations or cash flows.
TAX CONTINGENCIES
CenterPoint Energy's consolidated federal income tax returns have been
audited and settled through the 1996 tax year.
21
In the audits of the 1997 through 2003 tax years, the IRS proposed to
disallow all deductions for original issue discount (OID) including interest
paid relating to the Company's 2.0% Zero Premium Exchangeable Subordinated Notes
(ZENS), and the interest paid on the 7% Automatic Common Exchange Securities
(ACES), redeemed in 1999. The IRS contended that (1) those instruments, in
combination with the Company's long position in TW Common, constituted a
straddle under Sections 1092 and 246 of the Internal Revenue Code of 1986, as
amended and (2) the indebtedness underlying those instruments was incurred to
carry the TW Common.
The Company reached agreement with the IRS on terms of a settlement
regarding the tax treatment of the Company's ZENS and its former ACES. On July
17, 2006, the Company signed a Closing Agreement prepared by the IRS and the
Company for the tax years 1999 through 2029 with respect to the ZENS issue. The
agreement reached with the IRS and the Closing Agreement are subject to approval
by the Joint Committee on Taxation of the U.S. Congress. Under the terms of the
agreement reached with the IRS, the Company will pay approximately $64 million
in previously accrued taxes associated with the ACES and the ZENS and will
reduce its future interest deductions associated with the ZENS. As a result of
the agreement reached with the IRS, the Company reduced its previously accrued
tax and related interest reserves by approximately $119 million in the second
quarter of 2006, and will no longer accrue a quarterly reserve.
The Company has also established reserves for other significant tax items
including issues relating to prior acquisitions and dispositions of business
operations, certain positions taken with respect to state tax filings and
certain items related to employee benefits. The total amount reserved for the
other tax items was approximately $60 million and $44 million as of December 31,
2005 and June 30, 2006, respectively.
GUARANTEES
Prior to the Company's distribution of its ownership in RRI to its
shareholders, CERC had guaranteed certain contractual obligations of what became
RRI's trading subsidiary. Under the terms of the separation agreement between
the companies, RRI agreed to extinguish all such guarantee obligations prior to
separation, but when separation occurred in September 2002, RRI had been unable
to extinguish all obligations. To secure the Company and CERC against
obligations under the remaining guarantees, RRI agreed to provide cash or
letters of credit for the benefit of CERC and the Company, and agreed to use
commercially reasonable efforts to extinguish the remaining guarantees. The
Company's current exposure under the remaining guarantees relates to CERC's
guarantee of the payment by RRI of demand charges related to transportation
contracts with one counterparty. The demand charges are approximately $53
million per year in 2006 through 2015, $49 million in 2016, $38 million in 2017
and $13 million in 2018. As a result of changes in market conditions, the
Company's potential exposure under that guarantee currently exceeds the security
provided by RRI. The Company has requested RRI to increase the amount of its
existing letters of credit or, in the alternative, to obtain a release of CERC's
obligations under the guarantee, and the Company and RRI are pursuing other
alternatives. On June 30, 2006, the RRI trading subsidiary and CERC jointly
filed a complaint at the FERC against the counterparty on the CERC guarantee. In
the complaint, the RRI trading subsidiary seeks a determination by the FERC that
the security held by the counterparty exceeds the level permitted by the FERC's
policies. The complaint asks the FERC to require the counterparty to release
CERC from its guarantee obligation and, in its place accept (i) a guarantee from
RRI of the obligations of the RRI trading subsidiary, and (ii) letters of credit
equal to (A) one year of demand charges for a transportation agreement related
to a 2003 expansion of the counterparty's pipeline, and (B) three months of
demand charges for three other transportation agreements held by the RRI trading
subsidiary. On July 20, 2006, the counterparty filed its answer to the
complaint, arguing that CERC is contractually bound to continue the guarantee
and that the amount of the guarantee does not violate the FERC's policies. The
complaint is in its beginning stages, and it is presently unknown what action
the FERC may take on the complaint. The RRI trading subsidiary continues to meet
its obligations under the transportation contracts.
NUCLEAR DECOMMISSIONING FUND COLLECTIONS
Pursuant to regulatory requirements and its tariff, CenterPoint Houston, as
collection agent, collects from its transmission and distribution customers the
nuclear decommissioning charge assessed with respect to the 30.8% ownership
interest in the South Texas Project which it owned when it was part of an
integrated electric utility. Amounts collected are transferred to nuclear
decommissioning trusts maintained by the current owner of that interest in the
South Texas Project. During 2003 and 2004, $2.9 million was transferred each
year and $3.2 million was transferred in 2005. There are various investment
restrictions imposed on owners of nuclear generating stations by the Texas
Utility Commission and the NRC relating to nuclear decommissioning trusts.
Pursuant to the provisions of both a separation agreement and a final order of
the Texas Utility Commission relating to the 2005 transfer of
22
ownership to Texas Genco LLC, now NRG, CenterPoint Houston and a subsidiary of
NRG were, until July 1, 2006, jointly administering the decommissioning funds
through the Nuclear Decommissioning Trust Investment Committee. On June 9, 2006,
the Texas Utility Commission approved an application by CenterPoint Houston and
an NRG subsidiary to name the NRG subsidiary as the sole fund administrator. As
a result, CenterPoint Houston is no longer responsible for administration of
decommissioning funds it collects as collection agent.
(12) EARNINGS PER SHARE
The following table reconciles numerators and denominators of the Company's
basic and diluted earnings per share calculations:
FOR THE THREE MONTHS ENDED FOR THE SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------------- ---------------------------
2005 2006 2005 2006
------------ ------------ ------------ ------------
(IN MILLIONS, EXCEPT SHARE AND PER SHARE AMOUNTS)
Basic earnings per share calculation:
Income from continuing operations before extraordinary item ..... $ 27 $ 194 $ 94 $ 282
Discontinued operations, net of tax ............................. (3) -- (3) --
Extraordinary item, net of tax .................................. 30 -- 30 --
------------ ------------ ------------ ------------
Net income ...................................................... $ 54 $ 194 $ 121 $ 282
============ ============ ============ ============
Weighted average shares outstanding ................................ 309,098,000 311,440,000 308,786,000 311,145,000
============ ============ ============ ============
Basic earnings per share:
Income from continuing operations before extraordinary item ..... $ 0.09 $ 0.62 $ 0.30 $ 0.91
Discontinued operations, net of tax ............................. (0.01) -- (0.01) --
Extraordinary item, net of tax .................................. 0.10 -- 0.10 --
------------ ------------ ------------ ------------
Net income ...................................................... $ 0.18 $ 0.62 $ 0.39 $ 0.91
============ ============ ============ ============
Diluted earnings per share calculation:
Net income ...................................................... $ 54 $ 194 $ 121 $ 282
Plus: Income impact of assumed conversions:
Interest on 3.75% convertible senior notes ................... 4 -- 7 --
------------ ------------ ------------ ------------
Total earnings effect assuming dilution ......................... $ 58 $ 194 $ 128 $ 282
============ ============ ============ ============
Weighted average shares outstanding ................................ 309,098,000 311,440,000 308,786,000 311,145,000
Plus: Incremental shares from assumed conversions:
Stock options (1) ............................................ 1,302,000 1,098,000 1,254,000 1,150,000
Restricted stock ............................................. 1,365,000 1,160,000 1,365,000 1,160,000
3.75% convertible senior notes ............................... 49,655,000 3,118,000 49,655,000 4,289,000
6.25% convertible trust preferred securities ................. 16,000 -- 16,000 --
------------ ------------ ------------ ------------
Weighted average shares assuming dilution ....................... 361,436,000 316,816,000 361,076,000 317,744,000
============ ============ ============ ============
Diluted earnings per share:
Income from continuing operations before extraordinary item ..... $ 0.09 $ 0.61 $ 0.28 $ 0.89
Discontinued operations, net of tax ............................. (0.01) -- (0.01) --
Extraordinary item, net of tax .................................. 0.08 -- 0.08 --
------------ ------------ ------------ ------------
Net income ...................................................... $ 0.16 $ 0.61 $ 0.35 $ 0.89
============ ============ ============ ============
----------
(1) Options to purchase 9,356,759 shares were outstanding for both the three
months and six months ended June 30, 2005, and options to purchase
7,137,644 shares were outstanding for both the three months and six months
ended June 30, 2006, but were not included in the computation of diluted
earnings per share because the options' exercise price was greater than the
average market price of the common shares for the respective periods.
23
In accordance with EITF 04-8, because all of the 2.875% contingently
convertible senior notes and approximately $572 million of the 3.75%
contingently convertible senior notes (subsequent to the August 2005 exchange
discussed in Note 10) provide for settlement of the principal portion in cash
rather than stock, the Company excludes the portion of the conversion value of
these notes attributable to their principal amount from its computation of
diluted earnings per share from continuing operations. The Company includes the
conversion spread in the calculation of diluted earnings per share when the
average market price of the Company's common stock in the respective reporting
period exceeds the conversion price. The conversion prices for the 2.875% and
the 3.75% contingently convertible senior notes are $12.66 and $11.44,
respectively.
(13) REPORTABLE BUSINESS SEGMENTS
The Company's determination of reportable business segments considers the
strategic operating units under which the Company manages sales, allocates
resources and assesses performance of various products and services to wholesale
or retail customers in differing regulatory environments. The accounting
policies of the business segments are the same as those described in the summary
of significant accounting policies except that some executive benefit costs have
not been allocated to business segments. The Company uses operating income as
the measure of profit or loss for its business segments.
