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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-Q/A
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-14365
---------------------
EL PASO CORPORATION
(Exact Name of Registrant as Specified in its Charter)
DELAWARE 76-0568816
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)
EL PASO BUILDING
1001 LOUISIANA STREET 77002
HOUSTON, TEXAS (Zip Code)
(Address of Principal Executive Offices)
Telephone Number: (713) 420-2600
Internet Website: www.elpaso.com
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 the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Common stock, par value $3 per share. Shares outstanding on May 6, 2002:
532,727,453
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BASIS FOR AMENDED FORM 10-Q
We are filing this amended Form 10-Q for the quarterly period ended March
31, 2002, to provide a more comprehensive discussion of our power restructuring
activities, as well as a more specific discussion of two power restructuring
transactions completed during the period, and the impact of these transactions
on our first quarter 2002 operating results. We have also expanded the
discussions related to our energy-related price risk management activities to
include the maturities and changes during the first quarter for non-trading
energy contracts. This amendment relates solely to the matters discussed above
and does not change in any way the financial results reported in our original
Form 10-Q filed on May 10, 2002. In addition, this amended Form 10-Q does not
update all information included in that original Form 10-Q, and you should refer
to our Current Reports on Form 8-K dated after May 10, 2002, for additional
events that have occurred since that date.
We will include a version of this amended Form 10-Q for the quarter ended
March 31, 2002, that is marked to show changes from the original filing on our
website at www.elpaso.com under For Investors, El Paso Corporation Financial
Filings, or you can request a copy of this amended filing at no charge. Requests
should be directed to El Paso Corporation 1001 Louisiana, Houston, Texas 77002,
attention: Bruce Connery, Vice President, Investor Relations; telephone
713-420-5855. You may also access this amended filing on the SEC website at
www.sec.gov, where all of our SEC filings may be found.
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EL PASO CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
(UNAUDITED)
QUARTER ENDED
MARCH 31,
-----------------
2002 2001
------- -------
Operating revenues.......................................... $13,188 $17,762
------- -------
Operating expenses
Cost of products and services............................. 11,025 15,697
Operation and maintenance................................. 696 663
Merger-related costs...................................... -- 1,161
Asset impairments......................................... 342 --
Ceiling test charge....................................... 33 --
Depreciation, depletion and amortization.................. 375 326
Taxes, other than income taxes............................ 92 127
------- -------
12,563 17,974
------- -------
Operating income (loss)..................................... 625 (212)
------- -------
Other income
Earnings from unconsolidated affiliates................... 61 100
Other, net................................................ (2) 44
------- -------
59 144
------- -------
Income (loss) before interest, income taxes and other
charges................................................... 684 (68)
------- -------
Interest and debt expense................................... 307 295
Minority interest........................................... 40 62
Income taxes................................................ 108 (35)
------- -------
455 322
------- -------
Income (loss) before extraordinary items and cumulative
effect of accounting change............................... 229 (390)
Extraordinary items, net of income taxes.................... -- (10)
Cumulative effect of accounting change, net of income
taxes..................................................... 154 --
------- -------
Net income (loss)........................................... $ 383 $ (400)
======= =======
Basic earnings per common share
Income (loss) before extraordinary items.................. $ 0.44 $ (0.78)
Extraordinary items, net of income taxes.................. -- (0.02)
Cumulative effect of accounting change, net of income
taxes.................................................. 0.29 --
------- -------
Net income (loss)......................................... $ 0.73 $ (0.80)
======= =======
Diluted earnings per common share
Income (loss) before extraordinary items.................. $ 0.43 $ (0.78)
Extraordinary items, net of income taxes.................. -- (0.02)
Cumulative effect of accounting change, net of income
taxes.................................................. 0.29 --
------- -------
Net income (loss)......................................... $ 0.72 $ (0.80)
======= =======
Basic average common shares outstanding..................... 527 502
======= =======
Diluted average common shares outstanding................... 538 502
======= =======
Dividends declared per common share......................... $ 0.22 $ 0.21
======= =======
See accompanying notes.
1
EL PASO CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
(UNAUDITED)
MARCH 31, DECEMBER 31,
2002 2001
--------- ------------
ASSETS
Current assets
Cash and cash equivalents................................. $ 1,259 $ 1,139
Accounts and notes receivable, net
Customer............................................... 5,240 5,074
Unconsolidated affiliates.............................. 1,186 911
Other.................................................. 737 896
Inventory................................................. 1,011 825
Assets from price risk management activities.............. 2,131 2,702
Other..................................................... 1,280 1,112
------- -------
Total current assets.............................. 12,844 12,659
------- -------
Property, plant and equipment, at cost
Pipelines................................................. 17,660 17,596
Natural gas and oil properties, at full cost.............. 13,717 14,466
Gathering and processing systems.......................... 2,675 2,628
Refining, crude oil and chemical facilities............... 2,442 2,425
Power facilities.......................................... 1,044 834
Other..................................................... 1,022 1,021
------- -------
38,560 38,970
Less accumulated depreciation, depletion and
amortization........................................... 14,256 14,379
------- -------
Total property, plant and equipment, net.......... 24,304 24,591
------- -------
Other assets
Investments in unconsolidated affiliates.................. 4,889 5,297
Assets from price risk management activities.............. 2,943 2,118
Other..................................................... 3,577 3,506
------- -------
11,409 10,921
------- -------
Total assets...................................... $48,557 $48,171
======= =======
See accompanying notes.
2
EL PASO CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS -- (CONTINUED)
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
(UNAUDITED)
MARCH 31, DECEMBER 31,
2002 2001
--------- ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable
Trade.................................................. $ 5,252 $ 4,971
Unconsolidated affiliates.............................. 28 26
Other.................................................. 855 959
Short-term borrowings and other financing obligations..... 2,674 3,314
Notes payable to unconsolidated affiliates................ 371 504
Liabilities from price risk management activities......... 1,950 1,868
Other..................................................... 1,196 1,923
------- -------
Total current liabilities......................... 12,326 13,565
------- -------
Debt
Long-term debt and other financing obligations............ 14,372 12,816
Notes payable to unconsolidated affiliates................ 326 368
------- -------
14,698 13,184
------- -------
Other liabilities
Liabilities from price risk management activities......... 1,277 1,231
Deferred income taxes..................................... 4,513 4,459
Other..................................................... 2,205 2,363
------- -------
7,995 8,053
------- -------
Commitments and contingencies
Securities of subsidiaries
Company-obligated preferred securities of consolidated
trusts................................................. 925 925
Minority interests........................................ 3,259 3,088
------- -------
4,184 4,013
------- -------
Stockholders' equity
Common stock, par value $3 per share; authorized
750,000,000 shares; issued 540,009,931 shares in 2002
and 538,363,664 shares in 2001......................... 1,620 1,615
Additional paid-in capital................................ 3,183 3,130
Retained earnings......................................... 5,169 4,902
Accumulated other comprehensive income.................... (171) 157
Treasury stock (at cost) 7,376,438 shares in 2002 and
7,628,799 shares in 2001............................... (254) (261)
Unamortized compensation.................................. (193) (187)
------- -------
Total stockholders' equity........................ 9,354 9,356
------- -------
Total liabilities and stockholders' equity........ $48,557 $48,171
======= =======
See accompanying notes.
3
EL PASO CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
(UNAUDITED)
QUARTER ENDED
MARCH 31,
-------------------
2002 2001
-------- -------
Cash flows from operating activities
Net income (loss)......................................... $ 383 $ (400)
Adjustments to reconcile net income (loss) to net cash
from operating activities
Non-cash gains from trading and power activities....... (427) (7)
Non-cash portion of merger-related costs and asset
impairments........................................... 342 677
Depreciation, depletion and amortization............... 375 326
Ceiling test charge.................................... 33 --
Undistributed earnings of unconsolidated affiliates.... (2) (61)
Net (gain) loss on the sale of assets.................. (16) 5
Deferred income tax expense (benefit).................. 96 (61)
Extraordinary items.................................... -- 11
Cumulative effect of accounting change................. (154) --
Other non-cash income items............................ 85 33
Working capital changes................................... (518) 306
Non-working capital changes and other..................... (111) 226
-------- -------
Net cash provided by operating activities......... 86 1,055
-------- -------
Cash flows from investing activities
Additions to property, plant and equipment................ (685) (704)
Additions to investments.................................. (280) (134)
Net proceeds from the sale of assets...................... 493 171
Proceeds from the sale of investments..................... 19 10
Repayment of notes receivable from unconsolidated
affiliates............................................. 62 77
Other..................................................... 48 --
-------- -------
Net cash used in investing activities............. (343) (580)
-------- -------
Cash flows from financing activities
Net borrowings (repayments) under commercial paper and
short-term credit facilities........................... 32 (1,130)
Borrowings under credit facilities........................ -- 245
Repayments on credit facilities........................... -- (260)
Repayments of notes payable............................... (15) --
Payments to retire long-term debt and other financing
obligations............................................ (751) (848)
Net proceeds from the issuance of long-term debt and other
financing obligations.................................. 1,378 1,746
Issuances of common stock................................. 13 24
Dividends paid............................................ (108) (60)
Increase in notes payable to unconsolidated affiliates.... 3 --
Decrease in notes payable to unconsolidated affiliates.... (175) (347)
-------- -------
Net cash provided by (used in) financing
activities....................................... 377 (630)
-------- -------
Increase (decrease) in cash and cash equivalents............ 120 (155)
Cash and cash equivalents
Beginning of period....................................... 1,139 741
-------- -------
End of period............................................. $ 1,259 $ 586
======== =======
See accompanying notes.
4
EL PASO CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(IN MILLIONS)
(UNAUDITED)
QUARTER ENDED
MARCH 31,
----------------
2002 2001
----- -------
Net income (loss)........................................... $ 383 $ (400)
----- -------
Foreign currency translation adjustments.................... (1) (14)
Unrealized net gains (losses) from cash flow hedging
activity
Cumulative-effect transition adjustment (net of tax of
$673).................................................. -- (1,280)
Unrealized mark-to-market losses arising during period
(net of tax of $135 in 2002 and $123 in 2001).......... (232) (239)
Reclassification adjustments for changes in initial value
to settlement date
(net of tax of $54 in 2002 and $249 in 2001)........... (95) 463
----- -------
Other comprehensive loss............................. (328) (1,070)
----- -------
Comprehensive income (loss)................................. $ 55 $(1,470)
===== =======
See accompanying notes.
5
EL PASO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION
Our 2001 Annual Report on Form 10-K includes a summary of our significant
accounting policies and other disclosures. You should read it in conjunction
with this Quarterly Report on Form 10-Q/A. The financial statements as of March
31, 2002, and for the quarters ended March 31, 2002 and 2001, are unaudited. The
balance sheet as of December 31, 2001, is derived from the audited balance sheet
filed in our Form 10-K. These financial statements have been prepared pursuant
to the rules and regulations of the U.S. Securities and Exchange Commission and
do not include all disclosures required by accounting principles generally
accepted in the United States. In our opinion, we have made all adjustments, all
of which are of a normal, recurring nature (except for merger-related costs,
asset impairments, a ceiling test charge and a cumulative effect of accounting
change, all discussed below), to fairly present our interim period results.
