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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
DATE OF REPORT (DATE OF EARLIEST EVENT REPORTED): MARCH 17, 2004
PLAINS EXPLORATION & PRODUCTION COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN CHARTER)
DELAWARE 33-0430755
(STATE OF INCORPORATION) (I.R.S. EMPLOYER IDENTIFICATION NO.)
001-31470
(COMMISSION FILE NO.)
700 MILAM, SUITE 3100
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
(ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (832) 239-6000
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ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND EXHIBITS.
(a) Financial Statements of Businesses Acquired.
The audited financial statements of Nuevo Energy Company, as required by
this Item 7(a), are filed with this Report:
Consolidated Statements of Income for the Years
Ended December 31, 2003, 2002 and 2001
Consolidated Balance Sheets as of December 31, 2003
and 2002
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2003, 2002 and 2001
Consolidated Statements of Stockholders' Equity for
the Years Ended December 31, 2003, 2002 and 2001
Consolidated Statements of Comprehensive Income for
the Years Ended December 31, 2003, 2002 and 2001
Notes to the Consolidated Financial Statements
Supplemental Schedule: Independent Auditors' Report
on Consolidated Financial Statement Schedule
Schedule II--Valuation and Qualifying Accounts
(b) Pro Forma Financial Information.
The following unaudited pro forma financial information of Plains
Exploration & Production Company, as required by this Item 7(b), are filed with
this Report:
Unaudited Pro Forma Combined Balance Sheet at
December 31, 2003
Unaudited Pro Forma Combined Statement of Income for
the Year Ended December 31, 2003
Notes to Unaudited Pro Forma Combined Financial
Statements
(c) Exhibits.
23.1 Consent of KPMG LLP.
INDEX TO FINANCIAL STATEMENTS
FINANCIAL STATEMENTS OF NUEVO ENERGY COMPANY
Consolidated Statements of Income for the Years
Ended December 31, 2003, 2002 and 2001 F-3
Consolidated Balance Sheets as of December 31, 2003
and 2002 F-4
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2003, 2002 and 2001 F-6
Consolidated Statements of Stockholders' Equity for
the Years Ended December 31, 2003, 2002 and 2001 F-7
Consolidated Statements of Comprehensive Income for
the Years Ended December 31, 2003, 2002 and 2001 F-8
Notes to the Consolidated Financial Statements F-9
Supplemental Schedule: Independent Auditors' Report
on Consolidated Financial Statement Schedule F-43
Schedule II--Valuation and Qualifying Accounts F-44
PRO FORMA FINANCIAL INFORMATION OF PLAINS EXPLORATION &
PRODUCTION COMPANY
Unaudited Pro Forma Combined Balance Sheet at
December 31, 2003 F-46
Unaudited Pro Forma Combined Statement of Income for
the Year Ended December 31, 2003 F-47
Notes to Unaudited Pro Forma Combined Financial
Statements F-48
F-1
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Nuevo Energy Company:
We have audited the accompanying consolidated balance sheets of Nuevo
Energy Company and subsidiaries as of December 31, 2003 and 2002, and the
related consolidated statements of income, stockholders' equity, cash flows and
comprehensive income for each of the years in the three-year period ended
December 31, 2003. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Nuevo Energy
Company and subsidiaries as of December 31, 2003 and 2002, and the results of
their operations and their cash flows for each of the years in the three-year
period ended December 31, 2003 in conformity with accounting principles
generally accepted in the United States of America.
As discussed in note 2, effective January 1, 2001, the Company changed its
method of accounting for derivative instruments. As discussed in note 3,
effective January 1, 2003, the Company changed its method of accounting for
asset retirement obligations. As discussed in note 2, effective December 31,
2003, the Company changed its method of accounting for certain convertible
subordinated debentures.
KPMG LLP
Houston, Texas
March 5, 2004
F-2
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------------
2003 2002 2001
-------- -------- --------
Revenues
Crude oil and liquids................................... $313,885 $276,494 $238,127
Natural gas............................................. 56,090 31,337 72,679
Other................................................... 1,362 4,070 273
-------- -------- --------
371,337 311,901 311,079
-------- -------- --------
Costs and Expenses
Lease operating expenses................................ 159,832 132,954 160,086
Exploration costs....................................... 2,115 4,541 22,058
Depreciation, depletion, amortization and accretion..... 70,810 73,128 70,554
Impairment of oil and gas properties.................... -- -- 103,490
General and administrative expenses..................... 28,457 25,877 36,904
Restructuring and severance charges..................... -- -- 4,859
Loss on assets held for sale............................ -- 1,253 3,494
Other................................................... 1,256 1,930 14,928
Gain on disposition of properties....................... (5,824) (16,588) (882)
-------- -------- --------
256,646 223,095 415,491
-------- -------- --------
Operating Income (Loss)..................................... 114,691 88,806 (104,412)
Derivative gain (loss).................................. (5,842) (4,746) 226
Interest income......................................... 342 266 1,311
Interest expense........................................ (29,793) (37,943) (43,006)
Loss on early extinguishment of debt.................... (12,578) -- --
Dividends on TECONS..................................... (6,613) (6,613) (6,613)
-------- -------- --------
Income (Loss) From Continuing Operations Before Income
Taxes..................................................... 60,207 39,770 (152,494)
Income Tax Expense (Benefit)
Current................................................. 2,086 1,330 --
Deferred................................................ 21,032 15,361 (61,123)
-------- -------- --------
23,118 16,691 (61,123)
-------- -------- --------
Income (Loss) From Continuing Operations.................... 37,089 23,079 (91,371)
Income (loss) from discontinued operations, including
gain/loss on disposal, net of income taxes................ 5,894 (10,804) 12,200
Cumulative effect of a change in accounting principle, net
of income taxes........................................... 8,496 -- --
-------- -------- --------
Net Income (Loss)........................................... $ 51,479 $ 12,275 $(79,171)
======== ======== ========
Earnings Per Share:
Basic
Income (Loss) from continuing operations................ $ 1.92 $ 1.31 $ (5.46)
Income (Loss) from discontinued operations, net of
income taxes........................................... 0.30 (0.61) 0.73
Cumulative effect of a change in accounting principle,
net of income tax benefit.............................. 0.44 -- --
-------- -------- --------
Net income (loss)....................................... $ 2.66 $ 0.70 $ (4.73)
======== ======== ========
Diluted
Income (Loss) from continuing operations................ $ 1.89 $ 1.30 $ (5.46)
Income (Loss) from discontinued operations, net of
income taxes........................................... 0.30 (0.61) 0.73
Cumulative effect of a change in accounting principle,
net of income tax benefit.............................. 0.43 -- --
-------- -------- --------
Net income (loss)....................................... $ 2.62 $ 0.69 $ (4.73)
======== ======== ========
Weighted Average Shares Outstanding:
Basic................................................... 19,355 17,651 16,735
======== ======== ========
Diluted................................................. 19,627 17,790 16,735
======== ======== ========
</Table>
See accompanying notes.
F-3
NUEVO ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
<Table>
<Caption>
DECEMBER 31,
----------------------
2003 2002
---------- ---------
ASSETS
Current assets
Cash and cash equivalents................................. $ 6,276 $ 5,047
Accounts receivable, net of allowance of $216 in 2003 and
$626 in 2002........................................... 39,729 40,945
Inventory................................................. 5,741 7,326
Assets held for sale...................................... 38,290 92,738
Deferred income taxes..................................... 11,906 7,683
Prepaid expenses and other................................ 4,489 3,862
---------- ---------
Total current assets................................... 106,431 157,601
---------- ---------
Property and equipment, at cost
Land...................................................... 5,224 5,224
Oil and gas properties (successful efforts method)........ 1,031,202 951,258
Gas plant and other facilities............................ 15,126 14,303
---------- ---------
1,051,552 970,785
Accumulated depreciation, depletion and amortization...... (355,311) (357,072)
---------- ---------
Total property and equipment, net...................... 696,241 613,713
---------- ---------
Deferred income taxes....................................... 17,404 43,258
Goodwill.................................................... 17,121 19,664
Other assets................................................ 7,779 20,935
---------- ---------
Total assets......................................... $ 844,976 $ 855,171
========== =========
</Table>
See accompanying notes.