The Company's reportable business segments include the following: Electric
Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas
Sales and Services, Pipelines and Field Services and Other Operations. The
electric transmission and distribution function (CenterPoint Houston) is
reported in the Electric Transmission & Distribution business segment. Natural
Gas Distribution consists of intrastate natural gas sales to, and natural gas
transportation and distribution for, residential, commercial, industrial and
institutional customers. The Company reorganized the oversight of its Natural
Gas Distribution business segment and, as a result, beginning in the fourth
quarter of 2005, the Company established a new reportable business segment,
Competitive Natural Gas Sales and Services. Competitive Natural Gas Sales and
Services represents the Company's non-rate regulated gas sales and services
operations, which consist of three operational functions: wholesale, retail and
intrastate pipelines. Pipelines and Field Services includes the interstate
natural gas pipeline operations and the natural gas gathering and pipeline
services businesses. Other Operations consists primarily of other corporate
operations which support all of the Company's business operations. All prior
period segment information has been reclassified to conform to the 2006
presentation.
Long-lived assets include net property, plant and equipment, net goodwill
and other intangibles and equity investments in unconsolidated subsidiaries.
Intersegment sales are eliminated in consolidation.
Financial data for business segments and products and services are as
follows (in millions):
FOR THE THREE MONTHS ENDED JUNE 30, 2005
-------------------------------------------------------------------
REVENUES FROM EXTERNAL NET INTERSEGMENT
CUSTOMERS REVENUES OPERATING INCOME (LOSS)
---------------------- ---------------- -----------------------
Electric Transmission & Distribution ......... $ 414(1) $ -- $122
Natural Gas Distribution ..................... 538 3 9
Competitive Natural Gas Sales and Services ... 801 44 10
Pipelines and Field Services ................. 87 38 52
Other Operations ............................. 2 2 (7)
Eliminations ................................. -- (87) --
------ ---- ----
Consolidated ................................. $1,842 $ -- $186
====== ==== ====
24
FOR THE THREE MONTHS ENDED JUNE 30, 2006
-------------------------------------------------------------------
REVENUES FROM EXTERNAL NET INTERSEGMENT
CUSTOMERS REVENUES OPERATING INCOME (LOSS)
---------------------- ---------------- -----------------------
Electric Transmission & Distribution ......... $ 456(1) $ -- $151
Natural Gas Distribution ..................... 546 3 (2)
Competitive Natural Gas Sales and Services ... 742 8 7
Pipelines and Field Services ................. 96 39 61
Other Operations ............................. 3 2 3
Eliminations ................................. -- (52) --
------ ---- ----
Consolidated ................................. $1,843 $ -- $220
====== ==== ====
FOR THE SIX MONTHS ENDED JUNE 30, 2005
-----------------------------------------------------------------------------
REVENUES FROM EXTERNAL NET INTERSEGMENT OPERATING TOTAL ASSETS AS OF
CUSTOMERS REVENUES INCOME (LOSS) DECEMBER 31, 2005
---------------------- ---------------- ------------- ------------------
Electric Transmission & Distribution ......... $ 759(1) $ -- $202 $ 8,227
Natural Gas Distribution ..................... 1,867 3 132 4,612
Competitive Natural Gas Sales and Services ... 1,633 137 26 1,849
Pipelines and Field Services ................. 171 75 116 2,968
Other Operations ............................. 7 4 (14) 2,202(2)
Eliminations ................................. -- (219) -- (2,742)
------ ----- ---- -------
Consolidated ................................. $4,437 $ -- $462 $17,116
====== ===== ==== =======
FOR THE SIX MONTHS ENDED JUNE 30, 2006
------------------------------------------------------------------------------
REVENUES FROM EXTERNAL NET INTERSEGMENT OPERATING TOTAL ASSETS AS OF
CUSTOMERS REVENUES INCOME (LOSS) JUNE 30, 2006
---------------------- ---------------- ------------- ------------------
Electric Transmission & Distribution ......... $ 841(1) $ -- $261 $ 8,381
Natural Gas Distribution ..................... 2,023 6 101 3,959
Competitive Natural Gas Sales and Services ... 1,868 45 32 1,259
Pipelines and Field Services ................. 183 77 134 3,057
Other Operations ............................. 5 4 (2) 2,146(2)
Eliminations ................................. -- (132) -- (2,093)
------ ----- ---- -------
Consolidated ................................. $4,920 $ -- $526 $16,709
====== ===== ==== =======
----------
(1) Sales to subsidiaries of RRI in the three months ended June 30, 2005 and
2006 represented approximately $183 million and $182 million, respectively.
Sales to subsidiaries of RRI in the six months ended June 30, 2005 and 2006
represented approximately $366 million and $344 million, respectively.
(2) Included in total assets of Other Operations as of December 31, 2005 and
June 30, 2006 is a pension asset of $654 million and $631 million,
respectively.
(14) SUBSEQUENT EVENT
On July 27, 2006, the Company's board of directors declared a regular
quarterly cash dividend of $0.15 per share of common stock payable on September
8, 2006, to the shareholders of record as of the close of business on August 16,
2006.
25
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
The following discussion and analysis should be read in combination with
our Interim Condensed Financial Statements contained in this Form 10-Q.
EXECUTIVE SUMMARY
RECENT EVENTS
DEBT FINANCING TRANSACTIONS
In May 2006, CERC Corp. issued $325 million aggregate principal amount of
senior notes due in May 2016 with an interest rate of 6.15%. The proceeds from
the sale of the senior notes will be used for general corporate purposes,
including repayment or refinancing of debt (including $145 million of CERC's
8.90% debentures due December 15, 2006), capital expenditures and working
capital.
AGREEMENT REGARDING TAX SETTLEMENT
During the second quarter of 2006, we reached agreement with the Internal
Revenue Service (IRS) on terms of a settlement regarding the tax treatment of
our Zero Premium Exchangeable Subordinated Notes (ZENS) and our former Automatic
Common Exchange Securities (ACES). On July 17, 2006, we signed a Closing
Agreement prepared by the IRS and us for the tax years 1999 through 2029 with
respect to the ZENS issue. The agreement reached with the IRS and the Closing
Agreement are subject to approval by the Joint Committee on Taxation of the U.S.
Congress. Under the terms of the agreement reached with the IRS, we will pay
approximately $64 million in previously accrued taxes associated with the ACES
and the ZENS and will reduce our future interest deductions associated with the
ZENS. As a result of the agreement reached with the IRS, we reduced our
previously accrued tax and related interest reserves by approximately $119
million in the second quarter of 2006, and will no longer accrue a quarterly
reserve.
AGREEMENT REGARDING SETTLEMENT OF THE ELECTRIC TRANSMISSION & DISTRIBUTION RATE
CASE AND THE 2001 UNBUNDLED COST OF SERVICE (UCOS) REMAND
On July 31, 2006, CenterPoint Houston entered into a settlement agreement
with the parties to the proceeding that would resolve the issues raised in its
pending rate case. Under the terms of the agreement, CenterPoint Houston's base
rate revenues will be reduced by approximately $58 million per year. Also,
CenterPoint Houston will commit to increase its energy efficiency expenditures
by an additional $10 million per year over the $13 million included in existing
rates. The expenditures will be made to benefit both residential and commercial
customers. CenterPoint Houston also will fund $10 million per year for programs
providing financial assistance to qualified low-income customers in its service
territory. The agreement provides for a rate freeze until June 30, 2010 under
which CenterPoint Houston will not seek to increase its base rates and the other
parties will not petition to decrease those rates.
The agreement also resolves all issues that could be raised in the Public
Utility Commission of Texas' (Texas Utility Commission) proceeding to review its
decision in CenterPoint Houston's 2001 UCOS case. Under the terms of the
agreement, CenterPoint Houston will add riders to its tariff rates under which
it will provide rate credits to retail and wholesale customers for a total of
approximately $8 million per year until a total of $32 million has been credited
to customers under those tariff riders. CenterPoint Houston reduced revenues and
established a corresponding regulatory liability for $32 million in the second
quarter of 2006 to reflect this obligation.
COMPETITION TRANSITION CHARGE (CTC) INTEREST RATE REDUCTION
In January 2006, the Texas Utility Commission staff (Staff) proposed that
the Texas Utility Commission adopt new rules governing the carrying charges on
unrecovered true-up balances. In June 2006, the Texas Utility Commission adopted
the revised rule as recommended by the Staff. The rule, which applies to
CenterPoint Houston, reduces carrying costs on the unrecovered CTC balance
prospectively from 11.075 percent to a weighted average cost of capital of 8.06
percent. The annualized impact on operating income is expected to be
approximately $18 million per year for the first year with lesser impacts in
subsequent years. In accordance with the agreement discussed above, CenterPoint
Houston implemented the rule change effective August 1, 2006.
26
CONSOLIDATED RESULTS OF OPERATIONS
All dollar amounts in the tables that follow are in millions, except for
per share amounts.
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
--------------- ---------------
2005 2006 2005 2006
------ ------ ------ ------
Revenues .................................. $1,842 $1,843 $4,437 $4,920
Expenses .................................. 1,656 1,623 3,975 4,394
------ ------ ------ ------
Operating Income .......................... 186 220 462 526
Interest and Other Finance Charges ........ (189) (151) (371) (299)
Other Income, net ......................... 48 9 84 11
------ ------ ------ ------
Income From Continuing Operations Before
Income Taxes and Extraordinary Item .... 45 78 175 238
Income Tax (Expense) Benefit .............. (18) 116 (81) 44
------ ------ ------ ------
Income From Continuing Operations Before
Extraordinary Item ..................... 27 194 94 282
Discontinued Operations, net of tax ....... (3) -- (3) --
------ ------ ------ ------
Income Before Extraordinary Item .......... 24 194 91 282
Extraordinary Item, net of tax ............ 30 -- 30 --
------ ------ ------ ------
Net Income ................................ $ 54 $ 194 $ 121 $ 282
====== ====== ====== ======
BASIC EARNINGS PER SHARE:
Income From Continuing Operations ...... $ 0.09 $ 0.62 $ 0.30 $ 0.91
Discontinued Operations, net of tax .... (0.01) -- (0.01) --
Extraordinary Item, net of tax ......... 0.10 -- 0.10 --
------ ------ ------ ------
Net Income ............................. $ 0.18 $ 0.62 $ 0.39 $ 0.91
====== ====== ====== ======
DILUTED EARNINGS PER SHARE:
Income From Continuing Operations ...... $ 0.09 $ 0.61 $ 0.28 $ 0.89
Discontinued Operations, net of tax .... (0.01) -- (0.01) --
Extraordinary Item, net of tax ......... 0.08 -- 0.08 --
------ ------ ------ ------
Net Income ............................. $ 0.16 $ 0.61 $ 0.35 $ 0.89
====== ====== ====== ======
THREE MONTHS ENDED JUNE 30, 2006 COMPARED TO THREE MONTHS ENDED JUNE 30, 2005
Income from Continuing Operations. We reported income from continuing
operations of $194 million ($0.61 per diluted share) for the three months ended
June 30, 2006 as compared to $27 million ($0.09 per diluted share) for the same
period in 2005. As discussed below, the increase in income from continuing
operations of $167 million was primarily due to:
- a $119 million reduction to previously accrued tax and related
interest reserves related to our ZENS and ACES as a result of an
agreement reached with the IRS discussed above;
- a $62 million decrease in interest expense, excluding transition
bond-related interest expense, due to lower borrowing costs and
borrowing levels;
- a $9 million increase in operating income from our Pipelines and Field
Services business segment; and
- a $6 million increase in operating income from the regulated utility
operations of our Electric Transmission & Distribution business
segment.