Information for interim periods may not necessarily indicate the results of
operations for the entire year due to the seasonal nature of our businesses. The
prior period information also includes reclassifications which were made to
conform to the current period presentation. These reclassifications have no
effect on our reported net income or stockholders' equity.
Our accounting policies are consistent with those discussed in our Form
10-K, except as discussed below.
Goodwill and Other Intangible Assets
Our intangible assets consist primarily of goodwill recognized from
acquisitions. On January 1, 2002, we adopted Statement of Financial Accounting
Standards (SFAS) No. 141, Business Combinations, and SFAS No. 142, Goodwill and
Other Intangible Assets. These standards require that we recognize goodwill
separately from other intangible assets. In addition, goodwill and
indefinite-lived intangibles are no longer amortized. Rather, goodwill is tested
periodically for impairment, at least on an annual basis, or whenever events or
circumstances indicate that an impairment may have occurred. SFAS No. 141
requires that upon adoption of SFAS No. 142, any negative goodwill should be
written off as a cumulative effect of a change in accounting. Prior to adoption
of these standards, we amortized goodwill, negative goodwill and other
intangibles using the straight-line method over periods ranging from 5 to 40
years. As a result of our adoption of these standards on January 1, 2002, we
recognized a $154 million gain, net of income taxes, related to the write-off of
negative goodwill as a cumulative effect of an accounting change in our income
statement. Our initial periodic tests for impairment were completed during the
first quarter of 2002, and did not indicate any impairment of our goodwill. In
addition, we stopped amortizing goodwill and negative goodwill that was
estimated to be approximately $7 million, net of income taxes, for the quarter
ended March 31, 2002. If we had adopted SFAS No. 141 and 142 on January 1, 2001,
for the quarter ended March 31, 2001, we would have reported a loss before
extraordinary items and cumulative effect of accounting change of $383 million,
or $(0.76) per share, and a net loss of $393 million, or $(0.78) per share.
Asset Impairments
On January 1, 2002, we adopted SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. The provisions of this statement supersede
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of. There was no initial financial statement
impact of adopting this standard.
Price Risk Management Activities
Accounting for Power Restructuring Activities. Our Merchant Energy
segment's power restructuring activities involve amending or terminating a power
plant's existing power purchase contract to eliminate the requirement that the
plant provide its own generation to the regulated utility and replacing that
requirement with the ability to provide power to the utility from the wholesale
power market. Prior to a restructuring, the
6
power plant and its related power purchase contract are accounted for at their
historical cost, which is either the cost of construction or, if acquired, the
acquisition cost. Revenues and expenses prior to restructuring are accounted for
on an accrual basis as power is generated and sold to the utility. Following a
restructuring, the accounting treatment for the power purchase agreement changes
because the restructured contract must be marked to its fair value under SFAS
No. 133, Accounting for Derivatives and Hedging Activities. In the period the
restructuring is completed, the book value of the restructured contract is
adjusted to its fair value, with any change reflected in income. Since the power
plant no longer has the exclusive right to provide power under the original,
dedicated power purchase contract, it operates as a peaking merchant plant,
operating only when it is economical to do so. Because of this significant
change in its use, in most cases the book value of the plant is reduced to its
fair value through a charge to earnings. These changes require us to terminate
or amend any related fuel supply and steam agreements associated with the
operations of the facility.
We conduct the majority of our power restructuring activities through our
unconsolidated affiliate, Chaparral, and therefore our share of the revenues and
expenses of these activities is recognized through earnings from unconsolidated
affiliates. However, as in the case of the Eagle Point restructuring completed
in the first quarter of 2002, we also conduct these activities for power assets
owned by our consolidated subsidiaries. In consolidated entities, the
restructured power contract is presented in our balance sheet as an asset from
price risk management activities. In our income statement we present, as
revenues, the original adjustment that occurs when the contract is marked to
fair value as a derivative, as well as subsequent changes in the value of the
contract. Costs associated with the restructuring activity, including
adjustments to the underlying power plant's book value and any related
intangible assets, contract termination fees and closing costs, are recorded in
our income statement as costs of products and services. During the first quarter
of 2002, we recognized revenues from power restructuring activities of $1,028
million and corresponding costs of products and services of $565 million.
2. DIVESTITURES
In March 2002, we completed the sale of natural gas and oil properties
located in east and south Texas. Net proceeds from this sale were approximately
$500 million. We did not recognize a gain or loss on the properties sold.
In April 2002, we sold midstream assets to El Paso Energy Partners, L.P., a
publicly traded master limited partnership in which we serve as the general
partner, for approximately $735 million, net of $15 million of working capital
changes due to natural gas imbalances. Net proceeds from this sale were
approximately $420 million in cash, a $119 million note payable to us that was
subsequently paid, common units of El Paso Energy Partners with a fair value of
$6 million and the partnership's interest in the Prince tension leg platform
including its nine percent overriding royalty interest in the Prince production
field with a combined fair value of $190 million. No gain or loss was recognized
on this sale.
In April 2002, we announced the sales of an additional $425 million of
assets, including natural gas and oil production properties and related
contracts and a natural gas gathering system.
3. MERGER-RELATED COSTS
On January 29, 2001, we merged with The Coastal Corporation in a merger
that was accounted for as a pooling of interests. During the quarter ended March
31, 2001, we incurred costs related to this merger consisting of the following
(in millions):
Employee severance, retention and transition costs.......... $ 802
Transaction costs........................................... 54
Business and operational integration costs.................. 17
Merger-related asset impairments............................ 134
Other....................................................... 154
------
$1,161
======
7
Employee severance, retention and transition costs include direct payments
to, and benefit costs for, severed employees and early retirees that occurred as
a result of our merger-related workforce reduction and consolidation. Following
the Coastal merger, we completed an employee restructuring across all of our
operating segments, resulting in the reduction of 3,285 full-time positions
through a combination of early retirements and terminations. Employee severance
costs include actual severance payments and costs for pension and
post-retirement benefits settled and curtailed under existing benefit plans as a
result of this restructuring. Retention charges include payments to employees
who were retained following the merger and payments to employees to satisfy
contractual obligations. Transition costs relate to costs to relocate employees
and costs for severed and retired employees arising after their severance date
to transition their jobs into the ongoing workforce. The amount of employee
severance, retention and transition costs paid and charged against the accrued
amount in the quarter ended March 31, 2001, was approximately $422 million. The
remainder of the charges were paid during subsequent quarters in 2001.
Also included in employee severance, retention and transition costs for the
quarter ended March 31, 2001, was a charge of $278 million resulting from the
issuance of approximately 4 million shares of common stock incurred on the date
of the Coastal merger in exchange for the fair value of Coastal employees' and
directors' stock options.
Transaction costs include investment banking, legal, accounting, consulting
and other advisory fees incurred to obtain federal and state regulatory
approvals and take other actions necessary to complete our merger. All of these
items were expensed as incurred.
Business and operational integration costs include charges to consolidate
facilities and operations of our business segments, such as lease termination
and abandonment charges and incremental fees under software and seismic license
agreements. These charges were accrued at the time we completed our relocations
and closed these offices. The amounts accrued will be paid over the term of the
applicable non-cancelable lease agreement. All other costs were expensed as
incurred.
Merger-related asset impairments relate to write-offs or write-downs of
capitalized costs for duplicate systems, and facilities and assets whose value
was impaired as a result of decisions on the strategic direction of our combined
operations following our merger with Coastal. These charges occurred in our
Merchant Energy and Production segments, and all of these assets have either had
their operations suspended or continue to be held for use. The charges taken
were based on a comparison of the cost of the assets to their estimated fair
value to the ongoing operations based on the change in operating strategy.
Other costs include payments made in satisfaction of obligations arising
from the Federal Trade Commission (FTC) approval of our merger with Coastal and
other miscellaneous charges. These items were expensed as incurred.
4. ASSET IMPAIRMENTS
During the first quarter of 2002, we recognized an asset impairment charge
in our Merchant Energy segment of $342 million related to several of our
investments in Argentina. During the latter part of 2001, economic conditions in
Argentina deteriorated and the Argentine government defaulted on its public debt
obligations. In the first quarter of 2002, the government changed several
Argentine laws, including: (i) repealing the one-to-one exchange rate for the
Argentine Peso with U.S. dollar; (ii) mandating that all Argentine contracts and
obligations previously denominated in U.S. dollars be re-negotiated and
denominated in Argentine Pesos; and (iii) imposing a tax on crude oil exports.
The Argentine Peso devaluation combined with these new law changes effectively
converted our projects' contracts and sources of revenue from U.S. dollars to
Argentine Pesos and resulted in the impairment charge, which represents the full
amount of each of the investments impacted by these law changes. We have a
remaining investment in a pipeline project in Argentina with an aggregate
investment of approximately $40 million. We continue to monitor the situation
closely. However, should these conditions persist, or new unfavorable
developments occur, we may also be required to evaluate our remaining investment
for impairment.
8
5. CEILING TEST CHARGE
Under the full cost method of accounting for natural gas and oil
properties, we perform quarterly ceiling tests to evaluate whether the carrying
value of natural gas and oil properties exceeds the present value of future net
revenues, discounted at 10 percent, plus the lower of cost or fair market value
of unproved properties. At March 31, 2002, capitalized costs exceeded this
ceiling limit by $33 million, including $10 million for our Brazilian full cost
pool and $23 million for other international production operations in Turkey.
6. EXTRAORDINARY ITEMS
Under an FTC order, as a result of our merger with Coastal, we sold our
Gulfstream pipeline project, our 50 percent interest in the Stingray pipeline
system and our investment in the Empire pipeline system during the first quarter
of 2001. Net proceeds from these sales were approximately $144 million, and we
recognized an extraordinary net loss of approximately $10 million, net of tax
benefits of approximately $1 million.
7. EARNINGS PER SHARE
We calculated basic and diluted earnings per share amounts as follows for
the quarters ended March 31:
2002 2001
------------------ --------
BASIC DILUTED(1) BASIC(1)
----- ---------- --------
(IN MILLIONS, EXCEPT PER
COMMON SHARE AMOUNTS)
Income (loss) before extraordinary items and cumulative
effect of accounting change............................... $ 229 $ 229 $ (390)
Interest on trust preferred securities and preferred stock
dividends, net of income taxes......................... -- 3 --
----- ----- ------
Adjusted income (loss) before extraordinary items and
cumulative effect of accounting change................. 229 232 (390)
Extraordinary items, net of income taxes.................. -- -- (10)
Cumulative effect of accounting change, net of income
taxes.................................................. 154 154 --
----- ----- ------
Adjusted net income (loss)................................ $ 383 $ 386 $ (400)
===== ===== ======
Average common shares outstanding........................... 527 527 502
Effect of dilutive securities
Stock options............................................. -- 2 --
Restricted stock.......................................... -- -- --
FELINE PRIDES(SM)......................................... -- 1 --
Trust preferred securities................................ -- 8 --
Convertible debentures.................................... -- -- --
----- ----- ------
Average common shares outstanding(1)........................ 527 538 502
===== ===== ======
Earnings per common share
Adjusted income (loss) before extraordinary items and
cumulative effect of accounting change................. $0.44 $0.43 $(0.78)
Extraordinary items, net of income taxes.................. -- -- (0.02)
Cumulative effect of accounting change, net of income
taxes.................................................. 0.29 0.29 --
----- ----- ------
Adjusted net income (loss)................................ $0.73 $0.72 $(0.80)
===== ===== ======
---------------
(1) Due to their antidilutive effect on earnings per share, for 2001, we
excluded our 6 million shares of stock options, 1 million shares of
restricted stock, 5 million shares of FELINE PRIDES(SM), 8 million shares of
trust preferred securities and 3 million shares of convertible debentures,
and for 2002, we excluded 8 million shares of convertible debentures.