F-4
NUEVO ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS -- (CONTINUED)
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
<Table>
<Caption>
DECEMBER 31,
----------------------
2003 2002
---------- ---------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable.......................................... $ 38,707 $ 34,323
Accrued interest.......................................... 3,663 5,169
Accrued drilling costs.................................... 5,568 8,035
Accrued lease operating costs............................. 13,558 15,598
Price risk management activities.......................... 35,005 20,884
Other accrued liabilities................................. 42,447 16,735
---------- ---------
Total current liabilities.............................. 138,948 100,744
---------- ---------
Long-Term debt
Senior subordinated notes................................. 225,000 409,577
Bank credit facility...................................... 15,000 28,700
Long-term liability to unconsolidated affiliate........... 115,000 --
---------- ---------
Total debt............................................. 355,000 438,277
Interest rate swaps -- fair value adjustment.............. (153) 2,161
Interest rate swaps -- termination gain................... 14,364 11,673
---------- ---------
Long-term debt......................................... 369,211 452,111
---------- ---------
Asset retirement obligation................................. 102,921 --
Price risk management activities............................ 10,512 4,198
Other long-term liabilities................................. 1,555 8,842
Company-obligated mandatorily redeemable convertible
preferred securities of Nuevo Financing I (TECONS)........ -- 115,000
Commitments and contingencies (Note 13)
Stockholders' equity
Preferred stock, $1.00 par value, 10,000,000 shares
authorized; 7% Cumulative Convertible Preferred Stock,
none issued and outstanding............................ -- --
Common stock, $0.01 par value, 50,000,000 shares
authorized, 23,151,781 and 23,048,388 shares issued and
19,682,494 and 19,110,102 shares outstanding,
respectively........................................... 232 230
Additional paid-in capital................................ 397,628 388,479
Treasury stock, at cost, 3,469,287 and 3,867,691 shares,
respectively........................................... (68,048) (75,683)
Deferred stock compensation and other..................... (6,512) (605)
Accumulated other comprehensive income.................... (24,614) (11,468)
Accumulated deficit....................................... (76,857) (126,677)
---------- ---------
Total stockholders' equity............................. 221,829 174,276
---------- ---------
Total liabilities and stockholders' equity........... $ 844,976 $ 855,171
========== =========
</Table>
See accompanying notes.
F-5
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
--------------------------------
2003 2002 2001
--------- --------- --------
Cash flows from operating activities
Net income (loss)..................................... $ 51,479 $ 12,275 $(79,171)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities
Depreciation, depletion, amortization and
accretion...................................... 70,810 73,128 70,554
Deferred income taxes............................ 21,032 15,361 (61,123)
Dry hole costs................................... 271 297 14,138
Amortization of debt financing costs............. 1,909 2,532 2,399
Loss on early extinguishment of debt............. 12,578 -- --
Impairment of oil and gas properties............. -- -- 103,490
Net gain on sales of assets...................... (5,824) (16,588) (882)
Loss on assets held for sale..................... -- 1,253 3,494
Non-cash effect of discontinued operations....... 471 30,317 13,767
Cumulative effect of a change in accounting
principle...................................... (8,496) -- --
Other............................................ 8,138 8,540 6,911
Working capital changes, net of non-cash transactions
Accounts receivable.............................. 1,780 9,341 23,043
Accounts payable................................. 7,797 (6,578) 9,876
Accrued liabilities and other.................... 3,836 (7,150) (17,602)
--------- --------- --------
Net cash provided by operating activities...... 165,781 122,728 88,894
--------- --------- --------
Cash flows from investing activities
Additions to oil and gas properties................... (61,636) (74,472) (133,228)
Acquisition of Athanor Resources, Inc................. -- (61,312) --
Acquisitions of oil and gas properties................ -- -- (28,456)
Proceeds from sales of properties..................... 85,002 26,968 6,145
Deposit received on real estate sale.................. 15,931 -- --
Other proceeds........................................ 1,841 -- --
Additions to other properties......................... (5,095) (5,698) (8,554)
--------- --------- --------
Net cash provided by (used in) investing
activities.................................. 36,043 (114,514) (164,093)
--------- --------- --------
Cash flows from financing activities
Net borrowings of credit facility..................... (13,700) (12,800) 41,500
Payments of long-term debt............................ (184,577) -- (150)
Premium paid for redemption of notes.................. (8,692) -- --
Proceeds from exercise of stock options............... 6,374 1,229 3,694
Purchase of treasury shares........................... -- -- (2,085)
Other................................................. -- 1,294 (97)
--------- --------- --------
Net cash provided by (used in) financing
activities.................................. (200,595) (10,277) 42,862
--------- --------- --------
Increase (decrease) in cash and cash equivalents........... 1,229 (2,063) (32,337)
Cash and cash equivalents
Beginning of year................................... 5,047 7,110 39,447
--------- --------- --------
End of year......................................... $ 6,276 $ 5,047 $ 7,110
========= ========= ========
</Table>
See accompanying notes.
F-6
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<Table>
<Caption>
2003 2002 2001
------------------ ------------------ ------------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
------ --------- ------ --------- ------ ---------
Common Stock
Balance, beginning of year........... 19,110 $ 230 16,880 $ 209 16,632 $ 206
Issuances and purchases of common
stock
Acquisition of Athanor Resources,
Inc. ........................... -- -- 1,970 20 -- --
Employee stock compensation and
plans........................... 572 2 260 1 376 3
Purchase of treasury stock........ -- -- -- -- (128) --
------ --------- ------ --------- ------ ---------
Balance, end of year................. 19,682 $ 232 19,110 $ 230 16,880 $ 209
------ --------- ------ --------- ------ ---------
Additional Paid-In Capital
Balance, beginning of year........... $ 388,479 $ 366,792 $ 361,643
Acquisition of Athanor Resources,
Inc. ........................... -- 20,066 --
Exercise of stock options......... 1,413 1,785 4,463
Employee stock compensation and
plans........................... 7,736 (164) 686
--------- --------- ---------
Balance, end of year................. $ 397,628 $ 388,479 $ 366,792
--------- --------- ---------
Accumulated Deficit
Balance, beginning of year........... $(126,677) $(138,952) $ (59,781)
Loss on issue of treasury
shares.......................... (1,659) -- --
Net income (loss)................. 51,479 12,275 (79,171)
--------- --------- ---------
Balance, end of year................. $ (76,857) $(126,677) $(138,952)
--------- --------- ---------
Accumulated Other Comprehensive Income
Balance, beginning of year........... $ (11,468) $ 11,534 $ --
Other comprehensive income........ (13,146) (23,002) 11,534
--------- --------- ---------
Balance, end of year................. $ (24,614) $ (11,468) $ 11,534
--------- --------- ---------
Treasury Stock
Balance, beginning of year........... $ (75,683) $ (75,855) $ (74,703)
Issuance related to employee stock
compensation and plans.......... 7,635 172 933
Purchase of treasury stock........ -- -- (2,085)
--------- --------- ---------
$ (68,048) $ (75,683) $ (75,855)
--------- --------- ---------
Deferred Compensation and Other
Balance, beginning of year........... $ (605) $ (3,821) $ (4,248)
Deferred compensation............. (5,466) 1,422 (300)
Stock acquired by benefit trust... (441) (172) (933)
Withdrawal from benefit trust..... -- 1,966 1,660
--------- --------- ---------
Balance, end of year................. $ (6,512) $ (605) $ (3,821)
--------- --------- ---------
Total Stockholders' Equity............. $ 221,829 $ 174,276 $ 159,907
========= ========= =========
</Table>
See accompanying notes.
F-7
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(IN THOUSANDS)
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------------
2003 2002 2001
-------- -------- --------
Comprehensive Income
Net income (loss)......................................... $ 51,479 $ 12,275 $(79,171)
Unrealized gains (losses) from cash flow hedging
activity:
Cumulative effect transition adjustment (net of
income tax benefit of $10,784 in 2001).......... -- -- (15,976)
Reclassification adjustment of settled contracts
(net of income taxes of $18,390 in 2003, $3,262
in 2002 and $19,202 in 2001).................... 28,523 4,753 28,446
Changes in fair value of derivative instruments
during the period (net of income tax benefit of
$26,866 in 2003, $19,049 in 2002 and $632 in
2001)........................................... (41,669) (27,755) (936)
-------- -------- --------
Other comprehensive income................... (13,146) (23,002) 11,534
-------- -------- --------
Comprehensive income................................... $ 38,333 $(10,727) $(67,637)
======== ======== ========
</Table>
See accompanying notes.
F-8
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
Nuevo Energy Company ("Nuevo") was formed as a Delaware corporation on
March 2, 1990, to acquire the businesses of certain public and private
partnerships (collectively "Predecessor Partnerships"). On July 9, 1990, the
plan of consolidation ("Plan of Consolidation") was approved by limited partners
owning a majority of units of limited partner interests in the partnerships
whereby the net assets of the Predecessor Partnerships, which were subject to
the Plan of Consolidation, were exchanged for Common Stock of Nuevo ("Common
Stock"). All references to the "Company" include Nuevo and its majority and
wholly-owned subsidiaries, unless otherwise indicated or the context indicates
otherwise.
We are engaged in the acquisition, exploitation, development, exploration
and production of crude oil and natural gas. Our principal oil and gas
properties are located domestically onshore and offshore California and West
Texas, and internationally offshore the Republic of Congo, West Africa.
We have entered into a definitive agreement to be merged with Plains
Exploration & Production Company ("Plains") in a stock transaction valued at
approximately $945 million, based on Plains' closing price on February 11, 2004.
If completed, Plains will issue up to 37.4 million shares to our stockholders
and assume $234 million of net debt (as of December 31, 2003) and $115 million
of Trust Convertible Preferred Securities. Under the terms of the transaction,
our stockholders will receive 1.765 shares of Plains' common stock for each
share of our common stock.