These increases in income from continuing operations were partially offset
by:
- a $35 million decrease in other income related to a return on the
true-up balance of our Electric Transmission & Distribution business
segment recorded in the second quarter of 2005;
- an $11 million decrease in operating income from our Natural Gas
Distribution business segment; and
27
- a $3 million decrease in operating income from our Competitive Natural
Gas Sales and Services business segment.
SIX MONTHS ENDED JUNE 30, 2006 COMPARED TO SIX MONTHS ENDED JUNE 30, 2005
Income from Continuing Operations. We reported income from continuing
operations of $282 million ($0.89 per diluted share) for the six months ended
June 30, 2006 as compared to $94 million ($0.28 per diluted share) for the same
period in 2005. As discussed below, the increase in income from continuing
operations of $188 million was primarily due to:
- a $120 million decrease in interest expense, excluding transition
bond-related interest expense, due to lower borrowing costs and
borrowing levels;
- a $119 million reduction to previously accrued tax and related
interest reserves related to our ZENS and ACES as discussed above;
- a $18 million increase in operating income from our Pipelines and
Field Services business segment;
- a $13 million increase in operating income from the regulated utility
operations of our Electric Transmission & Distribution business
segment; and
- a $6 million increase in operating income from our Competitive Natural
Gas Sales and Services business segment.
These increases in income from continuing operations were partially offset
by:
- a $69 million decrease in other income related to a return on the
true-up balance of our Electric Transmission & Distribution business
segment recorded in the first six months of 2005; and
- a $31 million decrease in operating income from our Natural Gas
Distribution business segment.
INCOME TAX EXPENSE
During the three months and six months ended June 30, 2005, our effective
tax rate was 39.3% and 46.2%, respectively. The most significant item affecting
our effective tax rates was an addition to the tax reserve relating to the ZENS
and ACES of approximately $12 million and $22 million, respectively, during the
three months and six months ended June 30, 2005. As discussed above, we reached
an agreement with the IRS in July 2006 and have reduced our previously accrued
tax and related interest reserves related to the ZENS and ACES by approximately
$119 million as of June 30, 2006. Settlement of other tax issues during the
three months and six months ended June 30, 2006 reduced income tax expense by
approximately $21 million. The effective tax rate for the three months and six
months ended June 30, 2006 was a net benefit as a result of these matters.
EXTRAORDINARY ITEM AND LOSS ON DISPOSAL OF TEXAS GENCO
Net income for both the three months and six months ended June 30, 2005
included an after-tax extraordinary gain of $30 million ($0.08 per diluted
share) reflecting an adjustment to the extraordinary loss recorded in the last
half of 2004 to write-down generation-related regulatory assets as a result of
the final orders issued by the Texas Utility Commission.
Net income for both the three months and six months ended June 30, 2005
included a net after-tax loss from discontinued operations of Texas Genco of $3
million ($0.01 per diluted share).
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
The following table presents operating income (loss) for each of our
business segments for the three and six months ended June 30, 2005 and 2006.
Some amounts from the previous year have been reclassified to conform to the
2006 presentation of the financial statements. These reclassifications do not
affect consolidated net income.
28
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
-------------- --------------
2005 2006 2005 2006
---- ---- ---- ----
(IN MILLIONS)
Electric Transmission & Distribution ........ $122 $151 $202 $261
Natural Gas Distribution .................... 9 (2) 132 101
Competitive Natural Gas Sales and Services .. 10 7 26 32
Pipelines and Field Services ................ 52 61 116 134
Other Operations ............................ (7) 3 (14) (2)
---- ---- ---- ----
Total Consolidated Operating Income ...... $186 $220 $462 $526
==== ==== ==== ====
ELECTRIC TRANSMISSION & DISTRIBUTION
For information regarding factors that may affect the future results of
operations of our Electric Transmission & Distribution business segment, please
read "Risk Factors -- Risk Factors Affecting Our Electric Transmission &
Distribution Business," " -- Risk Factors Associated with Our Consolidated
Financial Condition" and "-- Risks Common to Our Business and Other Risks" in
Item 1A of Part I of our Annual Report on Form 10-K for the year ended December
31, 2005 (2005 Form 10-K).
The following tables provide summary data of our Electric Transmission &
Distribution business segment for the three and six months ended June 30, 2005
and 2006 (in millions, except throughput and customer data):
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2005 2006 2005 2006
---------- ---------- --------- ----------
Revenues:
Electric transmission and distribution utility .................. $ 388 $ 386 $ 711 $ 717
Transition bond companies ....................................... 26 70 48 124
---------- ---------- ---------- ----------
Total revenues ............................................... 414 456 759 841
---------- ---------- ---------- ----------
Expenses:
Operation and maintenance ....................................... 153 147 291 281
Depreciation and amortization ................................... 64 61 128 124
Taxes other than income taxes ................................... 58 59 108 115
Transition bond companies ....................................... 17 38 30 60
---------- ---------- ---------- ----------
Total expenses ............................................... 292 305 557 580
---------- ---------- ---------- ----------
Operating Income ................................................... $ 122 $ 151 $ 202 $ 261
========== ========== ========== ==========
Operating Income - Electric transmission and distribution utility .. $ 113 $ 119 $ 184 $ 197
Operating Income - Transition bond companies (1) ................... 9 32 18 64
---------- ---------- ---------- ----------
Total segment operating income ............................ $ 122 $ 151 $ 202 $ 261
========== ========== ========== ==========
Throughput (in gigawatt-hours (GWh)):
Residential ..................................................... 6,594 6,808 10,736 10,794
Total ........................................................... 18,956 20,422 34,783 36,409
Average number of metered customers:
Residential ..................................................... 1,675,573 1,730,130 1,668,447 1,723,983
Total ........................................................... 1,904,090 1,965,180 1,895,556 1,958,005
----------
(1) Represents the amount necessary to pay interest on the transition bonds.
THREE MONTHS ENDED JUNE 30, 2006 COMPARED TO THREE MONTHS ENDED JUNE 30, 2005
Our Electric Transmission & Distribution business segment reported
operating income of $151 million for the three months ended June 30, 2006,
consisting of $119 million for the regulated electric transmission and
distribution utility and $32 million related to the transition bonds. For the
three months ended June 30, 2005, operating income totaled $122 million,
consisting of $113 million for the regulated electric transmission and
distribution utility and $9 million related to the transition bonds. Revenues
for the regulated electric transmission and distribution utility continue to
benefit from solid customer growth, with nearly 60,000 metered customers added
since June 2005 ($10
29
million), recovery of our 2004 true-up balance through the CTC, which was
implemented in September 2005 ($12 million) as well as favorable weather and
increased usage ($6 million). This increase in revenues was more than offset by
the impact related to the resolution of the 2001 UCOS order, which reduced
revenues by $32 million. Operation and maintenance expense decreased primarily
due to lower employee benefit expenses ($4 million).
SIX MONTHS ENDED JUNE 30, 2006 COMPARED TO SIX MONTHS ENDED JUNE 30, 2005
Our Electric Transmission & Distribution business segment reported
operating income of $261 million for the six months ended June 30, 2006,
consisting of $197 million for the regulated electric transmission and
distribution utility and $64 million related to the transition bonds. For the
six months ended June 30, 2005, operating income totaled $202 million,
consisting of $184 million for the regulated electric transmission and
distribution utility and $18 million related to the transition bonds. Revenues
for the regulated electric transmission and distribution utility increased due
to continued customer growth, with nearly 60,000 metered customers added since
June 2005 ($18 million), recovery of our 2004 true-up balance through the CTC
($26 million) and favorable weather ($2 million), partially offset by decreased
usage ($8 million) and the impact related to the resolution of the 2001 UCOS
order ($32 million). Operation and maintenance expense decreased primarily due
to a gain on the sale of land in 2006 ($14 million) and lower employee benefit
expenses ($5 million), which was partially offset by higher transmission costs
($5 million) and severance costs associated with staff reductions ($4 million).
Additionally, taxes other than income taxes increased primarily due to higher
franchise fees ($7 million).
NATURAL GAS DISTRIBUTION
For information regarding factors that may affect the future results of
operations of our Natural Gas Distribution business segment, please read "Risk
Factors -- Risk Factors Affecting Our Natural Gas Distribution, Competitive
Natural Gas Sales and Services and Pipelines and Field Services Businesses," "
-- Risk Factors Associated with Our Consolidated Financial Condition" and "--
Risks Common to Our Business and Other Risks" in Item 1A of Part I of our 2005
Form 10-K.