9
8. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES
The following table summarizes the carrying value of our trading and
non-trading price risk management assets and liabilities as of March 31, 2002
and December 31, 2001:
MARCH 31, DECEMBER 31,
2002 2001
--------- ------------
(IN MILLIONS)
Net assets (liabilities)
Energy contracts
Trading contracts(1)(2)................................ $ 995 $1,295
------ ------
Non-trading contracts(3)
Derivatives designated as hedges..................... (70) 459
Other derivatives.................................... 968 --
------ ------
898 459
------ ------
Total energy contracts................................. 1,893 1,754
------ ------
Interest rate and foreign currency contracts.............. (46) (33)
------ ------
Total price risk management activities................. $1,847 $1,721
====== ======
---------------
(1) Trading contracts represent those that qualify for accounting under Emerging
Issues Task Force Issue No. 98-10, Accounting for Contracts Involved in
Energy Trading and Risk Management Activities.
(2) Impacting our trading balance at March 31, 2002, was a charge to earnings of
approximately $61 million related to our revised estimate of the fair value
of long-term positions in our trading price risk management activities. As a
result of diminished liquidity in the marketplace for natural gas and power
transactions, we no longer recognize gains from the fair value of trading
positions beyond ten years unless there is clearly demonstrated liquidity in
a specific market.
(3) Non-trading contracts include hedges related to our oil and natural gas
producing activities and derivatives from our power contract restructuring
activities. We do not recognize gains from the fair value of our non-trading
activities beyond ten years, unless there is clearly demonstrated liquidity
in a specific market.
Included in other derivatives as of March 31, 2002, are $984 million of
derivative contracts related to the power restructuring activities of our
consolidated subsidiaries. Of this amount, $884 million related to a power
restructuring that occurred during the first quarter of 2002 at our Eagle Point
Cogeneration power plant, and $100 million related to a power restructuring that
occurred during the fourth quarter of 2001 at our Capital District Energy Center
Cogeneration Associates plant.
The fair value of the derivatives related to our power restructuring
activities is determined based on the expected cash receipts and payments under
the contracts using future power prices compared to the contractual prices under
these contracts. We discount these cash flows at an interest rate commensurate
with the term of each contract and the credit risk of each contract's
counterparty. We also adjust our valuations for factors such as market
liquidity, market price correlation and model risk, as needed. Future power
prices are based on the forward pricing curve of the appropriate power delivery
and receipt points in the applicable power market. This forward pricing curve is
derived from a combination of actual prices observed in the applicable market,
price quotes from brokers and extrapolation models that rely on actively quoted
prices and historical information. The timing of cash receipts and payments are
based on the expected timing of power delivered under these contracts. The fair
value of our derivatives is updated each period based on changes in actual and
projected market prices, fluctuations in the credit ratings of our
counterparties, significant changes in interest rates, and changes to the
assumed timing of deliveries.
Also included in other derivatives is a $16 million loss we recognized in
connection with the sale of our natural gas and oil properties located in east
and south Texas in March 2002. We recognized this loss on derivative positions
that no longer qualify as cash flow hedges under SFAS No. 133 because they were
designated as hedges of anticipated future production on the properties sold.
10
9. INVENTORY
Our inventory consisted of the following:
MARCH 31, DECEMBER 31,
2002 2001
--------- ------------
(IN MILLIONS)
Refined products, crude oil and chemicals................... $ 738 $577
Coal, materials and supplies and other...................... 217 207
Natural gas in storage...................................... 56 41
------ ----
$1,011 $825
====== ====
10. DEBT AND OTHER CREDIT FACILITIES
At March 31, 2002, our weighted average interest rate on our commercial
paper and short-term credit facilities was 2.7%, and at December 31, 2001, it
was 3.2%. We had the following short-term borrowings and other financing
obligations:
MARCH 31, DECEMBER 31,
2002 2001
------------- ------------
(IN MILLIONS)
Commercial paper............................................ $1,435 $1,265
Short-term credit facility.................................. 35 111
Current maturities of long-term debt and other financing
obligations............................................... 1,089 1,799
Notes payable............................................... 115 139
------ ------
$2,674 $3,314
====== ======
Our significant borrowing and repayment activities during 2002 are
presented below. These activities do not include borrowings or repayments on our
short-term financing instruments with an original maturity of three months or
less, including our commercial paper programs and short-term credit facilities.
INTEREST NET
DATE COMPANY TYPE RATE PRINCIPAL PROCEEDS DUE DATE
---- ------- ---- -------- --------- -------- --------
(IN MILLIONS)
Issuances
2002
January El Paso Medium-term notes 7.75% $1,100 $1,081 2032
February SNG Notes 8.00% 300 297 2032
Senior secured
April Mohawk River notes 7.75% 92 90 2008
Funding IV
May El Paso Euro notes 7.125% 450(1) 448 2009
Retirements
2002
January SNG Long-term debt 7.85% $ 100 2002
January EPNG Long-term debt 7.75% 215 2002
March El Paso CGP Long-term debt Variable 400 2002
Jan.-Mar. El Paso Natural gas LIBOR+ 24 2002
Production production payment 0.372%
Jan.-Mar. Various Long-term debt Various 12 2002
May SNG Long-term debt 8.625% 100 2002
---------------
(1)Represents the U.S. dollar equivalent of 500 million Euros on the issuance
date.
11. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
We and several of our subsidiaries were named defendants in eleven
purported class action, municipal or individual lawsuits, filed in California
state courts (a list of the California cases is included in Part II, Item 1,
11
Legal Proceedings). The eleven suits contend that our entities acted improperly
to limit the construction of new pipeline capacity to California and/or to
manipulate the price of natural gas sold into the California marketplace. The
lawsuits are at the preliminary pleading stages with trial not anticipated until
late 2003 at the earliest. We and our directors also have been named in a
shareholder derivative action, contending that our directors failed to prevent
the conduct alleged in several of these underlying lawsuits. The derivative suit
originally was filed in California, but was dismissed and refiled in Texas in
March 2002.
In September 2001, we received a civil document subpoena from the
California Department of Justice, seeking information said to be relevant to the
Department's ongoing investigation into the high electricity prices in
California. We have produced and expect to continue to produce materials
pursuant to this subpoena.
In August 2000, a main transmission line owned and operated by El Paso
Natural Gas Company (EPNG) ruptured at the crossing of the Pecos River near
Carlsbad, New Mexico. Twelve individuals at the site were fatally injured. On
June 20, 2001, the U.S. Department of Transportation's Office of Pipeline Safety
issued a Notice of Proposed Violation to EPNG. The Notice alleged five probable
violations of its regulations (a list of the alleged five probable violations is
included in Part II, Item 1, Legal Proceedings), proposed fines totaling $2.5
million and proposed corrective actions. In October 2001, EPNG filed a detailed
response with the Office of Pipeline Safety disputing each of the alleged
violations. We are cooperating with the National Transportation Safety Board in
an investigation into the facts and circumstances concerning the possible causes
of the rupture. If we are required to pay the proposed fines, it will not have a
material adverse effect on our financial position, operating results or cash
flows. In addition, a number of personal injury and wrongful death lawsuits were
filed against us in connection with the rupture. Several of these suits have
been settled, with payments fully covered by insurance. Seven Carlsbad lawsuits
remain, with one of the seven having reached a contingent settlement within
insurance coverage (a list of the remaining Carlsbad lawsuits is included in
Part II, Item 1, Legal Proceedings).
In 1997, a number of our subsidiaries were named defendants in actions
brought by Jack Grynberg on behalf of the U.S. Government under the False Claims
Act. Generally, these complaints allege an industry-wide conspiracy to under
report the heating value as well as the volumes of the natural gas produced from
federal and Native American lands, which deprived the U.S. Government of
royalties. These matters have been consolidated for pretrial purposes (In re:
Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District
of Wyoming, filed June 1997). In May 2001, the court denied the defendants'
motions to dismiss.
A number of our subsidiaries were named defendants in Quinque Operating
Company, et al v. Gas Pipelines and Their Predecessors, et al, filed in 1999 in
the District Court of Stevens County, Kansas. This class action complaint
alleges that the defendants mismeasured natural gas volumes and heating content
of natural gas on non-federal and non-Native American lands. The Quinque
complaint was transferred to the same court handling the Grynberg complaint and
has now been sent back to Kansas State Court for further proceedings. A motion
to dismiss this case is pending.
In compliance with the 1990 amendments to the Clean Air Act (CAA), we use
the gasoline additive, methyl tertiary-butyl ether (MTBE), in some of our
gasoline. We also produce, buy, sell and distribute MTBE. A number of lawsuits
have been filed throughout the U.S. regarding MTBE's potential impact on water
supplies. We are currently one of several defendants in five such lawsuits in
New York. Our costs and legal exposure related to these lawsuits and claims are
not currently determinable.
In addition, we and our subsidiaries and affiliates are named defendants in
numerous lawsuits and governmental proceedings that arise in the ordinary course
of our business. For each of these matters, we evaluate the merits of the case,
our exposure to the matter and possible legal or settlement strategies and the
likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we make the necessary accruals. As new
information becomes available, our estimates may change. The impact of these
changes may have a material effect on our results of operations. As of March 31,
2002, we had reserves totaling $171 million for all outstanding legal matters.
12
While the outcome of the matters discussed above cannot be predicted with
certainty, based on information known to date and our existing accruals, we do
not expect the ultimate resolution of these matters will have a material adverse
effect on our ongoing financial position, operating results or cash flows.
Environmental Matters
We are subject to extensive federal, state and local laws and regulations
governing environmental quality and pollution control. These laws and
regulations require us to remove or remedy the effect on the environment of the
disposal or release of specified substances at current and former operating
sites. As of March 31, 2002, we had a reserve of approximately $562 million for
expected remediation costs including $535 million for associated onsite, offsite
and groundwater technical studies, and approximately $27 million for other costs
which we anticipate incurring through 2027. In addition, we expect to make
capital expenditures for environmental matters of approximately $341 million in
the aggregate for the years 2002 through 2007. These expenditures primarily
relate to compliance with clean air regulations.
Since 1988, our subsidiary, Tennessee Gas Pipeline Company (TGP), has been
engaged in an internal project to identify and deal with the presence of
polychlorinated biphenyls (PCBs) and other substances, including those on the
Environmental Protection Agency's (EPA) List of Hazardous Substances, at
compressor stations and other facilities it operates. While conducting this
project, TGP has been in frequent contact with federal and state regulatory
agencies, both through informal negotiation and formal entry of consent orders,
to ensure that its efforts meet regulatory requirements. TGP executed a consent
order in 1994 with the EPA, governing the remediation of the relevant compressor
stations and is working with the EPA, and the relevant states regarding those
remediation activities. TGP is also working with the Pennsylvania and New York
environmental agencies regarding remediation and post-remediation activities at
the Pennsylvania and New York stations.