The transaction is expected to qualify as a tax free reorganization under
Section 368(a) and is expected to be tax free to Plains' stockholders and tax
free for the stock consideration received by our stockholders. The Boards of
Directors of both companies have approved the merger agreement and each has
recommended it to their respective stockholders for approval. Consummation of
the transaction is subject to shareholder approval from both companies and other
customary conditions.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
Our consolidated financial statements include the accounts of Nuevo and our
majority and wholly-owned subsidiaries. All significant intercompany accounts
and transactions have been eliminated in consolidation.
As a result of adopting FIN 46R, Consolidation of Variable Interest
Entities, at December 31, 2003, we are required to deconsolidate our wholly
owned Nuevo Financing I Business Trust subsidiary. See New Accounting
Pronouncements.
OIL AND GAS PROPERTIES
We use the successful efforts method to account for our investments in oil
and gas properties. Under the successful efforts method, oil and gas lease
acquisition costs and intangible drilling costs associated with exploration
efforts that result in the discovery of proved reserves and costs associated
with development drilling, whether or not successful, are capitalized when
incurred. When a proved property is sold, ceases to produce or is abandoned, a
gain or loss is recognized. When an entire interest in an unproved property is
sold for cash or cash equivalent, a gain or loss is recognized, taking into
consideration any recorded impairment. When a partial interest in an unproved
property is sold, the amount received is treated as a reduction of the cost of
the interest retained.
Costs of successful wells, development dry holes and proved leases are
capitalized and depleted on a unit-of-production basis over the remaining proved
reserves. Capitalized drilling costs are depleted on a unit-of-production basis
over the lives of the remaining proved developed reserves. See Note 3 for a
discussion of the provisions of SFAS No. 143, which was adopted effective
January 1, 2003.
F-9
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets requires that long-lived assets that are to be disposed of by sale be
measured at the lower of book value or fair value less cost to sell. The
standard also expanded the scope of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction. We adopted the provisions of this statement
effective January 1, 2002 and have presented certain property dispositions as
discontinued operations in accordance with SFAS No. 144. (See Note 5).
We review our long-lived assets to be held and used, including proved oil
and gas properties accounted for using the successful efforts method of
accounting, on a depletable unit basis whenever events or circumstances indicate
that the carrying value of those assets may not be recoverable. SFAS No. 144
requires an impairment loss to be recognized when the carrying amount of an
asset exceeds the sum of the undiscounted estimated future net cash flows and we
recognize an impairment loss equal to the difference between the carrying value
and the fair value of the asset. Fair value is estimated to be the expected
present value of future net cash flows from proved reserves, utilizing a
risk-free rate of return. Also, in accordance with SFAS No. 144, when the proved
properties are classified as held for sale, if the carrying amount of the assets
is greater than their fair market value less our estimated costs to sell them,
the difference, if significant, is recognized as a loss in that period and the
associated results of operations are accounted for as discontinued. We recorded
impairments required to be taken in 2003 and 2002 on properties designated as
assets held for sale. During 2001, we recorded an impairment totaling $103.5
million on our Santa Clara, Huntington Beach, Pitas Point, Masseko (Congo) and
Point Pedernales fields and certain other oil and gas properties.
Unproved leasehold costs are capitalized pending the results of exploration
efforts. Significant unproved leasehold costs are reviewed periodically and a
loss is recognized to the extent, if any, that the cost of the property has been
impaired. Exploration costs, including geological and geophysical expenses,
exploratory dry holes and delay rentals, are charged to expense as incurred.
Interest costs associated with non-producing leases and exploration and
development projects were capitalized only for the period that activities were
in progress to bring these projects to their intended use. The capitalization
rates were based on our weighted average cost of funds used to finance
expenditures. We capitalized $1.6 million, $1.9 million and $2.5 million of
interest costs in 2003, 2002 and 2001.
Any reference to oil and gas reserve information in the Notes to the
Consolidated Financial Statements is unaudited.
DERIVATIVE FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES
We use price risk management activities to manage non-trading market risks.
We use derivative financial instruments such as swaps, collars and put options
to hedge the impact market price risk exposures on our crude oil and natural gas
production and to mitigate our exposure to interest rate risk.
All of our derivative instruments are recognized on the balance sheet at
their fair value. We currently use swaps, collars and put options to hedge our
exposure to material changes in the future price of crude oil and natural gas
and interest rate swaps to hedge the fair value of our long-term debt.
On the date we enter into a derivative contract, we designate the
derivative as either a hedge of the fair value of a recognized asset, liability
or firm commitment ("fair value" hedge), as a hedge of the variability of cash
flows to be received or paid ("cash flow" hedge), or elect not to designate the
derivative as a hedge. Changes in the fair value of a derivative that is highly
effective as, and that is designated and qualifies as, a fair value hedge, along
with the change in fair value of the hedged asset or liability that is
attributable to the hedged risk (including losses or gains on firm commitments),
are recorded in current period earnings. Changes in the fair value of a cash
flow hedge are recorded in other comprehensive income (loss) until the
F-10
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
hedged transaction occurs. At December 31, 2003, we had cash flow hedges, fair
value hedges and derivatives not designated as a hedge. (See Note 14.)
We formally document all relationships between hedging instruments and
hedged items, as well as its risk-management objective and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated as cash flow hedges to forecasted transactions.
We also formally assess, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions. When it is
determined that a derivative is not highly effective as a hedge or that it has
ceased to be a highly effective hedge, we discontinue hedge accounting
prospectively.
When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value, and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately. In all other situations in which hedge accounting is discontinued,
the derivative will be carried at its fair value on the balance sheet, with
changes in its fair value recognized in earnings prospectively.
At December 31, 2003, we had recorded $24.6 million, net of related taxes
of $15.9 million, of cumulative hedging losses in other comprehensive income,
which will be reclassified to earnings within the next 12 months. The amounts
ultimately reclassified to earnings will vary due to changes in the fair value
of the open derivative contracts prior to settlement.
As a result of hedging transactions, oil and gas revenues were reduced by
$46.8 million, $9.4 million and $47.6 million in 2003, 2002 and 2001. The
portion of our derivative financial instruments that were ineffective or did not
qualify for hedge accounting totaled $5.8 million in 2003 and was recorded in
derivative gain/loss in the accompanying consolidated statements of income.
GOODWILL AND OTHER INTANGIBLE ASSETS
SFAS No. 142, Goodwill and Other Intangible Assets requires discontinuing
amortization of goodwill after 2001 and requires that goodwill be tested at
least annually for impairment. The impairment test requires allocating goodwill
and all other assets and liabilities to business levels referred to as reporting
units. The fair value of each reporting unit that has goodwill is determined and
compared to the book value of the reporting unit. If the fair value of the
reporting unit is less than the book value (including goodwill), then a second
test is performed to determine the amount of the impairment.
If the second test is necessary, the fair value of the reporting unit's
individual assets and liabilities is deducted from the fair value of the
reporting unit. This difference represents the implied fair value of goodwill,
which is compared to the book value of the reporting unit's goodwill. Any excess
of the book value of goodwill over the implied fair value of goodwill is the
amount of the impairment.
The goodwill impairment test is performed annually, and also at interim
dates upon the occurrence of significant events. Significant events include: a
significant adverse change in legal factors or business climate; an adverse
action or assessment by a regulator; a more-likely-than-not expectation that a
reporting unit or significant portion of a reporting unit will be sold;
significant adverse trends in current and future oil and gas prices;
nationalization of any of the Company's oil and gas properties; or, significant
increases in a reporting unit's carrying value relative to its fair value.
We recorded $17.1 million of goodwill in connection with our acquisition of
Athanor Resources, Inc. in 2002 (See Note 12). The goodwill is recorded in our
West Texas reporting unit. The annual impairment test is performed in the fourth
quarter of each year, or more often if required.
F-11
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
COMPREHENSIVE INCOME
Comprehensive income includes net income and all changes in other
comprehensive income. Changes in other comprehensive income include changes in
the fair value of derivatives designated as cash flow hedges.
ENVIRONMENTAL LIABILITIES
Environmental expenditures that relate to current or future revenues are
expensed or capitalized as appropriate. Expenditures that relate to an existing
condition caused by past operations, and do not contribute to current or future
revenue generation, are expensed. Liabilities are recorded when environmental
assessments and/or clean-ups are probable, and the costs can be reasonably
estimated. Generally, the timing of these accruals coincides with our commitment
to a formal plan of action. As of December 31, 2003, we had accrued
approximately $0.6 million for future environmental expenditures.
CONTINGENCIES
We recognize liabilities for contingencies when we have an exposure that,
when fully analyzed, indicates it is both probable and that the amount can be
reasonably estimated. Funds spent to remedy these contingencies are charged
against a reserve, if one exists, or expensed.
INVENTORY
Our inventory is valued at the lower of cost or market, with cost being
determined on a first-in, first-out (FIFO) method. We had crude oil inventory in
the Congo of $2.5 million and $3.0 million at December 31, 2003 and 2002. Our
materials and supplies inventory totaled $3.2 million and $4.3 million at
December 31, 2003 and 2002.