The following table provides summary data of our Natural Gas Distribution
business segment for the three and six months ended June 30, 2005 and 2006 (in
millions, except throughput and customer data):
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2005 2006 2005 2006
---------- ---------- ---------- ----------
Revenues ................................... $ 541 $ 549 $ 1,870 $ 2,029
---------- ---------- ---------- ----------
Expenses:
Natural gas ............................. 341 343 1,338 1,489
Operation and maintenance ............... 126 142 261 292
Depreciation and amortization ........... 39 37 76 75
Taxes other than income taxes ........... 26 29 63 72
---------- ---------- ---------- ----------
Total expenses ....................... 532 551 1,738 1,928
---------- ---------- ---------- ----------
Operating Income (Loss) .................... $ 9 $ (2) $ 132 $ 101
========== ========== ========== ==========
Throughput (in billion cubic feet (Bcf)):
Residential ............................. 21 17 98 84
Commercial and industrial ............... 43 44 120 116
---------- ---------- ---------- ----------
Total Throughput ..................... 64 61 218 200
========== ========== ========== ==========
Average number of customers:
Residential ............................. 2,833,773 2,860,802 2,842,645 2,872,978
Commercial and industrial ............... 246,032 253,725 247,429 253,505
---------- ---------- ---------- ----------
Total ................................ 3,079,805 3,114,527 3,090,074 3,126,483
========== ========== ========== ==========
THREE MONTHS ENDED JUNE 30, 2006 COMPARED TO THREE MONTHS ENDED JUNE 30, 2005
Our Natural Gas Distribution business segment reported an operating loss of
$2 million for the three months ended June 30, 2006 as compared to operating
income of $9 million for the three months ended June 30, 2005.
30
Increases in operating margins (revenues less natural gas costs) from rate
increases and rate design changes, along with the addition of nearly 32,000
customers since June 2005 ($6 million) and increased gross receipts taxes
resulting from higher revenues ($3 million), were partially offset by decreased
customer usage and unfavorable weather ($5 million). Operation and maintenance
expenses increased primarily due to costs associated with staff reductions ($5
million), increased bad debt expense due to high natural gas prices ($3 million)
and a write-off of certain rate case expenses ($3 million). Additionally, taxes
other than income taxes increased $3 million primarily due to higher gross
receipts taxes, which offset the corresponding increase in revenues discussed
above.
SIX MONTHS ENDED JUNE 30, 2006 COMPARED TO SIX MONTHS ENDED JUNE 30, 2005
Our Natural Gas Distribution business segment reported operating income of
$101 million for the six months ended June 30, 2006 as compared to $132 million
for the six months ended June 30, 2005. Increases in operating margins from rate
increases and rate design changes, along with the addition of nearly 32,000
customers since June 2005 ($20 million) and increased gross receipts taxes
resulting from higher revenues ($9 million), were partially offset by decreased
customer usage and unfavorable weather ($21 million). Operation and maintenance
expenses increased primarily due to costs associated with staff reductions ($11
million), increased bad debt expense due to high natural gas prices ($6
million), increased contracts and services expenses and corporate services ($8
million) and a write-off of certain rate case expenses ($3 million).
Additionally, taxes other than income taxes increased $9 million primarily due
to higher gross receipts taxes, which offset the corresponding increase in
revenues discussed above.
COMPETITIVE NATURAL GAS SALES AND SERVICES
For information regarding factors that may affect the future results of
operations of our Competitive Natural Gas Sales and Services business segment,
please read "Risk Factors -- Risk Factors Affecting Our Natural Gas
Distribution, Competitive Natural Gas Sales and Services and Pipelines and Field
Services Business," " -- Risk Factors Associated with Our Consolidated Financial
Condition" and "-- Risks Common to Our Business and Other Risks" in Item 1A of
Part I of our 2005 Form 10-K.
The following table provides summary data of our Competitive Natural Gas
Sales and Services business segment for the three and six months ended June 30,
2005 and 2006 (in millions, except throughput and customer data):
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ----------------
2005 2006 2005 2006
------ ------ ------ ------
Revenues .......................... $ 845 $ 750 $1,770 $1,913
------ ------ ------ ------
Expenses:
Natural gas .................... 828 735 1,730 1,864
Operation and maintenance ...... 7 7 12 15
Depreciation and amortization .. -- 1 1 1
Taxes other than income taxes .. -- -- 1 1
------ ------ ------ ------
Total expenses .............. 835 743 1,744 1,881
------ ------ ------ ------
Operating Income .................. $ 10 $ 7 $ 26 $ 32
====== ====== ====== ======
Throughput (in Bcf):
Wholesale - third parties ...... 72 72 154 161
Wholesale - affiliates ......... 21 8 35 19
Retail ......................... 34 31 81 79
Pipeline ....................... 12 10 31 20
------ ------ ------ ------
Total Throughput ............ 139 121 301 279
====== ====== ====== ======
Average number of customers:
Wholesale ...................... 135 132 130 138
Retail ......................... 6,237 6,468 6,207 6,501
Pipeline ....................... 145 136 151 138
------ ------ ------ ------
Total ....................... 6,517 6,736 6,488 6,777
====== ====== ====== ======
31
THREE MONTHS ENDED JUNE 30, 2006 COMPARED TO THREE MONTHS ENDED JUNE 30, 2005
Our Competitive Natural Gas Sales and Services business segment reported
operating income of $7 million for the three months ended June 30, 2006 as
compared to $10 million for the three months ended June 30, 2005. Increased
operating income from higher sales to utilities and favorable basis
differentials across the pipeline capacity that we control ($12 million) was
more than offset by a charge of $17 million to reflect the write-down of natural
gas inventory to the lower of average cost or market. Our Competitive Natural
Gas Sales and Services business segment purchases and stores natural gas to meet
future sales requirements and enters into derivative contracts to hedge the
economic value of the future sales. Therefore, operating income in future
periods when these sales occur is expected to be higher as a result of the
inventory write-down taken in this quarter.
SIX MONTHS ENDED JUNE 30, 2006 COMPARED TO SIX MONTHS ENDED JUNE 30, 2005
Our Competitive Natural Gas Sales and Services business segment reported
operating income of $32 million for the six months ended June 30, 2006 as
compared to $26 million for the six months ended June 30, 2005. Increased
operating income from higher sales to utilities and favorable basis
differentials across the pipeline capacity that we control ($35 million) was
partially offset by a charge of $30 million to reflect the write-downs of
natural gas inventory to the lower of average cost or market. Therefore,
operating income in future periods when these sales occur is expected to be
higher as a result of the inventory write-downs taken in the first two quarters
of this year.
PIPELINES AND FIELD SERVICES
For information regarding factors that may affect the future results of
operations of our Pipelines and Field Services business segment, please read
"Risk Factors -- Risk Factors Affecting Our Natural Gas Distribution,
Competitive Natural Gas Sales and Services and Pipelines and Field Services
Businesses," " -- Risk Factors Associated with Our Consolidated Financial
Condition" and "-- Risks Common to Our Business and Other Risks" in Item 1A of
Part I of our 2005 Form 10-K.
The following table provides summary data of our Pipelines and Field
Services business segment for the three and six months ended June 30, 2005 and
2006 (in millions, except throughput data):
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
-------------- --------------
2005 2006 2005 2006
---- ---- ---- ----
Revenues .................................... $125 $135 $246 $260
---- ---- ---- ----
Expenses:
Natural gas .............................. 18 7 25 3
Operation and maintenance ................ 40 50 74 89
Depreciation and amortization ............ 11 12 22 24
Taxes other than income taxes ............ 4 5 9 10
---- ---- ---- ----
Total expenses ........................ 73 74 130 126
---- ---- ---- ----
Operating Income ............................ $ 52 $ 61 $116 $134
==== ==== ==== ====
Operating Income - Pipeline business ........ $ 35 $ 40 $ 83 $ 89
Operating Income - Field Services business .. 17 21 33 45
---- ---- ---- ----
Total segment operating income ........ $ 52 $ 61 $116 $134
==== ==== ==== ====
Throughput (in Bcf):
Natural Gas Sales ........................ 3 2 4 2
Transportation ........................... 230 240 501 514
Gathering ................................ 87 94 170 182
Elimination (1) .......................... (2) (1) (3) (1)
---- ---- ---- ----
Total Throughput ................... 318 335 672 697
==== ==== ==== ====
----------
(1) Elimination of volumes both transported and sold.
32
THREE MONTHS ENDED JUNE 30, 2006 COMPARED TO THREE MONTHS ENDED JUNE 30, 2005
Our Pipelines and Field Services business segment reported operating income
of $61 million for the three months ended June 30, 2006 as compared to $52
million for the three months ended June 30, 2005. This segment's businesses
continue to benefit from favorable dynamics in the markets for natural gas
gathering and transportation services in the Gulf Coast and Mid-Continent
regions where they operate. Within this segment, the pipeline business achieved
higher operating income of $40 million for the three months ended June 30, 2006
as compared to $35 million for the same period in 2005 resulting from increased
demand for transportation due to favorable basis differentials across the system
($5 million), higher demand for ancillary services ($3 million) and increased
project-related revenues ($5 million), offset by a corresponding increase in
project-related expenses ($5 million) and higher operation and maintenance
expenses ($3 million). The field services business achieved higher operating
income of $21 million for the three months ended June 30, 2006 as compared to
$17 million for the same period in 2005 driven by increased throughput ($3
million) and higher commodity prices ($2 million).
Additionally, this business segment recorded equity income of $1 million
and $2 million for the three months ended June 30, 2005 and 2006, respectively,
from its 50 percent interest in a jointly-owned gas processing plant. These
amounts are included in Other - net under the Other Income (Expense) caption in
our Condensed Statements of Consolidated Income.