In November 1988, the Kentucky environmental agency filed a complaint in a
Kentucky state court alleging that TGP discharged pollutants into the waters of
the state and disposed of PCBs without a permit. The agency sought an injunction
against future discharges, an order to remediate or remove PCBs and a civil
penalty. TGP entered into agreed orders with the agency to resolve many of the
issues raised in the complaint and received water discharge permits from the
agency for its Kentucky compressor stations. The relevant Kentucky compressor
stations are being characterized and remediated under the 1994 consent order
with the EPA. Despite these remediation efforts, the agency may raise additional
technical issues or require additional remediation work in the future.
In May 1995, following negotiations with its customers, TGP filed a
stipulation and agreement with the Federal Energy Regulatory Commission (FERC)
that established a mechanism for recovering a substantial portion of the
environmental costs identified in its internal remediation project. The
stipulation and agreement was effective July 1, 1995. Refunds may be required to
the extent actual eligible expenditures are less than amounts collected.
From May 1999 to March 2001, our Coastal Eagle Point Oil Company received
several Administrative Orders and Notices of Civil Administrative Penalty
Assessment from the New Jersey Department of Environmental Protection. All of
the assessments are related to alleged noncompliances with the New Jersey Air
Pollution Control Act pertaining to excess emissions from the first quarter 1998
through the fourth quarter 2000 reported by our Eagle Point refinery in
Westville, New Jersey. The New Jersey Department of Environmental Protection has
assessed penalties totaling approximately $1.1 million for these alleged
violations. Our Eagle Point refinery has been granted an administrative hearing
on issues raised by the assessments and, currently, is in negotiations to settle
these assessments.
In February 2002, we received a Notice of Violation from the EPA alleging
noncompliance with the EPA's fuel regulations from 1996 to 1998. The notice
proposes a penalty of $165,000 for these alleged violations. We are
investigating the allegations and are preparing a response.
We have been designated and have received notice that we could be
designated, or have been asked for information to determine whether we could be
designated, as a Potentially Responsible Party (PRP) with
13
respect to 54 active sites under the Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) or state equivalents. We have sought to
resolve our liability as a PRP at these CERCLA sites, as appropriate, through
indemnification by third parties and settlements which provide for payment of
our allocable share of remediation costs. As of March 31, 2002, we have
estimated our share of the remediation costs at these sites to be between $65
million and $203 million and have provided reserves that we believe are adequate
for such costs. Since the clean-up costs are estimates and are subject to
revision as more information becomes available about the extent of remediation
required, and because in some cases we have asserted a defense to any liability,
our estimates could change. Moreover, liability under the federal CERCLA statute
is joint and several, meaning that we could be required to pay in excess of our
pro rata share of remediation costs. Our understanding of the financial strength
of other PRPs has been considered, where appropriate, in the determination of
our estimated liabilities. We presently believe that based on our existing
reserves, and information known to date, the impact of the costs associated with
these CERCLA sites will not have a material adverse effect on our financial
position, operating results or cash flows.
It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based on our evaluation and experience to date, we believe the recorded reserves
are adequate. For a further discussion of specific environmental matters, see
Legal Proceedings above.
Rates and Regulatory Matters
In April 2000, the California Public Utilities Commission (CPUC) filed a
complaint with the FERC alleging that the sale of approximately 1.2 billion
cubic feet per day of California capacity by EPNG to El Paso Merchant Energy
Company, both of whom are our wholly-owned subsidiaries, was anticompetitive and
an abuse of the affiliate relationship under the FERC's policies. Other parties
in the proceeding requested that the original complaint be set for hearing and
that Merchant Energy pay back any profits it earned under the contract. In March
2001, the FERC established a hearing, before an administrative law judge, to
address the issue of whether EPNG and/or Merchant Energy had market power and,
if so, had exercised it. In October 2001, a FERC administrative law judge issued
a proposed decision finding that El Paso did not exercise market power and that
the market power portion of the CPUC's complaint should be dismissed. The
decision further found that El Paso had violated the FERC's marketing affiliate
regulations. In October 2001, the Market Oversight and Enforcement (MOE) section
of the FERC's Office of the General Counsel filed comments in this proceeding
stating that record development at the trial was inadequate to conclude that
EPNG and Merchant Energy complied with the FERC's regulation. We filed a motion
to strike the MOE's pleading, but in December 2001, the FERC denied our motion
and remanded the proceeding to the administrative law judge for a supplemental
hearing on the availability of capacity at El Paso's California delivery points.
The hearing commenced on March 21, 2002, and concluded on April 4, 2002. Oral
argument was held on April 10, 2002, and post-hearing briefing is to be
completed by June 5, 2002.
In late 1999, several of EPNG's customers filed complaints requesting that
the FERC order us to cease and desist from selling primary firm delivery point
capacity at the Southern California Gas Company Topock delivery point in excess
of the downstream capacity available at that point and to cease and desist from
overselling firm mainline capacity on the east-end of our mainline system.
Several technical conferences and alternative dispute resolution meetings were
held during the summer of 2000 but they failed to produce a settlement. In
October 2000, the FERC ordered EPNG to make a one time allocation of available
delivery point capacity at the Southern California Gas Company Topock delivery
point among affected firm shippers, but deferred action on east-end and system
wide capacity allocation issues. In February 2001, the FERC issued an order
accepting EPNG's tariff filing affirming the results of the Topock delivery
point allocation process and directing EPNG to formulate a system wide capacity
allocation methodology to be addressed in
14
EPNG's order No. 637 proceeding. In March 2001, EPNG filed its proposed
system-wide allocation methodology with the FERC. In April 2001, the February
2001 order was appealed by a customer to the U.S. Court of Appeals for the 9th
Circuit and that appeal is pending a decision. In July 2001 and August 2001,
technical conferences were conducted by the FERC on EPNG's system-wide capacity
allocation proposal, after which the parties submitted position papers to the
FERC regarding the appropriate method for allocating receipt point capacity on
EPNG's system.
Two groups of EPNG's customers, those within California and those east of
California, have filed complaints against EPNG with the FERC. In July 2001,
twelve parties composed of California customers, natural gas producers and
natural gas marketers, filed a complaint alleging that EPNG's full requirements
contracts with its east of California customers should be converted to contracts
with specific volumetric entitlements, that EPNG should be required to expand
its interstate pipeline system and that firm shippers who experience reductions
in their nominated gas volumes should be awarded demand charge credits. Also, in
July 2001, ten parties, most of which are east of California full-requirement
contract customers, filed a complaint against EPNG with the FERC, alleging that
EPNG violated the Natural Gas Act of 1938 and breached its contractual
obligations by failing to expand its system in order to serve the needs of the
full-requirement contract shippers. The complainants have requested that the
FERC require EPNG to show cause why it should not be required to augment its
system capacity. In September 2001, the July 2001 complainants filed a motion
for partial summary disposition of their complaint, to which EPNG responded. In
addition, in November 2001, one of the complainants submitted a type of
settlement proposal that we and most other parties have opposed. At its March
13, 2002 public meeting, the FERC Staff made a presentation to the FERC
Commissioners recommending that the FERC address the capacity allocation issues
raised in these and other related EPNG proceedings, including its Order No. 637
proceeding, by, among other things, eliminating the full requirements provisions
from all of EPNG's contracts except those in a small customer category and
converting them to contracts with specific volumetric entitlements. The Staff
also recommended scheduling a technical conference. A technical conference
attended by the Commissioners was held on April 16, 2002, at which EPNG, state
commissions and customers groups presented comments. Responses to the
presentations were filed by EPNG and others on April 30, 2002.
In September 2001, the FERC issued a Notice of Proposed Rulemaking (NOPR).
The NOPR proposes to apply the standards of conduct governing the relationship
between interstate pipelines and marketing affiliates to all energy affiliates.
The proposed regulations, if adopted by the FERC, would dictate how all our
energy affiliates conduct business and interact with our interstate pipelines.
In December 2001, we filed comments with the FERC addressing our concerns with
the proposed rules. In April 2002, the FERC Staff issued a notice of a public
conference to be held on May 21, 2002, at which interested parties will be given
an opportunity to comment further on the NOPR. We cannot predict the outcome of
the NOPR, but adoption of the regulations in substantially the form proposed
would, at a minimum, place additional administrative and operational burdens on
us.
While we cannot predict with certainty the final outcome or the timing of
the resolution of all of our rates and regulatory matters discussed above, we
believe the ultimate resolution of these issues, based on information known to
date, will not have a material adverse effect on our financial position, results
of operations or cash flows.
In June 2001, the Western Australia regulators issued a draft rate decision
at lower than expected levels for the Dampier-to-Bunbury pipeline owned by EPIC
Energy Australia Trust, in which we have a 33 percent ownership interest and a
total investment, including financial guarantees, of approximately $195 million.
EPIC Energy Australia has appealed a variety of issues related to the draft
decision to the Western Australia Supreme Court. The appeal was heard at the
Western Australia Supreme Court in November 2001, and a decision from the court
is expected in the middle of 2002. If the draft decision rates are implemented,
the new rates will adversely impact future operating results, liquidity and debt
capacity, possibly reducing the value of our investment by up to $135 million.
We are engaged in arbitration proceedings with Southwestern Bell involving
disputes regarding our telecommunications interconnection agreement in our
metropolitan transport business. We anticipate a
15
determination from an administrative law judge on this proceeding by the end of
the second quarter. The Public Utilities Commission (PUC) of Texas will then
rule on the administrative law judge's recommendation, the outcome of which
could negatively impact our metro transport business. We also continue to
evaluate the impact of ongoing industry issues, including credit concerns, on
our business, which includes not only our metro business but also the operation
of a telecommunications facility that we lease under an agreement supported by a
residual value guarantee of $237 million. An adverse resolution to the
arbitration proceeding by the PUC or continual decline in the industry could
have a negative impact on our ongoing operations and prospects in this business.
Other Matters
In December 2001, Enron Corp. and a number of its subsidiaries, including
Enron North America Corp. and Enron Power Marketing, Inc., filed for Chapter 11
bankruptcy protection in the United States Bankruptcy Court for the Southern
District of New York. We had contracts with Enron North America, Enron Power
Marketing and other Enron subsidiaries for, among other things, the
transportation of natural gas and natural gas liquids, the trading of physical
gas, power, petroleum and financial derivatives. We established reserves for
potential losses related to the receivables from our transportation contracts,
as well as the positions and receivables under our marketing and trading
contracts that we believe are adequate. In addition, we have terminated most of
our trading related contracts as a result of Enron's bankruptcy filings, and are
analyzing our damage claims arising from the Enron bankruptcy proceedings.