RECOGNITION OF CRUDE OIL AND NATURAL GAS REVENUE
Crude oil and natural gas revenue is recognized when title to the
commodities produced passes to the purchaser. We use the entitlement method for
recording sales of crude oil and natural gas from producing wells. Under the
entitlement method, revenue is recorded based on our net revenue interest in
production. Deliveries of crude oil and natural gas in excess of our net revenue
interests are recorded as liabilities and under-deliveries are recorded as
assets. Production imbalances are recorded at the lower of the sales price in
effect at the time of production or the current market value. Substantially all
such amounts are anticipated to be settled with production in future periods. At
December 31, 2003 and 2002, our imbalances were insignificant.
INCOME TAXES
Deferred income taxes are accounted for under the asset and liability
method of accounting for income taxes. Under this method, deferred income taxes
are recognized for the tax consequences of temporary differences by applying
enacted statutory tax rates applicable to future years to differences between
the financial statement carrying amounts and the tax basis of existing assets
and liabilities. The effect on deferred taxes of a change in tax rates is
recognized in income in the period the change occurs.
STATEMENTS OF CASH FLOWS
For cash flow presentation purposes, we consider all highly liquid money
market instruments with an original maturity of three months or less to be cash
equivalents. Interest paid in cash, including amounts capitalized, for 2003,
2002, and 2001 was $31.4 million, $35.4 million, and $38.3 million. Net amounts
paid (refunded) in cash for income taxes for 2003, 2002, and 2001 were $1.8
million, $(1.5) million, and $0.4 million.
F-12
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
USE OF ESTIMATES
In order to prepare these financial statements in conformity with
accounting principles generally accepted in the United States of America, our
management has made a number of estimates and assumptions relating to the
reporting of assets and liabilities and the disclosure of contingent assets and
liabilities, as well as reserve information, which affects the depletion
calculation. Actual results could differ from those estimates.
STOCK-BASED COMPENSATION
We account for stock compensation plans under the intrinsic value method of
Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to
Employees. No compensation expense is recognized for stock options that had an
exercise price equal to their market value of the underlying common stock on the
date of grant. As allowed by SFAS No. 123, Accounting for Stock-Based
Compensation, we have continued to apply APB Opinion No. 25 for purposes of
determining net income. In December 2002, the FASB issued SFAS No. 148,
Accounting for Stock-Based Compensation -- Transition and Disclosure -- an
amendment of FASB Statement No. 123 to provide alternative methods of transition
for a voluntary change to the fair value based method of accounting for
stock-based employee compensation. Additionally, the statement amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method used on reported
results. Had compensation expense for stock-based compensation been determined
based on the fair value at the date of grant, our net income and earnings per
share would have been as follows:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------------------
2003 2002 2001
---------- ---------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Net income (loss) as reported.......................... $51,479 $12,275 $(79,171)
Add:
Stock based employee compensation expense included
in reported net income, net of related income
tax............................................. 1,079 755 310
Deduct:
Total stock based employee compensation expense
determined under fair value based method for all
awards, net of related income tax............... (2,115) (4,777) (4,316)
------- ------- --------
Pro forma net income (loss)............................ $50,443 $ 8,253 $(83,177)
======= ======= ========
Earnings per share:
Basic -- as reported............................ $ 2.66 $ 0.70 $ (4.73)
Basic -- pro forma.............................. 2.61 0.47 (4.97)
Diluted -- as reported.......................... 2.62 0.69 (4.73)
Diluted -- pro forma............................ 2.57 0.46 (4.97)
</Table>
The weighted-average fair value of options granted during 2003, 2002 and
2001 was $9.87, $8.20 and $6.23. The fair value of each option grant is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following weighted-average assumptions: expected stock price volatility of
44.5% in 2003 and 2002 and 54.5% in 2001; risk free interest of 4% in 2003, 2002
and 2001; and average expected option lives of eight years in 2003 and 2002 and
three years in 2001.
We granted 372,574, 25,465 and 47,520 shares of restricted stock in 2003,
2002 and 2001. The weighted-average fair value of restricted common stock
granted during 2003, 2002 and 2001 was $19.15, $13.99 and $14.43, respectively.
F-13
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FUNCTIONAL CURRENCY
Our functional currency for all operations is the U.S. dollar.
RECLASSIFICATIONS
Certain reclassifications of prior period amounts have been made to conform
to the current presentation. The unaudited quarterly data footnote (Note 17)
also reflects reclassifications to conform with current presentation. These
reclassifications had no effect on net income or earnings per share.
NEW ACCOUNTING PRONOUNCEMENTS
Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity. In May 2003, the FASB issued SFAS No. 150, Accounting
for Certain Financial Instruments with Characteristics of both Liabilities and
Equity. SFAS No. 150 establishes standards for how an issuer classifies and
measures three classes of freestanding financial instruments (mandatorily
redeemable instruments, instruments with repurchase obligations, instruments
with obligations to issue a variable number of shares) with characteristics of
both liabilities and equity. Instruments within the scope of the statement must
be classified as liabilities on the balance sheet. SFAS No. 150 was effective
for all freestanding financial instruments entered into or modified after May
31, 2003, and otherwise was effective at the beginning of the first interim
period beginning after June 15, 2003. We have not entered into any financial
instruments within the scope of SFAS No. 150 since May 31, 2003, nor do we
currently hold any significant financial instruments within the scope. SFAS No.
150 does not apply to convertible bonds, consequently our TECONS are not within
the scope of SFAS No. 150.
Guarantor's Accounting and Disclosure Requirements. The FASB issued
Interpretation No. 45 ("FIN 45"), Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of the Indebtedness
of Others, in November 2002, which clarifies the requirements of SFAS No. 5,
Accounting for Contingencies, relating to a guarantor's accounting for and
disclosures of certain guarantees issued. FIN 45 requires enhanced disclosures
for certain guarantees. It also requires that certain guarantees issued or
modified after December 31, 2002, including certain third-party guarantees, be
recorded initially on the balance sheet at fair value. For guarantees issued on
or before December 31, 2002, liabilities are recorded when and if payments
become probable and estimable. We adopted FIN 45 effective January 1, 2003, and
have included the disclosure requirements of FIN 45 in Note 13 to the
consolidated financial statements. The adoption of FIN 45 had no effect on our
consolidated financial position, results of operations or cash flows.
Consolidation of Variable Interest Entities. In December 2003, the FASB
issued Interpretation No. 46 (revised December 2003), ("FIN 46R"), Consolidation
of Variable Interest Entities ("VIE's"), replacing Interpretation No. 46 ("FIN
46"), Consolidation of Variable Interest Entities, an interpretation of
Accounting Research Bulletin No. 51, issued in January 2003. FIN 46R was issued
to replace FIN 46 and to provide clarification of key terms, additional
exemptions for application and an extended initial application period. FIN 46R
requires certain VIEs be consolidated by the primary beneficiary of the entity
if the equity investors in the entity do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. FIN 46 was effective for all VIEs created or
acquired after January 31, 2003. For VIEs created or acquired prior to February
1, 2003, the provisions of FIN 46 was required to be applied for the first
interim or annual period beginning after June 15, 2003. We had no contractual
relationship or other business relationship with a variable interest entity and
therefore the adoption of FIN 46 had no effect on our consolidated financial
position, results of operations or cash flows.
We adopted FIN 46R on December 31, 2003. As a result of adopting FIN 46R,
we were required to deconsolidate our Nuevo Financing I business trust and our
TECONS. Accordingly, our 5 3/4% Convertible
F-14
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Subordinated Debentures due December 15, 2026, have been included in long-term
liabilities as a long-term liability to an unconsolidated affiliate at December
31, 2003. Beginning in 2004, dividends on the TECONS will no longer be reported
in our results of operations; instead, we will be reflecting the dividends as
interest expense on the income statement.
The FASB issued SFAS No. 141, Business Combinations, and SFAS No. 142,
Goodwill and Other Intangible Assets in June 2001. We adopted the provisions of
these statements on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141
requires all business combinations initiated after June 30, 2001 to be accounted
for using the purchase method. SFAS No. 142 addresses accounting and reporting
of acquired goodwill and other intangible assets. This statement requires that,
at a minimum, all intangible assets be aggregated and presented as a separate
line item on the balance sheet. A reporting issue has arisen regarding the
application of certain provisions of SFAS No. 141 and SFAS No. 142 for companies
in the extractive industries, including oil and gas companies. The issue is
whether SFAS No. 142 requires registrants to classify the costs of mineral
rights associated with extracting oil and gas as intangible assets in the
balance sheet, apart from other capitalized oil and gas property costs, and to
provide specific footnote disclosures.
The Emerging Issues Task Force has added the treatment of oil and gas
mineral rights to an upcoming agenda which may result in a change in how we are
currently classifying these costs. Historically, we have included the costs of
mineral rights associated with extracting oil and gas as a component of oil and
gas properties pursuant to the provisions of SFAS No. 19, Financial Accounting
and Reporting by Oil and Gas Companies. If it is ultimately determined that SFAS
No. 142 requires these costs to be classified as a separate intangible asset
line item on the balance sheet, we would be required to reclassify approximately
$95 million and $101 million at December 31, 2003 and December 31, 2002,
respectively, out of oil and gas properties into a separate intangible assets
line item on the balance sheet. To calculate these amounts, we deducted our
estimate of the fair value of tangible oil and gas equipment acquired in the
merger with Athanor Resources, Inc. in 2002 from the amount of the purchase
price allocated to property, plant and equipment. Our results of operations
would not be affected since such intangible assets would continue to be depleted
and assessed for impairment in accordance with successful efforts accounting
rules. The classification of these costs as intangible assets would not have any
impact on our compliance with the covenants under our debt agreements.
3. ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, Accounting for Asset Retirement Obligations requires a
liability to be recorded relating to the eventual retirement and removal of
assets used in our business. The liability is discounted to its present value,
with a corresponding increase to the related asset value. 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. We adopted the provisions
of SFAS No. 143 on January 1, 2003 to record our asset retirement obligation to
plug and abandon oil and gas wells, offshore platforms and facilities. In
connection with the initial application of SFAS No. 143, we recorded a
cumulative effect of change in accounting principle, net of taxes, of $8.5
million as an increase to net income. In addition, we recorded an asset
retirement obligation for oil and gas properties and equipment
F-15
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of $92.7 million. The following table rolls forward our asset retirement
obligation in accordance with the provisions of SFAS No. 143:
<Table>
<Caption>
YEAR ENDED
DECEMBER 31, 2003
-----------------
(IN THOUSANDS)
Beginning asset retirement obligation....................... $ 92,680
Liabilities incurred during period(1)....................... 2,643
Liabilities settled during period........................... (1,159)
Accretion expense........................................... 9,089
Revisions................................................... (332)
--------
Ending asset retirement obligation.......................... $102,921
========
</Table>
- ---------------
(1) Consists of $2.4 million related to acquisitions and $0.2 million associated
with new domestic wells drilled.
The following table summarizes the pro forma basis as required by SFAS No.
143, had we adopted the provisions of SFAS No. 143 prior to January 1, 2003:
<Table>
<Caption>
PRO FORMA ASSET
ADOPTION DATE RETIREMENT OBLIGATION
- ------------- ---------------------
(IN THOUSANDS)
December 31, 2002........................................... $92,680
December 31, 2001........................................... 84,182
January 1, 2001............................................. 76,461
</Table>
In addition, pro forma net income and earnings per share for the years
ended December 31, 2002 and 2001 for the change in accounting had SFAS No. 143
been implemented during these periods would have been as follows:
<Table>
<Caption>
2002 2001
--------- ----------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
Net income (loss)
As reported............................................... $12,275 $(79,171)
Pro forma................................................. 14,799 (75,607)
Net income (loss) per share -- reported
Basic..................................................... 0.70 (4.73)
Diluted................................................... 0.69 (4.73)
Net income (loss) per share -- pro forma
Basic..................................................... 0.84 (4.52)
Diluted................................................... 0.83 (4.52)
</Table>
4. EARNINGS PER SHARE
EPS COMPUTATION
SFAS No. 128, Earnings per Share, requires a reconciliation of the
numerator (income) and denominator (shares) of the basic EPS computation to the
numerator and denominator of the diluted EPS computation. In 2001, the weighted
average shares held by benefit trust of 145,000 are not included in the
calculation of diluted loss per share due to their anti-dilutive effect. In
2001, stock options were excluded from the calculation of diluted loss per share
due to their anti-dilutive effect. We had 0.9 million and 2.1 million
F-16
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
stock options in 2003 and 2002 which were not included in the calculation of
diluted earnings per share because the option exercise price exceeded the
average market price. We also have 2.3 million Term Convertible Securities,
Series A ("TECONS') that were not included in the calculation of diluted
earnings (loss) per share in 2003, 2002 or 2001 due to their anti-dilutive
effect. The reconciliation is as follows:
<Table>
<Caption>
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------------------------------
2003 2002 2001
---------------- ---------------- -----------------
NET COMMON NET COMMON NET COMMON
INCOME SHARES INCOME SHARES LOSS SHARES
------- ------ ------- ------ -------- ------
(IN THOUSANDS)
Income (loss) before cumulative
effect available for Common
shares -- Basic................... $42,983 19,355 $12,275 17,651 $(79,171) 16,735
Effect of dilutive securities:
Stock options..................... -- 146 -- 52 -- --
Restricted stock.................. -- 126 -- 24 -- --
Shares held by Benefit Trust...... -- -- (8) 63 -- --
------- ------ ------- ------ -------- ------
Income (loss) before cumulative
effect available for Common
shares -- Diluted................. $42,983 19,627 $12,267 17,790 $(79,171) 16,735
======= ====== ======= ====== ======== ======
</Table>
5. DISCONTINUED OPERATIONS
We sold our Eastern properties located in Texas, Alabama and Louisiana in
2002 and sold our Brea-Olinda, Union Island and Orcutt Hill oil and gas
properties located in California in 2003. The historical results of operations
of these properties are classified as discontinued operations in our statements
of income. The following table reflects revenue, gain/loss on disposition and
pre-tax income for the periods presented:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
----------------------------
2003 2002 2001
------- -------- -------
(IN THOUSANDS)
Brea-Olinda
Revenue.............................................. $ 3,246 $ 16,390 $18,005
Loss on disposition.................................. (31) (30,466) --
Pre-tax income (loss)................................ 2,675 (22,465) 7,731
Union Island
Revenue.............................................. 1,575 2,431 7,189
Gain on disposition.................................. 7,889 -- --
Pre-tax income....................................... 9,302 1,518 5,799
Orcutt Hill
Revenue.............................................. 6,609 8,724 9,039
Loss on disposition.................................. (4,578) -- --
Pre-tax income (loss)................................ (1,662) 2,389 2,229
Eastern Properties
Revenue.............................................. -- 3,216 8,330
Loss on disposition.................................. -- (1,045) --
Pre-tax income (loss)................................ -- (157) 4,607
</Table>
F-17
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. ACCOUNTS RECEIVABLE
Our accounts receivable and allowance for doubtful accounts consisted of
the following at December 31:
<Table>
<Caption>
2003 2002
------- -------
(IN THOUSANDS)
Oil and gas sales........................................... $32,604 $31,551
Joint interest billings..................................... 2,584 4,070
Other....................................................... 4,541 5,324
------- -------
$39,729 $40,945
======= =======
Allowance for doubtful accounts............................. $ 216 $ 626
======= =======
</Table>
7. STOCKHOLDERS' EQUITY
COMMON AND PREFERRED STOCK
Our Certificate of Incorporation authorizes the issuance of up to 50
million shares of Common Stock and 10 million shares of Preferred Stock, the
terms, preferences, rights and restrictions of which are established by our
Board of Directors. All shares of Common Stock have equal voting rights of one
vote per share on all matters to be voted upon by stockholders. Cumulative
voting for the election of directors is not permitted. Certain restrictions
contained in our loan agreements limit the amount of dividends that may be
declared. Under the terms of the most restrictive covenant in our indenture for
the 9 1/2% Senior Subordinated Notes due 2008 described in Note 9, we and our
restricted subsidiaries had $20.5 million available for the payment of dividends
and share repurchases at December 31, 2003. We have not paid dividends on our
Common Stock and do not anticipate the payment of cash dividends in the
immediate future.
TREASURY STOCK REPURCHASES
Our Board of Directors has authorized the open market repurchase of up to
5.6 million shares of common stock. Repurchases may be made at times and at
prices deemed appropriate by management and consistent with the authorization of
our Board. There were no shares repurchased during 2003. As of December 31,
2003, we had 3.5 million shares of treasury stock.
SHAREHOLDER RIGHTS PLAN
In 1997, we adopted a Shareholder Rights Plan to protect our shareholders
from coercive or unfair takeover tactics. Under the Shareholder Rights Plan,
each outstanding share and each share of subsequently issued common stock has
attached to it one Right. Generally, in the event a person or group ("Acquiring
Person") acquires or announces an intention to acquire beneficial ownership of
15% or more of the outstanding shares of common stock without our prior consent,
or we are acquired in a merger or other business combination, or 50% or more of
our assets or earning power is sold, each holder of a Right will have the right
to receive, upon exercise of the Right, that number of shares of common stock of
the acquiring company, which at the time of such transaction will have a market
price of two times the exercise price of the Right. We may redeem the Right for
$.01 at any time before a person or group becomes an Acquiring Person without
prior approval. The Rights will expire on March 21, 2007, subject to earlier
redemption by us.
In 2000, we amended the Shareholder Rights Plan to provide that if we
receive and consummate a transaction pursuant to a qualifying offer, the
provisions of the Shareholder Rights Plan are not triggered. In general, a
qualifying offer is an all cash, fully-funded tender offer for all outstanding
common shares by a person who, at the commencement of the offer, beneficially
owns less than five percent of the outstanding common shares. A qualifying offer
must remain open for at least 120 days, must be conditioned on the person
F-18
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
commencing the qualifying offer acquiring at least 75% of the outstanding common
shares and the per share consideration must exceed the greater of (1) 135% of
the highest closing price of the common shares during the one-year period prior
to the commencement of the qualifying offer or (2) 150% of the average closing
price of the common shares during the 20 day period prior to the commencement of
the qualifying offer.
In February 2004, the Board of Directors approved the amendment of the plan
to permit a merger with Plains without triggering the provisions of the plan.