SIX MONTHS ENDED JUNE 30, 2006 COMPARED TO SIX MONTHS ENDED JUNE 30, 2005
Our Pipelines and Field Services business segment reported operating income
of $134 million for the six months ended June 30, 2006 as compared to $116
million for the six months ended June 30, 2005. The pipeline business achieved
operating income of $89 million for the six months ended June 30, 2006 as
compared to $83 million for the same period in 2005 resulting from increased
demand for transportation due to favorable basis differentials across the system
($11 million), higher demand for ancillary services ($4 million) and increased
project-related revenues ($6 million), partially offset by a corresponding
increase in project-related expenses ($5 million) and increased operation and
maintenance expenses ($6 million). The field services business achieved
operating income of $45 million for the six months ended June 30, 2006 as
compared to $33 million for the same period in 2005 driven by increased
throughput ($7 million), higher commodity prices ($7 million) and higher demand
for ancillary services ($2 million), partially offset by increased operation and
maintenance expenses ($4 million).
In addition, this business segment recorded equity income of $3 million and
$5 million for the six months ended June 30, 2005 and 2006, respectively, from
its 50 percent interest in a jointly-owned gas processing plant as discussed
above.
OTHER OPERATIONS
The following table shows the operating loss of our Other Operations
business segment for the three and six months ended June 30, 2005 and 2006 (in
millions):
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
-------------- --------------
2005 2006 2005 2006
---- ---- ---- ----
Revenues ................. $ 4 $5 $ 11 $ 9
Expenses ................. 11 2 25 11
--- -- ---- ---
Operating Income (Loss) .. $(7) $3 $(14) $(2)
=== == ==== ===
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
For information on other developments, factors and trends that may have an
impact on our future earnings, please read "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Certain Factors Affecting
Future Earnings" in Item 7 of Part II and "Risk Factors" in Item 1A of Part I of
our 2005 Form 10-K.
33
LIQUIDITY AND CAPITAL RESOURCES
HISTORICAL CASH FLOWS
The following table summarizes the net cash provided by (used in)
operating, investing and financing activities for the six months ended June 30,
2005 and 2006 (in millions):
SIX MONTHS
ENDED JUNE 30,
--------------
2005 2006
----- -----
Cash provided by (used in):
Operating activities ...... $ 16 $ 517
Investing activities ...... 412 (396)
Financing activities ...... (185) 202
CASH PROVIDED BY OPERATING ACTIVITIES
Net cash provided by operating activities in the first six months of 2006
increased $533 million compared to the same period in 2005 primarily due to
decreased tax payments of $345 million, the majority of which related to the tax
payment in the first quarter of 2005 associated with the sale of our former
electric generation business (Texas Genco), decreases in net regulatory
assets/liabilities ($187 million), primarily due to the termination of excess
mitigation credits effective April 29, 2005, decreased gas storage inventory
($53 million) and fuel under-recovery ($123 million) primarily related to
declining gas prices during the first six months of 2006 and decreased cash used
in the operations of Texas Genco ($38 million). These increases in cash provided
by operating activities were partially offset by decreased net accounts
receivable/payable ($208 million) primarily due to decreased gas prices in the
first two quarters of 2006 as compared to the same period in 2005 and decreases
in the amount of advances for the purchase of receivables under CERC Corp.'s
receivables facility. Additionally, customer margin deposit requirements
decreased ($88 million) primarily due to the decline in natural gas prices from
December 2005 to June 2006 and our margin deposits increased ($32 million).
CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES
Net cash used in investing activities increased $808 million in the first
six months of 2006 as compared to the same period in 2005 primarily due to
increased capital expenditures of $49 million primarily related to our Electric
Transmission & Distribution and Pipelines and Field Services business segments
and the absence of $700 million in proceeds received in the second quarter of
2005 from the sale of our remaining interest in Texas Genco and cash of Texas
Genco of $23 million.
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
Net cash provided by financing activities in the first six months of 2006
increased $387 million compared to the same period in 2005 primarily due to net
proceeds from the issuance of long-term debt ($324 million), decreased payments
under our revolving credit facility ($116 million) and decreased payments of
long-term debt ($33 million), partially offset by the absence of borrowings
under Texas Genco's revolving credit facility ($75 million) due to the sale of
Texas Genco and increased dividend payments of $10 million.
FUTURE SOURCES AND USES OF CASH
Our liquidity and capital requirements are affected primarily by our
results of operations, capital expenditures, debt service requirements, tax
payments, working capital needs, various regulatory actions and appeals relating
to such regulatory actions. Our principal cash requirements for the remaining
six months of 2006 include the following:
- approximately $700 million of capital expenditures;
- dividend payments on CenterPoint Energy common stock and debt service
payments; and
- long-term debt payments of $199 million, including $54 million of
transition bonds.
34
We expect that borrowings under our credit facilities, liquidation of
temporary investments and anticipated cash flows from operations will be
sufficient to meet our cash needs for the next twelve months. Cash needs may
also be met by issuing securities in the capital markets.
Contractual Obligations. We negotiated new natural gas transportation
contracts during the second quarter of 2006 which was the primary reason for an
$809 million increase in the amount of other commodity commitments from the
contractual obligations reported in our 2005 Form 10-K. Minimum payment
obligations for natural gas supply and related transportation contracts are
approximately $367 million for the remaining six months in 2006, $627 million in
2007, $174 million in 2008, $118 million in 2009, $118 million in 2010 and $721
million in 2011 and thereafter.
Off-Balance Sheet Arrangements. Other than operating leases and the
guarantees described below, we have no off-balance sheet arrangements. However,
we do participate in a receivables factoring arrangement. CERC Corp. has a
bankruptcy remote subsidiary, which we consolidate, which was formed for the
sole purpose of buying receivables created by CERC and selling those receivables
to an unrelated third-party. This transaction is accounted for as a sale of
receivables under the provisions of Statement of Financial Accounting Standards
(SFAS) No. 140, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities," and, as a result, the related receivables are
excluded from the Condensed Consolidated Balance Sheet. In January 2006, our
$250 million facility was extended to January 2007. As of June 30, 2006, no
amounts were funded under our receivables facility. The facility was temporarily
increased to $375 million for the period from January 2006 to June 2006.
Prior to the CenterPoint Energy's distribution of its ownership in RRI to
its shareholders, CERC had guaranteed certain contractual obligations of what
became RRI's trading subsidiary. Under the terms of the separation agreement
between the companies, RRI agreed to extinguish all such guarantee obligations
prior to separation, but when separation occurred in September 2002, RRI had
been unable to extinguish all obligations. To secure the CenterPoint Energy and
CERC against obligations under the remaining guarantees, RRI agreed to provide
cash or letters of credit for the benefit of CERC and CenterPoint Energy, and
agreed to use commercially reasonable efforts to extinguish the remaining
guarantees. CenterPoint Energy's current exposure under the remaining guarantees
relates to CERC's guarantee of the payment by RRI of demand charges related to
transportation contracts with one counterparty. The demand charges are
approximately $53 million per year in 2006 through 2015, $49 million in 2016,
$38 million in 2017 and $13 million in 2018. As a result of changes in market
conditions, the Company's potential exposure under that guarantee currently
exceeds the security provided by RRI. CenterPoint Energy has requested RRI to
increase the amount of its existing letters of credit or, in the alternative, to
obtain a release of CERC's obligations under the guarantee, and CenterPoint
Energy and RRI are pursuing other alternatives. On June 30, 2006, the RRI
trading subsidiary and CERC jointly filed a complaint at the FERC against the
counterparty on the CERC guarantee. In the complaint, the RRI trading subsidiary
seeks a determination by the FERC that the security held by the counterparty
exceeds the level permitted by the FERC's policies. The complaint asks the FERC
to require the counterparty to release CERC from its guarantee obligation and,
in its place accept (i) a guarantee from RRI of the obligations of the RRI
trading subsidiary, and (ii) letters of credit equal to (A) one year of demand
charges for a transportation agreement related to a 2003 expansion of the
counterparty's pipeline, and (B) three months of demand charges for three other
transportation agreements held by the RRI trading subsidiary. On July 20, 2006,
the counterparty filed its answer to the complaint, arguing that CERC is
contractually bound to continue the guarantee and that the amount of the
guarantee does not violate the FERC's policies. The complaint is in its
beginning stages, and it is presently unknown what action the FERC may take on
the complaint. The RRI trading subsidiary continues to meet its obligations
under the transportation contracts.
Senior Notes. In May 2006, CERC Corp. issued $325 million aggregate
principal amount of senior notes due in May 2016 with an interest rate of 6.15%.
The proceeds from the sale of the senior notes will be used for general
corporate purposes, including repayment or refinancing of debt (including $145
million of CERC's 8.90% debentures due December 15, 2006), capital expenditures
and working capital.
Credit Facilities. In March 2006, we, CenterPoint Houston and CERC Corp.,
entered into amended and restated bank credit facilities. We replaced our $1
billion five-year revolving credit facility with a $1.2 billion five-year
revolving credit facility. The facility has a first drawn cost of LIBOR plus 60
basis points based on our current credit ratings, as compared to LIBOR plus 87.5
basis points for borrowings under the facility it replaced. The facility
contains covenants, including a debt to earnings before interest, taxes,
depreciation and amortization (EBITDA) covenant.
35
CenterPoint Houston replaced its $200 million five-year revolving credit
facility with a $300 million five-year revolving credit facility. The facility
has a first drawn cost of LIBOR plus 45 basis points based on CenterPoint
Houston's current credit ratings, as compared to LIBOR plus 75 basis points for
borrowings under the facility it replaced. The facility contains covenants,
including a debt, excluding transition bonds, to total capitalization covenant
of 65%.
CERC Corp. replaced its $400 million five-year revolving credit facility
with a $550 million five-year revolving credit facility. The facility has a
first drawn cost of LIBOR plus 45 basis points based on CERC Corp.'s current
credit ratings, as compared to LIBOR plus 55 basis points for borrowings under
the facility it replaced. The facility contains covenants, including a debt to
total capitalization covenant of 65%.