Affiliates of Enron hold both short-term and long-term capacity on several
of our pipeline systems. While some transportation contracts between various
Enron entities with EPNG or TGP have been rejected, we are uncertain as to
Enron's intent to maintain or release capacity associated with contracts on
other El Paso pipeline entities and also Enron's ability to honor the terms of
their contracts. Future revenue related to these capacity contracts will depend
upon the outcome of Enron's bankruptcy proceedings and our pipelines' ability to
re-market or otherwise maximize the value of the rejected or released capacity.
We do not presently know the precise values that will be received by our
pipelines as a result of these efforts.
12. SEGMENT INFORMATION
We segregate our business activities into four distinct operating segments:
Pipelines, Merchant Energy, Production and Field Services. These segments are
strategic business units that provide a variety of energy products and services.
They are managed separately as each business unit requires different technology
and marketing strategies. We measure segment performance using earnings before
interest expense and income taxes (EBIT). The following are our segment results
as of and for the quarters ended March 31, 2002 and 2001:
2002
-----------------------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY PRODUCTION SERVICES OTHER(1) TOTAL
--------- -------- ---------- -------- -------- -------
(IN MILLIONS)
Revenues from external customers.......... $ 647 $12,100 $ 155 $ 274 $ 12 $13,188
Intersegment revenues..................... 56 26 395 266 (743) --
Asset impairments......................... -- 342 -- -- -- 342
Ceiling test charge....................... -- -- 33 -- -- 33
Operating income (loss)................... 345 83 173 38 (14) 625
EBIT...................................... 399 63 176 51 (5) 684
Segment assets............................ 14,437 18,203 7,791 3,635 4,491 48,557
16
2001
-----------------------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY PRODUCTION SERVICES OTHER(1) TOTAL
--------- -------- ---------- -------- -------- -------
(IN MILLIONS)
Revenues from external customers......... $ 715 $15,984 $ 239 $ 647 $ 177 $17,762
Intersegment revenues.................... 77 425 332 110 (944) --
Merger-related costs..................... 89 136 63 29 844 1,161
Operating income (loss).................. 294 169 188 20 (883) (212)
EBIT..................................... 333 258 185 36 (880) (68)
---------------
(1) Includes Corporate and eliminations as well as our telecommunications
activities. In 2001, we also included our retail businesses.
The reconciliations of EBIT to income (loss) before extraordinary items and
cumulative effect of accounting change are presented below for the quarters
ended March 31:
2002 2001
---- -----
(IN MILLIONS)
Total EBIT.................................................. $684 $ (68)
Interest and debt expense................................... 307 295
Minority interest........................................... 40 62
Income taxes................................................ 108 (35)
---- -----
Income (loss) before extraordinary items and cumulative
effect of accounting change........................... $229 $(390)
==== =====
13. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS
We hold investments in various affiliates which we account for using the
equity method of accounting. Summarized financial information of our
proportionate share of unconsolidated affiliates below includes affiliates in
which we hold a less than 50 percent interest as well as those in which we hold
a greater than 50 percent interest. Our proportional shares of the
unconsolidated affiliates in which we hold a greater than 50 percent interest
had net income of $10 million and $16 million for March 31, 2002 and 2001.
2002 2001
----- -----
(IN MILLIONS)
Operating results data
Revenues and other income................................. $471 $526
Costs and expenses........................................ $410 $390
Income from continuing operations......................... $ 51 $ 98
Net income................................................ $ 51 $ 89
Consolidation of Investments
As of December 31, 2001, we had investments in the Eagle Point Cogeneration
Partnership, in Capital District Energy Center Cogeneration Associates and in
Mohawk River Funding IV. During 2002, we obtained additional rights from our
partners in these investments and acquired an additional one percent ownership
interest in Capital District Energy Center Cogeneration Associates and Mohawk
River Funding IV. As a result of these actions, we began consolidating these
investments effective January 1, 2002.
Gemstone
In November 2001, we issued debt securities to Gemstone with a principal
balance of $462 million that carry a fixed annual interest rate of 5.25%. As of
March 31, 2002 and December 31, 2001, the outstanding balance on these
securities, plus accrued interest, was $225 million and $350 million.
In May 2002, we completed amendments to the Gemstone agreements by
eliminating any stock price and credit ratings downgrade trigger and eliminating
$950 million of mandatorily convertible preferred stock held
17
in a share trust we control. In exchange, we issued a direct guarantee
supporting Gemstone's notes in the amount of $950 million.
Chaparral
We have a credit facility with Chaparral that allows Chaparral to borrow
funds from us at a variable interest rate. The outstanding balance, plus accrued
interest, owed to us under this credit facility was $750 million and $552
million at March 31, 2002 and December 31, 2001. The interest rate on the
facility is based on LIBOR plus a margin, and was 2.4% and 2.6% at March 31,
2002 and December 31, 2001.
In April 2002, we completed amendments to the Chaparral agreements by
eliminating any stock price and credit ratings downgrade trigger and reducing
the liquidation preference value of mandatorily convertible preferred stock held
in a share trust we control to $200 million. In exchange, we issued a direct
guarantee supporting Chaparral's notes totaling approximately $1 billion.
El Paso Energy Partners
In April 2002, we sold midstream assets to El Paso Energy Partners for
total consideration of $735 million. Net proceeds were approximately $420
million in cash, a $119 million note payable to us, common units of El Paso
Energy Partners with a fair value of $6 million, and the partnership's interest
in the Prince tension leg platform including its nine percent overriding royalty
interest in the Prince production field with a combined fair value of $190
million.
14. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Accounting for Asset Retirement Obligations
In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 143, Accounting for Asset Retirement Obligations. This Statement requires
companies to record a liability relating to the retirement and removal costs of
assets used in their business. The liability is discounted to its present value,
and the related asset value is increased by the amount of the resulting
liability. Over the life of the asset, the liability will be accreted to its
future value and eventually extinguished when the asset is taken out of service.
Capitalized retirement and removal costs will be depreciated over the useful
life of the related asset. The provisions of this Statement are effective for
fiscal years beginning after June 15, 2002. We are currently evaluating the
effects of this pronouncement.
Derivatives Implementation Group Issue C-16
In September 2001, the Derivatives Implementation Group of the FASB cleared
guidance on Issue C-16, Scope Exceptions: Applying the Normal Purchases and
Normal Sales Exception to Contracts that Combine a Forward Contract and a
Purchased Option Contract. This guidance impacts the accounting for fuel supply
contracts that require delivery of a contractual minimum quantity of a fuel
other than electricity at a fixed price and have an option that permits the
holder to take specified additional amounts of fuel at the same fixed price at
various times. We use fuel supply contracts such as these in our power producing
operations and currently do not reflect them in our balance sheet since they are
considered normal purchases that are not classified as derivative instruments
under SFAS No. 133. This guidance becomes effective in the second quarter of
2002, and we will be required to account for these contracts as derivative
instruments under SFAS No. 133. We are currently evaluating the financial impact
of this guidance on our financial statements.
18
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information contained in Item 2 updates, and you should read it in
conjunction with, information disclosed in our Annual Report on Form 10-K filed
March 15, 2002, in addition to the financial statements and notes presented in
Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.
Below is a list of terms that are common to our industry and used
throughout our Management's Discussion and Analysis:
/d = per day MMBtu = million British thermal units
Bbl = barrel Mcf = thousand cubic feet
BBtu = billion British thermal units MMcf = million cubic feet
BBtue = billion British thermal unit MTons = thousand tons
equivalents MMWh = thousand megawatt hours
Btu = British thermal unit
MBbls = thousand barrels
When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl is equal to six Mcf of natural
gas. Also, when we refer to cubic feet measurements, all measurements are at
14.73 pounds per square inch.
RESULTS OF OPERATIONS
Our results of operations, along with the impact by segment of the
merger-related costs, asset impairments and other charges, are presented below
for the quarters ended March 31 (in millions):
2002 2001
------------------------------------ ------------------------------------
EBIT BY SEGMENT REPORTED CHARGES(1) PRO-FORMA(2) REPORTED CHARGES(1) PRO-FORMA(2)
------------------------------ -------- ---------- ------------ -------- ---------- ------------
Pipelines..................... $ 399 $ -- $ 399 $ 333 $ 89 $ 422
Merchant Energy............... 63 342 405 258 136 394
Production.................... 176 33 209 185 63 248
Field Services................ 51 -- 51 36 29 65
----- ----- ------ ----- ------- ------
Segment EBIT................ 689 375 1,064 812 317 1,129
Corporate and other........... (5) -- (5) (880) 844 (36)
----- ----- ------ ----- ------- ------
Consolidated EBIT........... 684 375 1,059 (68) 1,161 1,093
----- ----- ------ ----- ------- ------
Interest and debt expense..... (307) -- (307) (295) -- (295)
Minority interest............. (40) -- (40) (62) -- (62)
Income taxes.................. (108) (120) (228) 35 (271) (236)
Extraordinary items........... -- -- -- (10) 10 --
Accounting changes............ 154 (154) -- -- -- --
----- ----- ------ ----- ------- ------
Net income.................... $ 383 $ 101 $ 484 $(400) $ 900 $ 500
===== ===== ====== ===== ======= ======
---------------
(1) Charges include merger-related costs, asset impairments, a ceiling test
charge, extraordinary items and the cumulative effect of accounting change.
See Item 1. Financial Statements Notes 1, 3, 4, 5 and 6 for further
discussions of these charges.
(2) Pro-forma amounts should not be used as a substitute for amounts reported
under generally accepted accounting principles. They are presented solely to
improve the understanding of the impact of the charges reported during the
periods presented.
19
SEGMENT RESULTS
Our four segments: Pipelines, Merchant Energy, Production and Field
Services are strategic business units that offer a variety of different energy
products and services; each requires different technology and marketing
strategies. We evaluate our segment performance based on EBIT. Operating
revenues and expenses by segment include intersegment revenues and expenses
which are eliminated in consolidation. Because changes in energy commodity
prices have a similar impact on both our operating revenues and cost of products
sold from period to period, we believe that gross margin (revenue less cost of
sales) provides a more accurate and meaningful basis for analyzing operating
results for the trading and refining portions of Merchant Energy and for the
Field Services segment. For a further discussion of our individual segments, see
Item 1, Financial Statements, Note 12, as well as our Annual Report on Form 10-K
for the year ended December 31, 2001. The segment EBIT results for the quarters
ended March 31 presented below include the charges discussed above:
2002 2001
---- -----
(IN MILLIONS)
Pipelines................................................... $399 $ 333
Merchant Energy............................................. 63 258
Production.................................................. 176 185
Field Services.............................................. 51 36
---- -----
Segment total............................................. 689 812
Corporate and other, net.................................... (5) (880)
---- -----
Consolidated EBIT......................................... $684 $ (68)
==== =====
PIPELINES
Our Pipelines segment holds our interstate transmission businesses. Results
of our Pipelines segment operations were as follows for the quarters ended March
31:
2002 2001
-------- --------
(IN MILLIONS, EXCEPT
VOLUME AMOUNTS)
Operating revenues.......................................... $ 703 $ 792
Operating expenses.......................................... (358) (498)
Other income................................................ 54 39
------- -------
EBIT...................................................... $ 399 $ 333
======= =======
Throughput volumes (BBtu/d)(1)
TGP....................................................... 4,789 5,045
EPNG and MPC.............................................. 4,203 4,826
ANR....................................................... 3,779 3,938
CIG and WIC............................................... 2,789 2,431
SNG....................................................... 2,283 2,231
Equity investments (our ownership share).................. 2,693 2,286
------- -------
Total throughput.................................. 20,536 20,757
======= =======
---------------
(1) Throughput volumes for 2001 exclude those related to pipeline systems sold
in connection with FTC orders related to our Coastal merger including the
Midwestern Gas Transmission system and investments in the Empire State and
Iroquois pipelines. Throughput volumes also exclude intrasegment activities.