EXECUTIVE COMPENSATION PLAN
In 1997, we adopted a plan to encourage senior executives to personally
invest in our stock, and to regularly review executives' ownership versus
targeted ownership objectives. These incentives include a deferred compensation
plan (the "Plan") that gives key executives the ability to defer all or a
portion of their salaries and bonuses and invest in our common stock or make
other investments at the employee's discretion. The Plan was amended in 2003 to
offer a 15% discount on investments in our common stock up to $30,000 annually.
Stock is held in a benefit trust and stock acquired at a discount is restricted
for a two-year period. Target levels of ownership are based on multiples of base
salary and are administered by the Compensation Committee of the Board of
Directors. Upon withdrawal from the Plan, the obligation to the employee is
settled with the invested assets. The Plan applies to certain highly compensated
employees and all executives at a level of Vice-President and above. The stock
held in the benefit trust (99,369 shares, 70,595 shares and 122,995 shares at
December 31, 2003, 2002 and 2001) was accounted for as a liability at market
value, with any changes in market value charged or credited to general and
administrative expense until July 2002. Using this approach, we recorded a net
benefit of $0.2 million in 2001 related to deferred compensation. In July 2002,
the Plan was further amended to remove the right to receive withdrawals in cash
resulting in a reclassification of the $1.1 million liability into shareholders'
equity. The deferred compensation obligation is now classified in shareholders'
equity and changes in the fair value of the obligation are not recognized.
DIRECTOR COMPENSATION
Non-employee directors may elect to receive all or part of an annual cash
retainer of $30,000 in restricted shares of our Common Stock at a 33% increase
in value. The election must be made in increments of 25% ($7,500). Therefore,
for each $7,500 of compensation for which the election is exercised, the
director would receive $9,975 in restricted stock. Beginning in 2003, each
non-employee director also receives a semi-annual grant of 2,125 restricted
shares of our common stock. All restricted shares are subject to a three-year
restricted period. Directors have the option of deferring delivery of restricted
shares beyond the three-year period. Directors also receive $1,000 for each
committee meeting attended while committee chairpersons receive $1,500.
Directors may also elect to receive restricted shares for committee meetings at
a 33% discount.
STOCK INCENTIVE PLANS
In 1990, we established the 1990 Stock Option Plan; in 1993, the Board of
Directors adopted the Nuevo Energy Company 1993 Stock Incentive Plan; and in
1999, the Board of Directors adopted the Nuevo Energy Company 1999 Stock
Incentive Plan (collectively, the "Stock Incentive Plans"). In 2001, the Board
of Directors adopted the 2001 Stock Incentive Plan as well as individual
incentive plans to induce Janet F. Clark, our former Senior Vice President and
Chief Financial Officer and George B. Nilsen, our Senior Vice President,
Planning and Asset Management to accept employment with us. The purpose of the
Stock Incentive Plans is to provide our directors and key employees with
performance incentives and to provide a means of encouraging these individuals
to own our stock.
In November 2002, the Compensation Committee of the Board of Directors
approved an increase of 250,000 shares under the 2001 Stock Incentive Plan,
increasing the total maximum number of incentive shares available under the
Stock Incentive Plans to 5,250,000 shares. Options or Restricted Shares are
granted
F-19
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
under the Stock Incentive Plans on the basis of the grantee's contribution to
us. No option may exceed a term of more than ten years. Options granted under
the Stock Incentive Plans may be either incentive stock options or options that
do not qualify as incentive stock options. Our Compensation Committee is
authorized to designate the recipients of options, the dates of grants, the
number of shares subject to options, the option price, the terms of payment upon
exercise of the options, and the time during which the options may be exercised.
Options for officers vest over a term of one to three years, as specified by the
Compensation Committee. Officers who have met their targeted stock ownership
requirement receive accelerated vesting on all options issued prior to October
15, 2001. The Company granted 10,500 options in 2003 and all the remaining
incentive grants were made in the form of Restricted Shares.
The following table details the summary of activity in the stock option
plans during the three years ended 2003:
<Table>
<Caption>
WEIGHTED-
AVERAGE
OPTIONS EXERCISE PRICE
--------- --------------
Outstanding at January 1, 2001.............................. 2,772,918 $21.94
Granted................................................... 875,026 15.51
Exercised................................................. (287,000) 12.93
Canceled.................................................. (102,525) 33.88
--------- ------
Outstanding at December 31, 2001............................ 3,258,419 20.62
Granted................................................... 487,750 14.79
Exercised................................................. (105,675) 11.99
Canceled.................................................. (938,245) 29.13
--------- ------
Outstanding at December 31, 2002............................ 2,702,249 16.96
Granted................................................... 10,500 16.12
Exercised................................................. (408,328) 15.61
Canceled.................................................. (390,031) 15.77
--------- ------
Outstanding at December 31, 2003............................ 1,914,390 17.49
========= ======
</Table>
We had options exercisable of 1,560,730 (weighted average exercise price of
$18.01), 2,053,416 (weighted average exercise price of $17.89) and 2,728,494
(weighted average exercise price of $21.80) at December 31, 2003, 2002 and 2001.
Detail of stock options outstanding and options exercisable at December 31, 2003
follows:
<Table>
<Caption>
OUTSTANDING
------------------------------------------------- EXERCISABLE
WEIGHTED- AVERAGE -----------------------------
REMAINING LIFE WEIGHTED- AVERAGE WEIGHTED- AVERAGE
RANGE OF EXERCISE PRICES NUMBER (YEARS) EXERCISE PRICE NUMBER EXERCISE PRICE
- ------------------------ --------- ----------------- ----------------- --------- -----------------
$10.31 to $15.42....... 895,065 7.68 $13.66 609,571 $13.09
$15.50 to $19.12....... 739,525 5.64 16.82 671,359 16.84
$20.38 to $29.88....... 149,800 2.09 25.02 149,800 25.02
$34.00 to $47.88....... 130,000 3.80 38.99 130,000 38.99
--------- ---------
1,914,390 1,560,730
========= =========
</Table>
F-20
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. COMPANY-OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED SECURITIES OF
NUEVO FINANCING I
On December 23, 1996, the Company and Nuevo Financing I, a statutory
business trust formed under the laws of the state of Delaware and wholly owned
by us, (the "Trust"), closed the offering of 2.3 million TECONS on behalf of the
Trust. The price to the public was $50.00 per TECONS. Distributions began to
accumulate from December 23, 1996, and are payable quarterly on March 15, June
15, September 15, and December 15, at an annual rate of $2.875 per TECONS. Each
TECONS is convertible at any time prior to the close of business on December 15,
2026, at the option of the holder into shares of common stock at the rate of
0.8421 shares of common stock for each TECONS, subject to adjustment. The sole
asset of the Trust as the obligor on the TECONS is $118.6 million aggregate
principal amount of 5 3/4% Convertible Subordinated Debentures ("Debentures") of
the Company due December 15, 2026. The Debentures were issued by us to the Trust
to facilitate the offering of the TECONS. The TECONS must be redeemed for $50.00
per TECONS plus accrued and unpaid dividends on December 15, 2026. We own the
Trust Common Securities which have an aggregate liquidation value of 3% of the
total capital of the Trust. We will receive this amount from the Trust upon
liquidation. We guarantee the Trust's obligations under the TECONS.
The balance sheet of the Trust at December 31, 2003 (dollars in thousands) is as
follows:
<Table>
Receivable from Nuevo Energy Company........................ $118,557
--------
Total Assets................................................ $118,557
========
TECONS...................................................... $115,000
Trust Common Securities owned by Nuevo Energy Company....... 3,557
--------
Total Liabilities and Equity................................ $118,557
========
</Table>
We offset the Trust Common Securities against the balance in the receivable
as we will receive the liquidation value of the Trust Common Securities.
The Trust pays interest on the $115.0 million and receives interest on
$118.6 million due from Nuevo Energy Company. The excess interest income
received will be paid to us as the owner of the Trust Common Securities.
As a result of adopting FIN 46R, Consolidation of Variable Interest
Entities, at December 31, 2003, we were required to deconsolidate our Nuevo
Financing I Business Trust. See Note 2.
F-21
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. LONG-TERM DEBT
Our long-term debt consisted of the following:
<Table>
<Caption>
DECEMBER 31,
-------------------
2003 2002
-------- --------
(IN THOUSANDS)
9 3/8% Senior Subordinated Notes due 2010................... $150,000 $150,000
9 1/2% Senior Subordinated Notes due 2008(1)................ 75,000 257,210
9 1/2% Senior Subordinated Notes due 2006................... -- 2,367
Long-term liability to unconsolidated affiliate............. 115,000 --
Bank credit facility (2.02% at December 31, 2003 and 3.11%
at December 31, 2002)..................................... 15,000 28,700
-------- --------
Total debt................................................ 355,000 438,277
Interest rate swaps -- fair value adjustment................ (153) 2,161
Interest rate swaps -- termination gain..................... 14,364 11,673
-------- --------
Long-term debt.............................................. $369,211 $452,111
======== ========
</Table>
- ---------------
(1) Redeemed February 27, 2004.