Under each of the credit facilities, an additional utilization fee of 10
basis points applies to borrowings any time more than 50% of the facility is
utilized, and the spread to LIBOR fluctuates based on the borrower's credit
rating. Borrowings under each of the facilities are subject to customary terms
and conditions. However, there is no requirement that we, CenterPoint Houston or
CERC Corp. make representations prior to borrowings as to the absence of
material adverse changes or litigation that could be expected to have a material
adverse effect. Borrowings under each of the credit facilities are subject to
acceleration upon the occurrence of events of default that we, CenterPoint
Houston or CERC Corp. consider customary.
We, CenterPoint Houston and CERC Corp. are currently in compliance with the
various business and financial covenants contained in the respective credit
facilities.
As of August 1, 2006, we had the following credit facilities (in millions):
AMOUNT UTILIZED AT
DATE EXECUTED COMPANY SIZE OF FACILITY AUGUST 1, 2006 TERMINATION DATE
------------- ------- ---------------- ------------------ ----------------
March 31, 2006 CenterPoint Energy $1,200 $28(1) March 31, 2011
March 31, 2006 CenterPoint Houston 300 4(1) March 31, 2011
March 31, 2006 CERC Corp. 550 -- March 31, 2011
----------
(1) Represents outstanding letters of credit.
The $1.2 billion CenterPoint Energy credit facility backstops a $1.0
billion commercial paper program under which CenterPoint Energy began issuing
commercial paper in June 2005. As of June 30, 2006, there was no commercial
paper outstanding. The commercial paper is rated "Not Prime" by Moody's
Investors Service, Inc. (Moody's), "A-3" by Standard & Poor's Rating Services
(S&P), a division of The McGraw-Hill Companies, and "F3" by Fitch, Inc. (Fitch)
and, as a result, we do not expect to be able to rely on the sale of commercial
paper to fund all of our short-term borrowing requirements. We cannot assure you
that these ratings, or the credit ratings set forth below in "-- Impact on
Liquidity of a Downgrade in 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 and may be revised or
withdrawn at any time by the rating agency. 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 obtain short- and long-term financing, the cost of such financings and the
execution of our commercial strategies.
Securities Registered with the SEC. At June 30, 2006, CenterPoint Energy
had a shelf registration statement covering senior debt securities, preferred
stock and common stock aggregating $1 billion. After giving effect to CERC
Corp.'s issuance of $325 million aggregate principal amount of senior notes due
in May 2016, as discussed above under "--Senior Notes," at June 30, 2006, CERC
Corp. had a shelf registration statement covering $175 million principal amount
of debt securities.
Temporary Investments. As of June 30, 2006, we had external temporary
investments of $290 million. As of August 1, 2006, we had external temporary
investments of $381 million.
Money Pool. We have a "money pool" through which the holding company and
participating subsidiaries can borrow or invest on a short-term basis. Funding
needs are aggregated and external borrowing or investing is based
36
on the net cash position. The net funding requirements of the money pool are
expected to be met with borrowings under CenterPoint Energy's revolving credit
facility or the sale of commercial paper.
Impact on Liquidity of a Downgrade in Credit Ratings. As of August 1, 2006,
Moody's, S&P, and Fitch had assigned the following credit ratings to senior debt
of CenterPoint Energy and certain subsidiaries:
MOODY'S S&P FITCH
------------------- ------------------- -------------------
COMPANY/INSTRUMENT RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3)
------------------ ------ ---------- ------ ---------- ------ ----------
CenterPoint Energy Senior Unsecured
Debt.................................... Ba1 Stable BBB- Stable BBB- Stable
CenterPoint Houston Senior Secured
Debt (First Mortgage Bonds)............. Baa2 Stable BBB Stable A- Stable
CERC Corp. Senior Unsecured Debt........... Baa3 Stable BBB Stable BBB Stable
----------
(1) A "stable" outlook from Moody's indicates that Moody's does not expect to
put the rating on review for an upgrade or downgrade within 18 months from
when the outlook was assigned or last affirmed.
(2) An S&P rating outlook assesses the potential direction of a long-term
credit rating over the intermediate to longer term.
(3) A "stable" outlook from Fitch encompasses a one-to-two-year horizon as to
the likely ratings direction.
A decline in credit ratings could increase borrowing costs under our $1.2
billion credit facility, CenterPoint Houston's $300 million credit facility and
CERC's $550 million revolving credit facility. A decline in credit ratings would
also increase the interest rate on long-term debt to be issued in the capital
markets and could negatively impact our ability to complete capital market
transactions. Additionally, a decline in credit ratings could increase cash
collateral requirements and reduce margins of our Natural Gas Distribution and
Competitive Natural Gas Sales and Services business segments.
In September 1999, we issued 2.0% ZENS having an original principal amount
of $1.0 billion of which $840 million remain outstanding. Each ZENS note is
exchangeable at the holder's option at any time for an amount of cash equal to
95% of the market value of the reference shares of TW Common attributable to
each ZENS note. If our creditworthiness were to drop such that ZENS note holders
thought our liquidity was adversely affected or the market for the ZENS notes
were to become illiquid, some ZENS note holders might decide to exchange their
ZENS notes for cash. Funds for the payment of cash upon exchange could be
obtained from the sale of the shares of TW Common that we own or from other
sources. We own shares of TW Common equal to 100% of the reference shares used
to calculate our obligation to the holders of the ZENS notes. ZENS note
exchanges result in a cash outflow because deferred tax liabilities related to
the ZENS notes and TW Common shares become current tax obligations when ZENS
notes are exchanged and TW Common shares are sold.
CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary of CERC
Corp. operating in our Competitive Natural Gas Sales and Services business
segment, provides comprehensive natural gas sales and services primarily to
commercial and industrial customers and electric and gas utilities throughout
the central and eastern United States. In order to hedge its exposure to natural
gas prices, CES uses financial derivatives with provisions standard for the
industry that establish credit thresholds and require a party to provide
additional collateral on two business days' notice when that party's rating or
the rating of a credit support provider for that party (CERC Corp. in this case)
falls below those levels. We estimate that as of June 30, 2006, unsecured credit
limits extended to CES by counterparties aggregate $133 million; however,
utilized credit capacity is significantly lower. In addition, CERC and its
subsidiaries purchase natural gas under supply agreements that contain an
aggregate credit threshold of $100 million based on CERC's S&P Senior Unsecured
Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will
increase and decrease the aggregate credit threshold accordingly.
Cross Defaults. Under our revolving credit facility, a payment default on,
or a non-payment default that permits acceleration of, any indebtedness
exceeding $50 million by us or any of our significant subsidiaries will cause a
default. Pursuant to the indenture governing our senior notes, a payment default
by us, CERC Corp. or CenterPoint Houston in respect of, or an acceleration of,
borrowed money and certain other specified types of obligations, in the
aggregate principal amount of $50 million will cause a default. As of August 1,
2006, we had issued six series of
37
senior notes aggregating $1.4 billion in principal amount under this indenture.
A default by CenterPoint Energy would not trigger a default under our
subsidiaries' debt instruments or bank credit facilities.
Other Factors that Could Affect Cash Requirements. In addition to the above
factors, our liquidity and capital resources could be affected by:
- cash collateral requirements that could exist in connection with
certain contracts, including gas purchases, gas price hedging and gas
storage activities of our Natural Gas Distribution and Competitive
Natural Gas Sales and Services business segments, particularly given
gas price levels and volatility;
- acceleration of payment dates on certain gas supply contracts under
certain circumstances, as a result of increased gas prices and
concentration of suppliers;
- increased costs related to the acquisition of gas;
- increases in interest expense in connection with debt refinancings and
borrowings under credit facilities;
- various regulatory actions;
- the ability of RRI and its subsidiaries to satisfy their obligations
as the principal customers of CenterPoint Houston and in respect of
RRI's indemnity obligations to us and our subsidiaries or in
connection with the contractual arrangement pursuant to which CERC is
a guarantor;
- slower customer payments and increased write-offs of receivables due
to higher gas prices;
- cash payments in connection with the exercise of contingent conversion
rights of holders of convertible debt;
- the outcome of litigation brought by or against us;
- contributions to benefit plans;
- restoration costs and revenue losses resulting from natural disasters
such as hurricanes; and
- various other risks identified in "Risk Factors" in Item 1A of Part I
of our 2005 Form 10-K.
Certain Contractual Limits on Our Ability to Issue Securities, Borrow Money
and Pay Dividends on Our Common Stock. CenterPoint Houston's credit facility
limits CenterPoint Houston's debt, excluding transition bonds, as a percentage
of its total capitalization to 65 percent. CERC Corp.'s bank facility and its
receivables facility limit CERC's debt as a percentage of its total
capitalization to 65 percent. Our $1.2 billion credit facility contains a debt
to EBITDA covenant. Additionally, in connection with the issuance of a certain
series of general mortgage bonds, CenterPoint Houston agreed not to issue,
subject to certain exceptions, additional first mortgage bonds.
38
CRITICAL ACCOUNTING POLICIES
A critical accounting policy is one that is both important to the
presentation of our financial condition and results of operations and requires
management to make difficult, subjective or complex accounting estimates. An
accounting estimate is an approximation made by management of a financial
statement element, item or account in the financial statements. Accounting
estimates in our historical consolidated financial statements measure the
effects of past business transactions or events, or the present status of an
asset or liability. The accounting estimates described below require us to make
assumptions about matters that are highly uncertain at the time the estimate is
made. Additionally, different estimates that we could have used or changes in an
accounting estimate that are reasonably likely to occur could have a material
impact on the presentation of our financial condition or results of operations.
The circumstances that make these judgments difficult, subjective and/or complex
have to do with the need to make estimates about the effect of matters that are
inherently uncertain. Estimates and assumptions about future events and their
effects cannot be predicted with certainty. We base our estimates on historical
experience and on various other assumptions that we believe to be reasonable
under the circumstances, the results of which form the basis for making
judgments. These estimates may change as new events occur, as more experience is
acquired, as additional information is obtained and as our operating environment
changes. Our significant accounting policies are discussed in Note 2 to the
consolidated financial statements in our 2005 Form 10-K. We believe the
following accounting policies involve the application of critical accounting
estimates. Accordingly, these accounting estimates have been reviewed and
discussed with the audit committee of the board of directors.