Operating revenues for the quarter ended March 31, 2002, were $89 million
lower than the same period in 2001. The decrease was primarily due to the impact
of lower prices on natural gas and liquids sales, including sales of natural gas
produced, resales of natural gas purchased from the Dakota gasification facility
and sales of excess natural gas. Also contributing to the decrease were lower
transportation revenues from capacity sold under short-term contracts, lower
throughput to California and other western states and to the northeast due to
milder weather in these areas in 2002, and the sale of our Midwestern Gas
Transmission system in April
20
2001. These decreases were partially offset by higher reservation revenues on
the EPNG system as a result of a larger portion of its capacity sold at maximum
tariff rates versus the same period in 2001 and revenues from SNG's Elba Island
liquefied natural gas (LNG) facility which was placed in service in December
2001.
Operating expenses for the quarter ended March 31, 2002, were $140 million
lower than the same period in 2001 primarily as a result of merger-related
charges incurred in 2001 related to our merger with Coastal. Also contributing
to the decrease were lower compressor fuel costs resulting from lower natural
gas prices, lower prices on natural gas purchased from the Dakota gasification
facility, lower operating expenses due to cost efficiencies following the merger
with Coastal and lower benefit costs in the first quarter of 2002. The decrease
was partially offset by increases to our reserve for bad debts in 2002 related
to the bankruptcy of Enron Corp.
Other income for the quarter ended March 31, 2002, was $15 million higher
than the same period in 2001 primarily due to a gain on the sale of pipeline
expansion rights in February 2002.
MERCHANT ENERGY
Our customer origination and trading activities, as well as our power,
refining, chemical and coal business activities are conducted through our
Merchant Energy segment. As part of the power operations of our Merchant Energy
segment, we engage in power contract restructuring activities. These power
contract restructurings are usually conducted through our unconsolidated
affiliate, Chaparral, or other joint ventures. However, they may also involve
restructuring of power plant facilities and related assets that are consolidated
in our financial statements, as in the case of our Eagle Point Cogeneration and
Mount Carmel restructuring transactions discussed in results of operations
below.
Power Contract Restructuring Activities
Many of our domestic power plants, and the power plants owned by Chaparral,
have long-term power sales contracts with regulated utilities that were entered
into under the Public Utility Regulatory Policies Act of 1978 (PURPA). The power
sold to the utility under these PURPA contracts is required to be delivered from
a specified power generation plant at power prices that are usually
significantly higher than the cost of power in the wholesale power market. Our
cost of generating power at these PURPA power plants is typically higher than
the cost we would incur by obtaining the power in the wholesale power market,
principally because the PURPA power plants are less efficient than newer power
generation facilities.
In a power contract restructuring, the PURPA power sales contract is
amended so that the power sold to the utility does not have to be provided from
the specific power plant. Because we are able to buy lower cost power in the
wholesale power market, we have the ability to reduce the cost paid by the
utility, thereby inducing the utility to enter into the power contract
restructuring transaction. Following the contract restructuring, the power plant
operates on a merchant basis, which means that it is no longer dedicated to one
buyer and will operate only when power prices are high enough to make operations
economical. In addition, we may assume, and in the case of Eagle Point we did
assume, the business and economic risks of supplying power to the utility to
satisfy the delivery requirements under the restructured power contract over its
term. When we assume this risk, we manage these obligations by entering into
transactions to buy power from third parties that manage our risk over the life
of the contract. These activities are reflected as part of our trading
activities and reduce our exposure to changes in power prices from period to
period. Power contract restructurings generally result in a higher return in our
power generation business because we can deliver reliable power at lower prices
than our cost to generate power at these PURPA power plants. In addition, we can
use the restructured contracts as collateral to obtain financing at a cost that
is comparable to, or lower than, our existing financing costs. The manner in
which we account for these activities is discussed in Item 1, Financial
Statements, Note 1, of this Form 10-Q/A.
Power restructuring transactions are extensively negotiated and can take a
significant amount of time to complete. In addition, there are a limited number
of facilities to which the restructuring process applies. Our ability to
successfully restructure a power plant's contracts and the future financial
benefit of that effort is difficult to determine, and may vary significantly
from period to period. Since we began these activities in
21
1999, we have completed ten restructuring transactions of varying financial
significance and will attempt to complete an additional eight to ten
transactions in the future through assets we, or Chaparral currently own.
Energy-related Price Risk Management Activities
As of March 31, 2002, the fair value of our energy contracts was $1.9
billion. Of this amount, the fair value of our trading-related energy contracts
was $995 million. Total margins generated from our trading activities during the
quarters ended March 31, 2002 and 2001 were $108 million and $291 million.
The following table details the fair value of our energy contracts by year
of maturity and valuation methodology as of March 31, 2002.
MATURITY MATURITY MATURITY MATURITY MATURITY TOTAL
LESS THAN 1 TO 3 4 TO 5 6 TO 10 BEYOND FAIR
SOURCE OF FAIR VALUE 1 YEAR YEARS YEARS YEARS 10 YEARS VALUE
-------------------- --------- -------- -------- -------- -------- ------
Trading contracts
Prices actively quoted....... $(40) $542 $260 $ 85 $ -- $ 847
Prices based on models and
other valuation methods... 91 58 21 (22) -- 148
---- ---- ---- ---- ---- ------
Total trading
contracts, net..... 51 600 281 63 -- 995
---- ---- ---- ---- ---- ------
Non-trading activities(1)
Prices actively quoted....... 141 61 (2) 141 134 475
Prices based on models and
other valuation methods... 37 77 73 142 94 423
---- ---- ---- ---- ---- ------
Total non-trading
contracts, net..... 178 138 71 283 228 898
---- ---- ---- ---- ---- ------
Total energy
contracts.......... $229 $738 $352 $346 $228 $1,893
==== ==== ==== ==== ==== ======
---------------
(1) Non-trading energy contracts include derivatives related to our oil and
natural gas producing activities of ($86) million and the balance relates to
derivatives from our power contract restructuring activities.
A reconciliation of our trading and non-trading energy contracts for the
quarter ended March 31, 2002, is as follows (in millions):
TOTAL
ENERGY
TRADING NON-TRADING CONTRACTS
------- ----------- ---------
Fair value of contracts outstanding at December 31,
2001.............................................. $1,295 $ 459 $1,754
------ ------ ------
Fair value of contracts settled during the period... (481) (177) (658)
Initial recorded value of new contracts............. 7 884(1) 891
Change in fair value of contracts................... 133 (268) (135)
Changes in fair value attributable to changes in
valuation techniques.............................. (69) -- (69)
Other............................................... 110 -- 110
------ ------ ------
Net change in contracts outstanding during the
period......................................... (300) 439 139
------ ------ ------
Fair value of contracts outstanding at March 31,
2002.............................................. $ 995 $ 898 $1,893
====== ====== ======
---------------
(1) Relates to our Eagle Point Cogeneration restructuring transaction completed
during the first quarter of 2002. See the discussion of this transaction
under results of operations below.
22
Included in "Changes in fair value attributable to changes in valuation
techniques" in our trading price risk management activities is a charge of
approximately $61 million related to our revised estimate of the fair value of
long-term trading positions. Specifically, we have recently experienced
diminished liquidity in the marketplace for natural gas and power transactions
in excess of ten years. Because we do not expect this condition to change in the
foreseeable future, we do not recognize gains from the fair value of trading or
non-trading positions beyond ten years unless there is clearly demonstrated
liquidity in a specific market.
Results of Operations
Below are Merchant Energy's operating results and an analysis of these
results for the quarters ended March 31:
2002 2001
--------- ---------
(IN MILLIONS, EXCEPT
VOLUME AMOUNTS)
Trading and refining gross margins.......................... $ 691 $ 505
Operating and other revenues................................ 196 207
Operating expenses.......................................... (804) (543)
Other income (loss)......................................... (20) 89
-------- --------
EBIT...................................................... $ 63 $ 258
======== ========
Volumes
Physical
Natural gas (BBtue/d).................................. 13,221 13,847
Power (MMWh)........................................... 105,783 36,307
Crude oil and refined products (MBbls)................. 166,842 169,237
Coal (MTons)........................................... 2,309 2,663
Financial settlements (BBtue/d)........................... 222,745 247,596
During the first quarter of 2002, we completed power restructurings at our
Eagle Point Cogeneration and Mount Carmel power plants. The Eagle Point
Cogeneration restructuring transaction was our most significant restructuring
transaction to date. In the transaction, we amended the existing PURPA power
sales contract with Public Service Electric and Gas, eliminating the requirement
to deliver power from the Eagle Point Cogeneration power plant and establishing
fixed prices (with stated increases) for delivery of power over the term of the
amended contract. From an accounting standpoint, these actions require us to
mark the contract to its fair value under SFAS No. 133. As a result, we recorded
non-cash revenue representing the estimated fair value of the derivative
contract of approximately $978 million in our first quarter results. We also
amended or terminated other ancillary agreements associated with the
cogeneration facility, such as gas supply and transportation agreements, a steam
contract and certain financing agreements, and adjusted the Eagle Point
Cogeneration facility to its fair value as a peaking merchant plant. The total
cost to terminate the transportation contract was $29 million, and we paid $103
million to the utility to terminate the original PURPA contract. We also
recorded a $98 million non-cash charge to adjust the Eagle Point Cogeneration
plant to fair value and a non-cash charge of $230 million to write off the book
value of the original PURPA contract. Based on these amounts, and including
closing and other costs, our first quarter results reflect a one time net
benefit from the Eagle Point Cogeneration restructuring transaction of $438
million. Because we retained the risks of providing power under the restructured
power contract, we then entered into transactions in the wholesale market to
manage these risks and to reduce our exposure to future price changes. Our gain
on the Eagle Point transaction does not include the costs of these risk
mitigating activities. The Mount Carmel restructuring involved the termination
of the existing PURPA power purchase contract for a fee from the utility of $50
million. In addition, we recorded a non-cash adjustment to fair value of the
Mount Carmel facility of $25 million, resulting in a total net benefit on the
restructuring transaction of $25 million.
23
Trading and refining gross margins consist of revenues from commodity
trading and origination activities less the costs of commodities sold, the
impact of power contract restructuring activities and revenues from refineries
and chemical plants, less the cost of the feedstocks used in the refining and
production processes. For the quarter ended March 31, 2002, these gross margins
were $186 million higher than the same period in 2001. The primary reason for
the increase in our trading and refining gross margins was the restructuring
gains at our Eagle Point Cogeneration and Mount Carmel facilities, which, as
discussed above, contributed margins of $463 million to our first quarter 2002
results. Partially offsetting these margins were decreases in natural gas and
power trading margins of approximately $231 million, principally resulting from
lower price volatility in the first quarter of 2002. Additionally, the first
quarter of 2002 includes a charge of $61 million as a result of a change in our
estimates of the fair value of our energy trading contracts with terms extending
beyond ten years. Also partially offsetting the increase were lower refining
margins resulting from lower spreads between the sales prices of the refined
product and the underlying feedstock cost, lower throughput at the Eagle Point
and Aruba refineries, the lease of our Corpus Christi refinery and related
assets to Valero in June 2001, and lower margins in heavy crude-based refined
products.