9 3/8% NOTES DUE 2010
On September 26, 2000, we issued $150.0 million of 9 3/8% Senior
Subordinated Notes due October 1, 2010. Interest accrues at 9 3/8% per annum and
is payable semi-annually in arrears on April 1 and October 1. The Notes are
redeemable, in whole or in part, at our option, on or after October 1, 2005,
under certain conditions. We are not required to make mandatory redemption or
sinking fund payments with respect to these Notes. The indenture contains
covenants that, among other things, limit our ability to incur additional
indebtedness, limit restricted payments, limit issuances and sales of capital
stock by restricted subsidiaries, limit dispositions of proceeds from asset
sales, limit dividends and other payment restrictions affecting restricted
subsidiaries, and restrict mergers, consolidations or sales of assets. The Notes
are unsecured general obligations, and are subordinated in right of payment to
all existing and future senior indebtedness. In the event of a defined change in
control, we will be required to make an offer to repurchase all outstanding
9 3/8% Notes at 101% of the principal amount, plus accrued and unpaid interest
to the date of redemption.
9 1/2% NOTES DUE 2008
In July 1999, we authorized a new issuance of $260.0 million of 9 1/2%
Senior Subordinated Notes due June 1, 2008. In August 1999, we exchanged $157.5
million of our 9 1/2% Notes due 2006 and $99.9 million of our 8 7/8% Senior
Subordinated Notes due 2008. In connection with the exchange offers, we
solicited consents to proposed amendments to the indentures under which the
exchanged notes were issued. The exchange was accounted for as a debt
modification and the consideration we paid to the holders of the exchanged
9 1/2% Notes due 2006 was $4.7 million and was accounted for as deferred
financing costs.
Interest on these Notes accrues at the rate of 9 1/2% per annum and is
payable semi-annually in arrears on June 1 and December 1. These Notes are
redeemable, in whole or in part, at our option, on or after June 1, 2003, under
certain conditions. In 2003, we redeemed $182.2 million of these notes at
104.75% of the principal amount plus accrued and unpaid interest. We recorded a
$12.6 million loss on early extinguishment of debt consisting of an $8.7 million
call premium and a $3.9 million write-off of deferred financing costs. We are
not required to make mandatory redemption or sinking fund payments on these
Notes. The indenture contains covenants that, among other things, limit our
ability to incur additional indebtedness, limit restricted
F-22
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
payments, limit issuances and sales of capital stock by restricted subsidiaries,
limit dispositions of proceeds from asset sales, limit dividends and other
payment restrictions affecting restricted subsidiaries, and restrict mergers,
consolidations or sales of assets. The 9 1/2% Notes are unsecured general
obligations, and are subordinated in right of payment to all of our existing and
future senior indebtedness. In the event of a defined change in control, we will
be required to make an offer to repurchase all outstanding Notes at 101% of the
principal amount, plus accrued and unpaid interest to the date of redemption. In
February 2004, we redeemed in full the remaining $75.0 million of these Notes at
104.75% of the principal amount plus accrued and unpaid interest.
9 1/2% NOTES DUE 2006
In April 1996, we issued $160.0 million of 9 1/2% Notes and in August 1999,
we exchanged $157.5 million of these Notes for 9 1/2% Notes due 2008 and have
repurchased some of the Notes in the open market. Interest on these Notes
accrues at the rate of 9 1/2% per annum and is payable semi-annually in arrears
on April 15 and October 15 and were redeemable, in whole or in part, at our
option, on or after April 15, 2001, under certain conditions. The Notes are
unsecured general obligations, and are subordinated in right of payment to all
existing and future senior indebtedness. In April 2003, we redeemed in full the
remaining $2.4 million of these Notes at 101.58% of the principal amount plus
accrued and unpaid interest.
LONG-TERM LIABILITY TO UNCONSOLIDATED AFFILIATE
In December 1996, we issued $115.0 million of 5 3/4% Convertible
Subordinated Debentures due December 15, 2026, to Nuevo Financing I business
trust to facilitate the offering of the TECONS in December 1996. Interest on
these Debentures accrues at 5 3/4% per annum and is payable quarterly on March
15, June 15, September 15 and December 15. The Debentures are redeemable, in
whole or in part, at our option, upon not less than 30 or more than 60 days
notice, on or after December 15, 1999, under certain conditions. We are required
to redeem the Debentures at 100% in the event the tax or legal structure changes
as defined in the agreement. The holder of the Debentures has the right,
exercisable at any time prior to close of business on December 15, 2026, to
convert the principal amount into shares of our common stock at a conversion
rate of 0.8421 shares for each Debenture, subject to adjustment under certain
circumstances. We are not required to make sinking fund payments with respect to
the Debentures.
INTEREST RATE SWAPS
We entered into interest rate swaps in 2003, 2002 and 2001. (See Note 14.)
BANK CREDIT FACILITY
Our Third Amended and Restated Credit Agreement, dated June 7, 2000, as
amended, provides for secured revolving credit availability of up to $250
million and issuance of letters of credit from a bank group led by Bank of
America, N.A., Bank One, NA, and Bank of Montreal until its expiration on June
7, 2005. At December 31, 2003, we had $15.0 million under the Credit Facility
and two letters of credit outstanding in the amount of $1.6 million.
Availability under the Credit Facility is determined pursuant to a
semi-annual borrowing base determination which establishes the maximum
borrowings that may be outstanding under the credit facility. The borrowing base
is determined by a 60% vote of participant banks (two-thirds in the event of an
increase in the borrowing base), each of which bases its judgement on: (i) the
present value of our oil and gas reserves based on their own assumptions
regarding future prices, production, costs, risk factors and discount rates, and
(ii) projected cash flow coverage ratios calculated under varying scenarios. If
amounts outstanding under the credit facility exceed the borrowing base, as
redetermined from time to time, we would be required to repay
F-23
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
such excess over a defined period of time. We have a $200 million borrowing base
under our Credit Facility with $183.4 million available at December 31, 2003 and
had outstanding $16.6 million under the agreement.
Amounts outstanding under the credit facility bear interest at a rate equal
to LIBOR plus an amount which varies according to our Indebtedness to
Capitalization ratio (as defined in the Credit Agreement). The weighted average
interest rate was 2.9% in 2003 and 3.6% in 2002.
Our Credit Agreement has covenants which limit certain restricted payments
and investments, guarantees and indebtedness, prepayments of subordinated and
certain other indebtedness, mergers and consolidations, on certain types of
acquisitions and on the issuance of certain securities by subsidiaries, liens,
sales of properties, transactions with affiliates, derivative contracts and debt
in subsidiaries. We are also required to maintain certain financial ratios and
conditions, including without limitation an EBITDAX (earnings before interest,
taxes, depreciation, depletion, amortization and exploration expenses) to fixed
charge coverage ratio and a funded debt to capitalization ratio. At December 31,
2003, we were in compliance with all covenants of the Credit Agreement.
The amount of scheduled debt maturities during the next five years and
thereafter as of December 31, 2003 is as follows (amounts in thousands):
<Table>
2004........................................................ $ --
2005........................................................ 15,000
2006........................................................ --
2007........................................................ --
2008(1)..................................................... 75,000
Thereafter.................................................. 265,000
--------
Total debt maturities..................................... $355,000
========
</Table>
- ---------------------
(1) Redeemed February 27, 2004.
Based upon the quoted market price, the fair value of the 9 3/8% Notes was
estimated to be $165.8 million and $149.4 million at December 31, 2003 and 2002;
the fair value of the 9 1/2% Notes due 2008 was estimated to be $78.8 million
and $264.0 million at December 31, 2003 and 2002, and the fair value of the
9 1/2% Notes due 2006 was estimated to be $2.4 million at December 31, 2002. The
fair value of the long-term liability to unconsolidated affiliate is $94.3
million at December 31, 2003. The carrying amount of the credit facility
approximates its fair value at December 31, 2003.
10. INCOME TAXES
The components of income before income taxes and cumulative effect of
change in accounting principle for each of the three years in the period ended
December 31, 2003, are as follows:
<Table>
<Caption>
2003 2002 2001
------- ------- ---------
United States......................................... $35,085 $28,254 $(144,143)
Foreign............................................... 25,122 11,516 (8,351)
------- ------- ---------
Income from continuing operations before income
taxes............................................... $60,207 $39,770 $(152,494)
======= ======= =========
</Table>
F-24
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Income tax expense (benefit) is summarized as follows:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
----------------------------
2003 2002 2001
------- ------- --------
(IN THOUSANDS)
Current
Federal.............................................. $ 341 $ -- $ --
State................................................ 276 1,330 --
Foreign.............................................. 1,469 -- --
------- ------- --------
2,086 1,330 --
------- ------- --------
Deferred
Federal.............................................. 19,590 14,023 (49,015)
State................................................ 4,321 1,338 (12,108)
Foreign.............................................. (2,879) -- --
------- ------- --------
21,032 15,361 (61,123)
------- ------- --------
Total income tax expense (benefit)................ $23,118 $16,691 $(61,123)
======= ======= ========
</Table>
We recorded income tax expense (benefit) of $4.4 million, $(7.9) million
and $8.2 million in 2003, 2002 and 2001 related to discontinued operations. We
recorded a tax expense of $5.7 million related to a cumulative effect of a
change in accounting principle in 2003 (see Note 3). A deferred tax benefit
related to the exercise of employee stock options of approximately $0.6 million,
$0.5 million and $0.8 million was allocated directly to additional paid-in
capital in 2003, 2002 and 2001.