ACCOUNTING FOR RATE REGULATION
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS No. 71), provides that rate-regulated entities account for and report
assets and liabilities consistent with the recovery of those incurred costs in
rates if the rates established are designed to recover the costs of providing
the regulated service and if the competitive environment makes it probable that
such rates can be charged and collected. Application of SFAS No. 71 to the
electric generation portion of our business was discontinued as of June 30,
1999. Our Electric Transmission & Distribution business continues to apply SFAS
No. 71 which results in our accounting for the regulatory effects of recovery of
stranded costs and other regulatory assets resulting from the unbundling of the
transmission and distribution business from our electric generation operations
in our consolidated financial statements. Certain expenses and revenues subject
to utility regulation or rate determination normally reflected in income are
deferred on the balance sheet and are recognized in income as the related
amounts are included in service rates and recovered from or refunded to
customers. Significant accounting estimates embedded within the application of
SFAS No. 71 with respect to our Electric Transmission & Distribution business
segment relate to $321 million of recoverable electric generation-related
regulatory assets as of June 30, 2006. These costs are recoverable under the
provisions of the 1999 Texas Electric Choice Plan. Based on our analysis of the
final order issued by the Public Utility Commission of Texas (Texas Utility
Commission), we recorded an after-tax charge to earnings in 2004 of
approximately $977 million to write-down our electric generation-related
regulatory assets to their realizable value, which was reflected as an
extraordinary loss. Based on subsequent orders received from the Texas Utility
Commission, we recorded an extraordinary gain of $30 million after-tax in the
second quarter of 2005 related to the regulatory asset. Additionally, a district
court in Travis County, Texas issued a judgment that would have the effect of
restoring approximately $650 million, plus interest, of disallowed costs.
Appeals of the district court's judgment are still pending. Oral arguments have
been scheduled for September 27, 2006. No amounts related to the district
court's judgment have been recorded in our consolidated financial statements.
IMPAIRMENT OF LONG-LIVED ASSETS AND INTANGIBLES
We review the carrying value of our long-lived assets, including goodwill
and identifiable intangibles, whenever events or changes in circumstances
indicate that such carrying values may not be recoverable, and at least annually
for goodwill as required by SFAS No. 142, "Goodwill and Other Intangible
Assets." Unforeseen events and changes in circumstances and market conditions
and material differences in the value of long-lived assets and intangibles due
to changes in estimates of future cash flows, regulatory matters and operating
costs could negatively affect the fair value of our assets and result in an
impairment charge.
Fair value is the amount at which the asset could be bought or sold in a
current transaction between willing parties and may be estimated using a number
of techniques, including quoted market prices or valuations by third parties,
present value techniques based on estimates of cash flows, or multiples of
earnings or revenue performance
39
measures. The fair value of the asset could be different using different
estimates and assumptions in these valuation techniques.
ASSET RETIREMENT OBLIGATIONS
We account for our long-lived assets under SFAS No. 143, "Accounting for
Asset Retirement Obligations" (SFAS No. 143), and Financial Accounting Standards
Board Interpretation No. 47, "Accounting for Conditional Asset Retirement
Obligations -- An Interpretation of SFAS No. 143" (FIN 47). SFAS No. 143 and FIN
47 require that an asset retirement obligation be recorded at fair value in the
period in which it is incurred if a reasonable estimate of fair value can be
made. In the same period, the associated asset retirement costs are capitalized
as part of the carrying amount of the related long-lived asset. Rate-regulated
entities may recognize regulatory assets or liabilities as a result of timing
differences between the recognition of costs as recorded in accordance with SFAS
No. 143 and FIN 47, and costs recovered through the ratemaking process.
We estimate the fair value of asset retirement obligations by calculating
the discounted cash flows that are dependent upon the following components:
- Inflation adjustment -- The estimated cash flows are adjusted for
inflation estimates for labor, equipment, materials, and other
disposal costs;
- Discount rate -- The estimated cash flows include contingency factors
that were used as a proxy for the market risk premium; and
- Third party markup adjustments -- Internal labor costs included in the
cash flow calculation were adjusted for costs that a third party would
incur in performing the tasks necessary to retire the asset.
Changes in these factors could materially affect the obligation recorded to
reflect the ultimate cost associated with retiring the assets under SFAS No. 143
and FIN 47. For example, if the inflation adjustment increased 25 basis points,
this would increase the balance for asset retirement obligations by
approximately 3.0%. Similarly, an increase in the discount rate by 25 basis
points would decrease asset retirement obligations by approximately the same
percentage. At June 30, 2006, our estimated cost of retiring these assets is
approximately $77 million.
UNBILLED ENERGY REVENUES
Revenues related to the sale and/or delivery of electricity or natural gas
(energy) are generally recorded when energy is delivered to customers. However,
the determination of energy sales to individual customers is based on the
reading of their meters, which is performed on a systematic basis throughout the
month. At the end of each month, amounts of energy delivered to customers since
the date of the last meter reading are estimated and the corresponding unbilled
revenue is estimated. Unbilled electricity delivery revenue is estimated each
month based on daily supply volumes, applicable rates and analyses reflecting
significant historical trends and experience. Unbilled natural gas sales are
estimated based on estimated purchased gas volumes, estimated lost and
unaccounted for gas and tariffed rates in effect. As additional information
becomes available, or actual amounts are determinable, the recorded estimates
are revised. Consequently, operating results can be affected by revisions to
prior accounting estimates.
PENSION AND OTHER RETIREMENT PLANS
We sponsor pension and other retirement plans in various forms covering all
employees who meet eligibility requirements. We use several statistical and
other factors which attempt to anticipate future events in calculating the
expense and liability related to our plans. These factors include assumptions
about the discount rate, expected return on plan assets and rate of future
compensation increases as estimated by management, within certain guidelines. In
addition, our actuarial consultants use subjective factors such as withdrawal
and mortality rates. The actuarial assumptions used may differ materially from
actual results due to changing market and economic conditions, higher or lower
withdrawal rates or longer or shorter life spans of participants. These
differences may result in a significant impact to the amount of pension expense
recorded. Please read "-- Other Significant Matters -- Pension Plan" for further
discussion. Please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations-- Other Significant Matters -- Pension Plan"
in Item 7 of our 2005 Form 10-K.
40
NEW ACCOUNTING PRONOUNCEMENTS
See Note 4 to the Interim Condensed Financial Statements for a discussion
of new accounting pronouncements that affect us.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK FROM NON-TRADING ACTIVITIES
We measure the commodity risk of our non-trading derivatives (Non-Trading
Energy Derivatives) using a sensitivity analysis.
The sensitivity analysis performed on our Non-Trading Energy Derivatives
measures the potential loss based on a hypothetical 10% movement in energy
prices. At June 30, 2006, the recorded fair value of our Non-Trading Energy
Derivatives was a net liability of $6 million. A decrease of 10% in the market
prices of energy commodities from their June 30, 2006 levels would have
decreased the fair value of our Non-Trading Energy Derivatives from their levels
on that date by $108 million.
The above analysis of the Non-Trading Energy Derivatives utilized for price
risk management purposes does not include the favorable impact that the same
hypothetical price movement would have on our physical purchases and sales of
natural gas to which the hedges relate. Furthermore, the Non-Trading Energy
Derivative portfolio is managed to complement the physical transaction
portfolio, reducing overall risks within limits. Therefore, the adverse impact
to the fair value of the portfolio of Non-Trading Energy Derivatives held for
hedging purposes associated with the hypothetical changes in commodity prices
referenced above is expected to be substantially offset by a favorable impact on
the underlying hedged physical transactions.
INTEREST RATE RISK
We have outstanding long-term debt, bank loans, mandatory redeemable
preferred securities of subsidiary trusts holding solely our junior subordinated
debentures (trust preferred securities), some lease obligations and our
obligations under the ZENS that subject us to the risk of loss associated with
movements in market interest rates.
We had no floating-rate obligations at June 30, 2006.
At June 30, 2006, we had outstanding fixed-rate debt (excluding indexed
debt securities) and trust preferred securities aggregating $9.1 billion in
principal amount and having a fair value of $9.2 billion. These instruments are
fixed-rate and, therefore, do not expose us to the risk of loss in earnings due
to changes in market interest rates. However, the fair value of these
instruments would increase by approximately $389 million if interest rates were
to decline by 10% from their levels at June 30, 2006. In general, such an
increase in fair value would impact earnings and cash flows only if we were to
reacquire all or a portion of these instruments in the open market prior to
their maturity.
Upon adoption of SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" (SFAS No. 133), effective January 1, 2001, the ZENS
obligation was bifurcated into a debt component and a derivative component. The
debt component of $110 million at June 30, 2006 is a fixed-rate obligation and,
therefore, does not expose us to the risk of loss in earnings due to changes in
market interest rates. However, the fair value of the debt component would
increase by approximately $18 million if interest rates were to decline by 10%
from levels at June 30, 2006. Changes in the fair value of the derivative
component will be recorded in our Condensed Statements of Consolidated Income
and, therefore, we are exposed to changes in the fair value of the derivative
component as a result of changes in the underlying risk-free interest rate. If
the risk-free interest rate were to increase by 10% from June 30, 2006 levels,
the fair value of the derivative component would increase by approximately $6
million, which would be recorded as a loss in our Condensed Statements of
Consolidated Income.
EQUITY MARKET VALUE RISK
We are exposed to equity market value risk through our ownership of 21.6
million shares of TW Common, which we hold to facilitate our ability to meet our
obligations under the ZENS. A decrease of 10% from the June 30,
41
2006 market value of TW Common would result in a net loss of approximately $4
million, which would be recorded as a loss in our Condensed Statements of
Consolidated Income.