Operating and other revenues consist of revenues from domestic and
international power generation facilities and investments, including our
management fee from Chaparral, coal operations, and revenues from EnCap and our
other financial services businesses. For the quarter ended March 31, 2002,
operating and other revenues were $11 million lower than the same period in
2001. The decrease resulted from lower income from financial services activities
in the first quarter of 2002 as a result of the sale of several investments in
2001, and lower coal revenues in 2002 as a result of lower volumes. Also
contributing to the decrease were lower power facility revenues resulting from
the sale of power facilities to Chaparral in 2001. Partially offsetting the
decrease were higher management fees from Chaparral in the first quarter of 2002
as well as the consolidation of an international power facility in the fourth
quarter of 2001.
Operating expenses for the quarter ended March 31, 2002, were $261 million
higher than the same period in 2001. The increase was primarily a result of the
impairment of our power investments in Argentina. Also contributing to the
increase in the first quarter of 2002, were higher expenses resulting from the
consolidation of several domestic power-related entities, additional reserves
recorded related to our coal operations and a turbine forfeiture fee for a
cancelled power project. These increases were partially offset by merger-related
costs and asset impairments recorded in the first quarter of 2001 associated
with combining operations with Coastal.
Other income for the quarter ended March 31, 2002, was $109 million lower
than the same period in 2001. The decrease was primarily the result of
Chaparral's minority ownership interest in income earned on our Eagle Point
restructuring transaction, which totaled $49 million, as well as lower equity
earnings from unconsolidated projects, primarily Chaparral.
PRODUCTION
Our Production segment conducts our natural gas and oil exploration and
production activities. Results of our Production segment operations were as
follows for the quarters ended March 31:
2002 2001
--------- ---------
(IN MILLIONS, EXCEPT
VOLUMES AND PRICES)
Natural gas................................................. $ 480 $ 480
Oil, condensate and liquids................................. 82 86
Other....................................................... (12) 5
-------- --------
Total operating revenues.......................... 550 571
24
2002 2001
--------- ---------
(IN MILLIONS, EXCEPT
VOLUMES AND PRICES)
Transportation and net product costs........................ (22) (37)
-------- --------
Total operating margin............................ 528 534
Operating expenses.......................................... (355) (346)
Other income (loss)......................................... 3 (3)
-------- --------
EBIT...................................................... $ 176 $ 185
======== ========
Volumes and prices
Natural gas
Volumes (MMcf)......................................... 133,266 133,944
======== ========
Average realized prices ($/Mcf)........................ $ 3.46 $ 3.48
======== ========
Oil, condensate and liquids
Volumes (MBbls)........................................ 4,988 3,134
======== ========
Average realized prices ($/Bbl)........................ $ 15.68 $ 27.42
======== ========
Operating revenues for the quarter ended March 31, 2002, were $21 million
lower than the same period in 2001. The decrease was primarily due to a loss on
derivative positions that no longer qualify as cash flow hedges under SFAS No.
133 because they were designated as hedges of anticipated future production from
oil and gas properties that were sold in March 2002. Also contributing to the
decrease was a significant decline in average realized prices for oil,
condensate and liquids in 2002 when compared to the same period of 2001.
Transportation and net product costs for the quarter ended March 31, 2002,
were $15 million lower than the same period in 2001 primarily due to lower
transported volumes and lower costs incurred to meet minimum payments on
pipeline agreements.
Operating expenses for the quarter ended March 31, 2002, were $9 million
higher than the same period in 2001. The increase was due to higher depletion
expense in 2002 as a result of additional capital spending on assets in the full
cost pool, a non-cash full cost ceiling test charge of $33 million incurred in
the current quarter on international properties in Turkey and Brazil, higher
corporate overhead allocations and increased oilfield services costs. Partially
offsetting these increases were merger-related charges incurred in 2001 due to
our merger with Coastal in January 2001 and lower severance and other taxes in
2002, which are generally tied to natural gas and oil prices.
Other income for the quarter ended March 31, 2002, was $6 million higher
than the same period in 2001 primarily due to a gain on the sale of non-full
cost pool assets in March 2002 and lower other miscellaneous expenses.
25
FIELD SERVICES
Our Field Services segment conducts our midstream activities. Results of
our Field Services segment operations were as follows for the quarters ended
March 31:
2002 2001
-------- --------
(IN MILLIONS, EXCEPT
VOLUMES AND PRICES)
Gathering, treating and processing gross margins............ $ 125 $ 150
Operating expenses.......................................... (87) (130)
Other income................................................ 13 16
------ ------
EBIT...................................................... $ 51 $ 36
====== ======
Volumes and prices
Gathering and treating
Volumes (BBtu/d)....................................... 5,706 6,108
====== ======
Prices ($/MMBtu)....................................... $ 0.16 $ 0.14
====== ======
Processing
Volumes (inlet BBtu/d)................................. 3,969 3,892
====== ======
Prices ($/MMBtu)....................................... $ 0.11 $ 0.17
====== ======
Total gross margins for the quarter ended March 31, 2002, were $25 million
lower than the same period in 2001. The decrease was primarily a result of lower
processing and NGL marketing margins due to lower prices in 2002. Processing
margins also decreased due to lower volumes in the south Texas and Rockies
regions, changes in processing operations in the south Louisiana region and
costs associated with a new processing arrangement at the Chaco processing
facility entered into in the fourth quarter of 2001 with El Paso Energy
Partners. Gathering and treating margins were higher due to the favorable
resolution of fuel, rate and volume matters in the first quarter of 2002 and
higher realized transportation rates in 2002 from the pipeline system acquired
in our acquisition of PG&E's Texas Midstream operations in December 2000.
Partially offsetting these increases were lower natural gas prices in the San
Juan Basin in 2002.
Operating expenses for the quarter ended March 31, 2002, were $43 million
lower than the same period of 2001. The decrease was primarily due to
merger-related costs arising from payments to El Paso Energy Partners in 2001
related to FTC ordered sales of assets owned by the partnership, merger-related
employee severance and relocation expenses in 2001 following our merger with
Coastal and lower amortization of goodwill due to the implementation of SFAS No.
142 in 2002. Also contributing to the decrease were lower operations and
depreciation expenses due to our sale of transportation and fractionation assets
to El Paso Energy Partners in March 2001.
Other income for the quarter ended March 31, 2002, was $3 million lower
than the same period in 2001 primarily due to gains we recognized as a result of
not participating in the issuance of El Paso Energy Partners' common units in
March 2001, partially offset by higher earnings in 2002 from our interests in El
Paso Energy Partners.
CORPORATE AND OTHER, NET
Corporate and other expenses, which include general and administrative
activities, as well as the operations of our telecommunications and other
miscellaneous businesses, for the quarter ended March 31, 2002, were $875
million lower than the same period in 2001. The decrease was primarily a result
of merger-related charges during 2001 in connection with our January 2001 merger
with Coastal.
INTEREST AND DEBT EXPENSE
Interest and debt expense for the quarter ended March 31, 2002, was $12
million higher than the same period in 2001. The increase was a result of higher
long-term borrowings for ongoing capital projects,
26
investment programs and operating requirements and lower capitalized interest in
2002. This increase was partially offset by lower interest rates on short-term
borrowings. We anticipate interest and debt expenses will continue to exceed
last year's levels throughout the remainder of 2002.
MINORITY INTEREST
Minority interest expense for the quarter ended March 31, 2002, was $22
million lower than the same period in 2001, primarily due to lower interest
rates, partially offset by increased minority interest balances due to the
formation of Gemstone in November 2001.
INCOME TAXES
The income tax expense for the quarter ended March 31, 2002, was $108
million, resulting in an effective tax rate of 32 percent. Our effective tax
rate was different than the statutory rate of 35 percent primarily due to the
following:
- state income taxes; and
- foreign income taxed at different rates.
The income tax benefit for the quarter ended March 31, 2001, was $35
million, resulting in an effective tax rate of 8 percent. This benefit is net of
$110 million of tax expense associated with non-deductible merger charges and
changes in our estimates of additional tax liabilities. The majority of these
estimated additional liabilities were paid in 2001 and are being contested by
us. The effective tax rate excluding these charges was 34 percent. Other
differences between the effective rate and the statutory rate of 35 percent were
primarily due to the following:
- state income taxes;
- earnings from unconsolidated affiliates where we anticipate receiving
dividends; and
- foreign income taxed at different rates.
LIQUIDITY AND CAPITAL RESOURCES
GENERAL
During the first quarter of 2002, our cash and cash equivalents increased
by $120 million. During the quarter, we generated an estimated $2.1 billion
through a combination of cash-based earnings and the issuance of short and
long-term debt. In addition, we generated approximately $0.5 billion through
sales of natural gas and oil properties. From these cash inflows, we invested
approximately $1.0 billion in fixed assets and investments, paid $0.8 billion on
maturing debt issues and short-term debt, paid $0.1 billion in dividends, and
funded working capital needs of approximately $0.5 billion, principally related
to margins and option premiums in our price risk management activities. Our
operating cash flow from period to period is significantly impacted, either
positively or negatively, by movements in commodity prices. For the remainder of
2002, we expect to meet our cash investing and financing needs through cash
generated from earnings in our operating businesses and through additional
financing transactions, as needed. However, our working capital inflows or
outflows for the remainder of 2002 will be dependent on fluctuations in
commodity prices as well as strategies we may implement to offset the impact of
commodity price fluctuations on our cash flows.
CASH FROM OPERATING ACTIVITIES
Net cash provided by our operating activities was $86 million for the
quarter ended March 31, 2002, compared to net cash provided by operating
activities of $1,055 million for the same period in 2001. The decrease was
primarily due to cash paid for broker and over-the-counter margins and option
premiums in 2002, as well as less cash generated through liquidations of price
risk management assets. Our operating cash flow reductions also related to
petroleum inventory increases due to higher volumes and prices compared to
27
last year. Partially offsetting these decreases were cash payments in 2001 for
charges related to the merger with Coastal.
CASH FROM INVESTING ACTIVITIES
Net cash used in our investing activities was $343 million for the quarter
ended March 31, 2002. Our investing activities consisted primarily of additions
to property, plant and equipment, including expenditures for developmental
drilling and expansion and construction projects. Our additions to investments
consisted mostly of short-term notes from unconsolidated affiliates, primarily
related to a subsidiary of Chaparral. Cash inflows from investment-related
activities included net proceeds from the sale of natural gas and oil properties
located in east and south Texas. We also received repayments of notes related to
our unconsolidated affiliates.