ITEM 4. CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our principal executive officer and principal financial officer, of
the effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our principal executive
officer and principal financial officer concluded that our disclosure controls
and procedures were effective as of June 30, 2006 to provide assurance that
information required to be disclosed in our reports filed or submitted under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the Securities and Exchange Commission's rules and forms
and such information is accumulated and communicated to our management,
including our principal executive officer and principal financial officer, as
appropriate to allow timely decisions regarding disclosure.
There has been no change in our internal controls over financial reporting
that occurred during the three months ended June 30, 2006 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For a description of certain legal and regulatory proceedings affecting
CenterPoint Energy, please read Notes 5 and 11 to our Interim Condensed
Financial Statements, each of which is incorporated herein by reference. See
also "Business -- Regulation" and " -- Environmental Matters" in Item 1 and
"Legal Proceedings" in Item 3 of our 2005 Form 10-K.
ITEM 1A. RISK FACTORS
There have been no material changes from the risk factors disclosed in our
2005 Form 10-K.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the annual meeting of our shareholders held on May 25, 2006, the matters
voted upon and the number of votes cast for, against or withheld, as well as the
number of abstentions and broker non-votes as to such matters (including a
separate tabulation with respect to each nominee for office), were as stated
below:
The following nominees for Class I Directors were elected to serve
three-year terms expiring at the 2009 annual meeting of shareholders (there
were no broker non-votes):
Nominees For Withheld
-------- ----------- ----------
Derrill Cody 261,674,008 11,221,695
David M. McClanahan 263,381,498 9,514,205
Robert T. O'Connell 261,474,445 11,421,258
Donald R. Campbell, Milton Carroll, John T. Cater, Michael E. Shannon, O.
Holcombe Crosswell, Janiece M. Longoria, Thomas F. Madison and Peter S. Wareing
all continue as directors of CenterPoint Energy.
The appointment of Deloitte & Touche LLP as independent accountants and
auditors for CenterPoint Energy for 2006 was ratified with 255,050,291 votes
for, 15,113,470 votes against and 2,731,940 abstentions.
The material terms of the performance goals under the Company's Short Term
Incentive Plan were reapproved, permitting certain awards to continue to qualify
as performance-based compensation deductible under Section 162(m) of the Code,
with 254,598,317 votes for, 14,236,776 votes against and 4,060,608 abstentions.
42
The material terms of the performance goals under the Company's Long-Term
Incentive Plan were reapproved, permitting certain awards to continue to qualify
as performance-based compensation deductible under Section 162(m) of the Code
with 252,407,921 votes for, 16,236,795 votes against and 4,250,985 abstentions.
The shareholder proposal regarding the future elections of directors
annually and not by classes did not receive the required affirmative vote of a
majority of the shares of common stock represented at the meeting. The proposal
received 127,569,119 votes for, 73,718,809 votes against, 3,824,715 abstentions
and 67,783,059 broker non-votes.
ITEM 5. OTHER INFORMATION
The ratio of earnings to fixed charges for the six months ended June 30,
2005 and 2006 was 1.46 and 1.76, respectively. We do not believe that the ratios
for these six month periods are necessarily indicators of the ratios for the
twelve month period due to the seasonal nature of our business. The ratios were
calculated pursuant to applicable rules of the Securities and Exchange
Commission.
ITEM 6. EXHIBITS
The following exhibits are filed herewith:
Exhibits not incorporated by reference to a prior filing are designated by
a cross (+); all exhibits not so designated are incorporated by reference to a
prior filing of CenterPoint Energy, Inc.
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
3.1.1 -- Amended and Restated Articles of Incorporation of CenterPoint Energy's Registration 3-69502 3.1
CenterPoint Energy Statement on Form S-4
3.1.2 -- Articles of Amendment to Amended and Restated Articles CenterPoint Energy's Form 10-K for 1-31447 3.1.1
of Incorporation of CenterPoint Energy the year ended December 31, 2001
3.2 -- Amended and Restated Bylaws of CenterPoint Energy CenterPoint Energy's Form 10-K for 1-31447 3.2
the year ended December 31, 2001
3.3 -- Statement of Resolution Establishing Series of Shares CenterPoint Energy's Form 10-K for 1-31447 3.3
designated Series A Preferred Stock of CenterPoint the year ended December 31, 2001
Energy
4.1 -- Form of CenterPoint Energy Stock Certificate CenterPoint Energy's Registration 3-69502 4.1
Statement on Form S-4
4.2 -- Rights Agreement dated January 1, 2002, between CenterPoint Energy's Form 10-K for 1-31447 4.2
CenterPoint Energy and JPMorgan Chase Bank, as Rights the year ended December 31, 2001
Agent
4.3 -- $1,200,000,000 Amended and Restated Credit Agreement CenterPoint Energy's Form 8-K 1-31447 4.1
dated as of March 31, 2006, among CenterPoint Energy, dated March 31, 2006
as Borrower, and the banks named therein
4.4 -- $300,000,000 Amended and Restated Credit Agreement CenterPoint Energy's Form 8-K 1-31447 4.2
dated as of March 31, 2006, among CenterPoint Houston, dated March 31, 2006
as Borrower, and the Initial Lenders named therein, as
Initial Lenders
4.5 -- $550,000,000 Amended and Restated Credit Agreement CenterPoint Energy's Form 8-K 1-31447 4.3
dated as of March 31, 2006 among CERC Corp., as dated March 31, 2006
Borrower, and the banks named therein
43
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
4.6 -- Indenture, dated as of February 1, 1998, between CERC Corp.'s Form 8-K dated 1-13265 4.1
CERC Corp. (formerly NorAm Energy Corp.) and JPMorgan February 5, 1998
Chase Bank, National Association (successor to Chase
Bank of Texas, National Association), as trustee
(the "Indenture")
+4.7 -- Supplemental Indenture No. 9 to the Indenture, dated
as of May 18, 2006, providing for the issuance of
CERC Corp.'s 6.15% Senior Notes due 2016
+12 -- Computation of Ratios of Earnings to Fixed Charges
+31.1 -- Rule 13a-14(a)/15d-14(a) Certification of David M.
McClanahan
+31.2 -- Rule 13a-14(a)/15d-14(a) Certification of Gary L.
Whitlock
+32.1 -- Section 1350 Certification of David M. McClanahan
+32.2 -- Section 1350 Certification of Gary L. Whitlock
+99.1 -- First Amendment to CenterPoint Energy Savings Plan
dated June 26, 2006
+99.2 -- Items incorporated by reference from the CenterPoint
Energy Form 10-K. Item 1A "Risk Factors"
44
SIGNATURES
Pursuant to the requirements 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.
CENTERPOINT ENERGY, INC.
By: /s/ James S. Brian
------------------------------------
James S. Brian
Senior Vice President and Chief
Accounting Officer
Date: August 3, 2006
45
EXHIBIT INDEX
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
3.1.1 -- Amended and Restated Articles of Incorporation of CenterPoint Energy's Registration 3-69502 3.1
CenterPoint Energy Statement on Form S-4
3.1.2 -- Articles of Amendment to Amended and Restated Articles CenterPoint Energy's Form 10-K for 1-31447 3.1.1
of Incorporation of CenterPoint Energy the year ended December 31, 2001
3.2 -- Amended and Restated Bylaws of CenterPoint Energy CenterPoint Energy's Form 10-K for 1-31447 3.2
the year ended December 31, 2001
3.3 -- Statement of Resolution Establishing Series of Shares CenterPoint Energy's Form 10-K for 1-31447 3.3
designated Series A Preferred Stock of CenterPoint the year ended December 31, 2001
Energy
4.1 -- Form of CenterPoint Energy Stock Certificate CenterPoint Energy's Registration 3-69502 4.1
Statement on Form S-4
4.2 -- Rights Agreement dated January 1, 2002, between CenterPoint Energy's Form 10-K for 1-31447 4.2
CenterPoint Energy and JPMorgan Chase Bank, as Rights the year ended December 31, 2001
Agent
4.3 -- $1,200,000,000 Amended and Restated Credit Agreement CenterPoint Energy's Form 8-K 1-31447 4.1
dated as of March 31, 2006, among CenterPoint Energy, dated March 31, 2006
as Borrower, and the banks named therein
4.4 -- $300,000,000 Amended and Restated Credit Agreement CenterPoint Energy's Form 8-K 1-31447 4.2
dated as of March 31, 2006, among CenterPoint Houston, dated March 31, 2006
as Borrower, and the Initial Lenders named therein, as
Initial Lenders
4.5 -- $550,000,000 Amended and Restated Credit Agreement CenterPoint Energy's Form 8-K 1-31447 4.3
dated as of March 31, 2006 among CERC Corp., as dated March 31, 2006
Borrower, and the banks named therein
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
4.6 -- Indenture, dated as of February 1, 1998, between CERC Corp.'s Form 8-K dated 1-13265 4.1
CERC Corp. (formerly NorAm Energy Corp.) and JPMorgan February 5, 1998
Chase Bank, National Association (successor to Chase
Bank of Texas, National Association), as trustee
(the "Indenture")
+4.7 -- Supplemental Indenture No. 9 to the Indenture, dated
as of May 18, 2006, providing for the issuance of
CERC Corp.'s 6.15% Senior Notes due 2016
+12 -- Computation of Ratios of Earnings to Fixed Charges
+31.1 -- Rule 13a-14(a)/15d-14(a) Certification of David M.
McClanahan
+31.2 -- Rule 13a-14(a)/15d-14(a) Certification of Gary L.
Whitlock
+32.1 -- Section 1350 Certification of David M. McClanahan
+32.2 -- Section 1350 Certification of Gary L. Whitlock
+99.1 -- First Amendment to CenterPoint Energy Savings Plan
dated June 26, 2006
+99.2 -- Items incorporated by reference from the CenterPoint
Energy Form 10-K. Item 1A "Risk Factors"