CASH FROM FINANCING ACTIVITIES
Net cash provided by our financing activities was $377 million for the
quarter ended March 31, 2002. Cash provided from our financing activities
included the issuance of long-term debt, borrowings under our commercial paper
and short-term credit facilities and issuances of common stock under employee
benefit plans. We also retired long-term debt, repaid other financing
obligations, paid dividends and repaid notes to unconsolidated affiliates,
primarily related to Gemstone.
On April 30, 2002, we declared a quarterly dividend of $0.2175 per share on
our common stock, payable on July 3, 2002, to stockholders of record on June 7,
2002. Also, during the quarter ended March 31, 2002, we paid dividends of $6
million on our Series A cumulative preferred stock, which is 8 1/4% per annum
(2.0625% per quarter), on our subsidiary, El Paso Tennessee Pipeline Co.
LIQUIDITY
Our 2001 Annual Report on Form 10-K includes a detailed discussion of our
liquidity, financing activities, contractual obligations and commercial
commitments. The information presented below updates, and you should read it in
conjunction with, the information disclosed in our 2001 Annual Report on Form
10-K.
28
Financing Activities
Our significant borrowing and repayment activities during 2002 are
presented below. These amounts do not include borrowings or repayments on our
short-term financing instruments with an original maturity of three months or
less, including our commercial paper programs and short-term credit facilities.
INTEREST NET
DATE COMPANY TYPE RATE PRINCIPAL PROCEEDS(1) DUE DATE
---- ------- ---- -------- --------- ----------- --------
(IN MILLIONS)
Issuances
2002
January El Paso Medium-term notes 7.75% $1,100 $1,081 2032
February SNG Notes 8.00% 300 297 2032
April Mohawk River Senior secured notes 7.75% 92 90 2008
Funding IV
May El Paso Euro notes 7.125% 450(2) 448 2009
Retirements
2002
January SNG Long-term debt 7.85% $ 100 2002
January EPNG Long-term debt 7.75% 215 2002
March El Paso CGP Long-term debt Variable 400 2002
Jan.-Mar. El Paso Natural gas LIBOR+ 24 2002
Production production payment 0.372%
Jan.-Mar. Various Long-term debt Various 12 2002
May SNG Long-term debt 8.625% 100 2002
---------------
(1) Net proceeds were primarily used to repay maturing long-term debt,
short-term borrowings and for general corporate purposes.
(2) Represents the U.S. dollar equivalent of 500 million Euros on the issuance
date.
In February 2002, we filed a new shelf registration statement with the
Securities and Exchange Commission that allows us to issue up to $3 billion in
securities. Under this registration statement, we can issue a combination of
debt, equity and other instruments, including trust preferred securities of El
Paso Capital Trust II and El Paso Capital Trust III, trusts wholly owned by us.
If we issue securities from these trusts, we will be required to issue full and
unconditional guarantees on these securities.
Future Liquidity
In December 2001, we announced a plan to strengthen our capital structure
and enhance our balance sheet in response to changes in market conditions. Key
elements of this plan were to raise cash from sales of assets and eliminate or
renegotiate the rating triggers in our Chaparral and Gemstone investments and on
our Trinity River and Clydesdale minority interest financing transactions.
During 2002, we sold or announced the sale of natural gas and oil
properties and midstream assets which generated, or will generate upon final
closing, cash totaling approximately $1.5 billion. We expect to close these
sales by the third quarter of 2002. We expect to sell additional assets during
the remainder of 2002 to meet the goals of our plan.
In March 2002, we completed the amendments to the Trinity River agreements
removing the rating trigger that could have required us to liquidate the assets
supporting the transaction in the event we are downgraded to below investment
grade by both rating agencies. We completed amendments to the Chaparral
agreements in April 2002 and completed the amendments to the Gemstone agreements
in May 2002. We have also started the amendment process on the Clydesdale
agreements.
Notes Payable to Affiliates
Our notes payable to unconsolidated affiliates as of March 31, 2002, were
$697 million versus $872 million as of December 31, 2001. The decrease is
primarily due to the partial repayment of Gemstone debt securities.
29
Securities of Subsidiaries and Minority Interests
Total amounts outstanding for securities of subsidiaries and minority
interests were $4,184 million at March 31, 2002, versus $4,013 million at
December 31, 2001. The increase was due to the consolidation of our Eagle Point
Cogeneration Partnership and our Capital District Energy Center Cogeneration
Associates investments in January 2002.
Lines of Credit
Mesquite, a subsidiary of Chaparral and our affiliate, may borrow from us
under a line of credit facility. As of March 31, 2002, Mesquite had borrowed
$750 million under this facility at an interest rate of 2.4%.
COMMITMENTS AND CONTINGENCIES
See Item 1, Financial Statements, Note 11, which is incorporated herein by
reference.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
See Item 1, Financial Statements, Note 14, which is incorporated herein by
reference.
30
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS
We have made statements in this document that constitute forward-looking
statements, as that term is defined in the Private Securities Litigation Reform
Act of 1995. These statements are subject to risks and uncertainties.
Forward-looking statements include information concerning possible or assumed
future results of operations. These statements may relate to information or
assumptions about:
- earnings per share;
- capital and other expenditures;
- dividends;
- financing plans;
- capital structure;
- liquidity and cash flow;
- pending legal proceedings and claims, including environmental matters;
- future economic performance;
- operating income;
- management's plans; and
- goals and objectives for future operations.
Important factors that could cause actual results to differ materially from
estimates or projections contained in forward-looking statements are described
in our Annual Report on Form 10-K for the year ended December 31, 2001 and other
filings with the Securities and Exchange Commission.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There are no material changes in our quantitative and qualitative
disclosures about market risks from those reported in our Annual Report on Form
10-K for the year ended December 31, 2001, except as presented below:
COMMODITY PRICE RISK
The following table presents our potential one-day unfavorable impact on
earnings before interest and income taxes as measured by Value-at-Risk using the
historical simulation technique for our commodity and energy related contracts
and is prepared based on a confidence level of 95 percent and a one-day holding
period.
MARCH 31, DECEMBER 31,
2002 2001
--------- ------------
(IN MILLIONS)
Trading Value-at-Risk....................................... $11 $18
Non-Trading Value-at-Risk................................... $10 $15
Portfolio Value-at-Risk(1).................................. $12 $17
---------------
(1) Portfolio Value-at-Risk represents the combined Value-at-Risk for the
trading and non-trading (primarily hedging) price risk management
activities. The separate calculation of Value-at-Risk for trading and
non-trading commodity contracts ignores the natural correlation that exists
between traded and non-traded commodity contracts and prices. As a result,
the individually determined values will be higher than the combined
Value-at-Risk in most instances. We manage our risks through a portfolio
approach that balances both trading and non-trading risks.
31
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Item 1, Financial Statements, Note 11, which is incorporated
herein by reference.
The California cases are: five filed in the Superior Court of Los Angeles
County (Continental Forge Company, et al v. Southern California Gas Company, et
al, filed September 25, 2000; Berg v. Southern California Gas Company, et al;
filed December 18, 2000; County of Los Angeles v. Southern California Gas
Company, et al, filed January 8, 2002; The City of Los Angeles, et al v.
Southern California Gas Company, et al; and The City of Long Beach, et al v.
Southern California Gas Company, et al, both filed March 20, 2001); two filed in
the Superior Court of San Diego County (John W.H.K. Phillip v. El Paso Merchant
Energy; and John Phillip v. El Paso Merchant Energy, both filed December 13,
2000); three filed in the Superior Court of San Francisco County (Sweetie's, et
al v. El Paso Corporation, et al, filed March 22, 2001; Philip Hackett, et al v.
El Paso Corporation, et al, filed May 9, 2001; and California Dairies, Inc., et
al v. El Paso Corporation, et al, filed May 21, 2001); and one filed in the
Superior Court of the State of California, County of Alameda (Dry Creek
Corporation v El Paso Natural Gas Company, et al, filed December 10, 2001). The
shareholder derivative suit was filed in district court in Harris County, Texas
(Gebhardt v. Allumbaugh, et al, filed March 15, 2002).
The alleged five probable violations of the regulations of the Department
of Transportation's Office of Pipeline Safety are: 1) failure to perform
appropriate tasks to prevent corrosion, with an associated proposed fine of
$500,000; 2) failure to investigate and minimize internal corrosion, with an
associated proposed fine of $1,000,000; 3) failure to consider unusual operating
and maintenance conditions and respond appropriately, with an associated
proposed fine of $500,000; 4) failure to follow company procedures, with an
associated proposed fine of $500,000; and 5) failure to maintain topographical
diagrams, with an associated proposed fine of $25,000.
The six remaining Carlsbad lawsuits are as follows: one filed in district
court in Harris County, Texas (Geneva Smith, et al v. EPEC and EPNG, filed
October 23, 2000), and five filed in state district court in Carlsbad, New
Mexico (Chapman, as Personal Representative of the Estate of Amy Smith Heady, v.
EPEC, EPNG and John Cole, filed February 9, 2001; Chapman, as Personal
Representative of the Estate of Dustin Wayne Smith, v. EPEC, EPNG and John Cole;
Chapman, as Personal Representative of the Estate of Terry Wayne Smith, v. EPNG,
EPEC and John Cole; Rackley, as Personal Representative of the Estate of Glenda
Gail Sumler, v. EPEC, EPNG and John Cole; and Rackley, as Personal
Representative of the Estate of Amanda Sumler Smith, v. EPEC, EPNG, and John
Cole, all filed March 16, 2001). We have reached a contingent settlement in an
additional case (Dawson, as Personal Representative of Kirsten Janay Sumler, v.
EPEC and EPNG, filed November 8, 2000).
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
32
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits
Each exhibit identified below is filed as a part of this report.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
99.1 -- Certification of Financial Statements
99.2 -- Certification of Financial Statements
Undertaking
We hereby undertake, pursuant to Regulation S-K, Item 601(b),
paragraph (4)(iii), to furnish to the U.S. Securities and Exchange
Commission, upon request, all constituent instruments defining the rights
of holders of our long-term debt not filed herewith for the reason that the
total amount of securities authorized under any of such instruments does
not exceed 10 percent of our total consolidated assets.
b. Reports on Form 8-K
We filed a current report on Form 8-K, dated January 4, 2002 reporting the
Computation of the Ratio of Earnings to Fixed Charges for the five years ended
December 31, 2000 and for the nine months ended September 30, 2000 and 2001.
We filed an amended current report on Form 8-K/A, dated January 8, 2002,
correcting a typographical error appearing in the January 4, 2002 report on Form
8-K.
We filed a current report on Form 8-K dated January 11, 2002, filing
exhibits in connection with the offering of medium-term notes pursuant to a
Registration Statement on Form S-3.
We filed a current report on Form 8-K, dated March 28, 2002, to correct a
typographical error in the Report of Independent Accountants filed as an exhibit
to our Form 10-K.
We filed a current report on Form 8-K, dated April 12, 2002, announcing the
sale of Midstream assets and oil and natural gas properties.
33
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.
EL PASO CORPORATION
Date: August 8, 2002 /s/ H. BRENT AUSTIN
------------------------------------
H. Brent Austin
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: August 8, 2002 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)
34
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
99.1 -- Certification of Financial Statements
99.2 -- Certification of Financial Statements