Total income tax expense (benefit) differs from the amount computed by
applying the federal income tax rate to income (loss) before income taxes and
cumulative effect. The reasons for these differences are as follows:
<Table>
<Caption>
YEAR ENDED
DECEMBER 31,
-------------------
2003 2002 2001
---- ---- -----
Statutory federal income tax rate........................... 35.0% 35.0% (35.0)%
Increase (decrease) in tax rate resulting from:
State income taxes, net of federal benefit................ 5.0 6.6 (5.2)
Nondeductible travel and entertainment and other.......... 0.3 0.1 0.1
Foreign income taxes net of federal benefit............... (1.1) -- --
---- ---- -----
39.2% 41.7% (40.1)%
==== ==== =====
</Table>
F-25
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The tax effects of temporary differences that result in significant
portions of the deferred income tax assets and liabilities and a description of
the financial statement items creating these differences are as follows:
<Table>
<Caption>
DECEMBER 31,
-----------------
2003 2002
------- -------
(IN THOUSANDS)
Net operating loss carryforwards............................ $44,835 $74,640
Alternative minimum tax credit carryforwards................ 781 200
Other accrued liabilities................................... -- 1,205
Commodity hedging contracts................................. 15,870 7,871
State income taxes.......................................... -- 2,298
Foreign income taxes........................................ 1,871 --
------- -------
Total deferred income tax assets.......................... 63,357 86,214
Less: valuation allowance................................. -- (804)
------- -------
Net deferred income tax assets............................ 63,357 85,410
------- -------
Property and equipment...................................... (30,667) (33,798)
Equity in foreign subsidiaries.............................. (585) (671)
Other accrued liabilities................................... (1,545) --
State income taxes.......................................... (1,250) --
------- -------
Total deferred income tax liabilities..................... (34,047) (34,469)
------- -------
Net deferred income tax asset............................... $29,310 $50,941
======= =======
</Table>
At December 31, 2003, we had a net operating loss carryforward for regular
tax purposes of approximately $128.1 million, which will begin expiring in 2018.
Alternative minimum tax credit carryforwards of $0.8 million do not expire and
may be applied to reduce regular income tax to an amount not less than the
alternative minimum tax payable in any one year. For all periods presented we
concluded that based upon available estimates and tax planning strategies, it
was more likely than not that all of the recorded deferred tax assets would be
realized. In 2003, we reversed a valuation allowance of a $0.8 million relating
to a capital loss carryover due to its realization in 2003.
11. SEGMENTS
Our operations consist of the acquisition, exploitation, exploration,
development and production of crude oil and natural gas. We have four operating
segments, Onshore California, Offshore California, West Texas and Congo because,
in accordance with SFAS No. 131, these are the segments that (1) engage in
business activities from which revenues are earned and expenses are incurred,
(2) whose operating results are regularly reviewed by our chief operating
decision maker to make decisions about resources to be allocated to the segment
and assess its performance and (3) for which discrete financial information is
available.
We have aggregated Onshore California, Offshore California and West Texas
into our domestic segment, which is a reportable segment. We have aggregated
these three operating segments because we believe these operating segments have
similar economic characteristics in the following areas as outlined in SFAS No.
131: (1) the nature of the products and services, (2) the nature of the
production process, (3) the type of class of customer for the products and
services, (4) the methods used to distribute their products or provide their
services and (5) the nature of the regulatory environment.
F-26
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Our reportable segments are domestic, foreign and other. Financial
information by reportable segment is presented below:
<Table>
<Caption>
2003
----------------------------------------
DOMESTIC FOREIGN OTHER(1) TOTAL
-------- ------- -------- --------
(IN THOUSANDS)
Revenues.................................... $327,009 $42,966 $ 1,362 $371,337
Depreciation, depletion, amortization and
accretion................................. 62,919 5,847 2,044 70,810
Income (loss) from continuing operations
before income tax......................... 119,964 25,122 (84,879) 60,207
Capital expenditures........................ 64,798 1,205 728 66,731
Total assets................................ 646,436 45,416 153,124 844,976
</Table>
<Table>
<Caption>
2002
----------------------------------------
DOMESTIC FOREIGN OTHER(1) TOTAL
-------- ------- -------- --------
(IN THOUSANDS)
Revenues.................................... $275,853 $31,978 $ 4,070 $311,901
Depreciation, depletion and amortization.... 64,562 6,198 2,368 73,128
Income (loss) from continuing operations
before income tax......................... 104,649 11,516 (76,395) 39,770
Capital expenditures........................ 137,002 1,524 2,956 141,482
Total assets................................ 557,421 52,269 245,481 855,171
</Table>
<Table>
<Caption>
2001
-----------------------------------------
DOMESTIC FOREIGN OTHER(1) TOTAL
-------- ------- --------- --------
(IN THOUSANDS)
Revenues................................... $274,786 $36,020 $ 273 $311,079
Depreciation, depletion and amortization... 58,347 10,381 1,826 70,554
Income (loss) from continuing operations
before income tax........................ (37,869) (8,351) (106,274) (152,494)
Capital expenditures....................... 148,329 20,647 1,262 170,238
Total assets............................... 548,186 56,404 235,222 839,812
</Table>
- ---------------
(1) Other includes corporate income and expenses.
CREDIT RISKS DUE TO CERTAIN CONCENTRATIONS
In 2003, 2002 and 2001, we had one customer under domestic segment that
accounted for 65%, 73%, and 63% of oil and gas revenues. In 2003 we had another
customer under domestic segment that accounted for 11% of oil and gas revenues
and in 2001 we had another domestic segment customer that accounted for 23% of
oil and gas revenues.
We entered into a 15-year contract, effective January 1, 2000, to sell all
of our current and future California crude oil production to ConocoPhillips. The
contract provides pricing based on a fixed percentage of the NYMEX crude oil
price for each type of crude oil that we produce in California. Effective
January 1, 2003, we renegotiated this contract relative to our Point Arguello
production, effectively increasing our price by 14.5% on the NYMEX price.
Effective January 1, 2004, we renegotiated our NYMEX relationship for all
production sold to ConocoPhillips increasing our effective realization by
approximately 11%. While the contract does not reduce our exposure to price
volatility, it does effectively eliminate the risk of widening basis
differential between the NYMEX price and the field price of our California oil
production. In doing so, the
F-27
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
contract makes it substantially easier for us to hedge our realized prices. The
ConocoPhillips contract permits, under certain circumstances, to separately
market up to ten percent of our California crude production. We exercised this
right and sold 5,000 BOPD of our San Joaquin Valley oil production to a third
party under a two-year contract containing NYMEX pricing in 2003 and under a
one-year contract containing NYMEX pricing in 2002 and 2001.
Our revenues are derived principally from uncollateralized sales to
customers in the oil and gas industry, therefore, customers may be similarly
affected by changes in economic and other conditions within the industry. We
have not experienced significant credit losses in such sales. Sales of oil and
gas to ConocoPhillips are similarly uncollateralized.
12. ACQUISITION OF ATHANOR RESOURCES, INC.
We acquired Athanor Resources, Inc. (Athanor) in September 2002, in a
transaction valued at $101.4 million, which included the combination of $61.3
million of available cash and additional borrowings, the issuance of
approximately $20.1 million of our common stock (approximately 2.0 million
shares) to Athanor stockholders, and the fair value of the net liabilities
assumed of approximately $20.0 million.
The acquisition was accounted for using the purchase method of accounting.
The purchase price was finalized during the second quarter of 2003, and the
following table summarizes the fair value of the assets acquired and liabilities
assumed at the date of acquisition.
<Table>
<Caption>
(IN THOUSANDS)
--------------
Current assets.............................................. $ 4,426
Property, plant and equipment............................... 102,801
Goodwill.................................................... 17,121
--------
Total assets acquired..................................... 124,348
--------
Current liabilities......................................... 4,474
Long-term debt.............................................. 20,000
Deferred tax liability...................................... 18,477
--------
Total liabilities assumed................................. 42,951
--------
Net assets acquired....................................... $ 81,397
========
</Table>
The allocation of the purchase price resulted in $17.1 million allocated to
goodwill which is not expected to be deductible for tax purposes.
The acquisition included certain non-cash investing and financing
activities not reflected in the Consolidated Statement of Cash Flows for the
year ended December 31, 2002, as follows:
<Table>
<Caption>
(IN THOUSANDS)
--------------
Common stock issued......................................... $20,086
Long-term debt assumed...................................... 20,000
</Table>
Subsequent to the acquisition, the long-term debt of $20.0 million was
repaid.
The following unaudited pro forma condensed income statement information
has been prepared as if the acquisition had occurred at the beginning of the
periods presented. The historical results of operations have been adjusted to
reflect the difference between Athanor's historical depletion, depreciation and
amortization
F-28
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
and the expense calculated based on the value allocated to the assets acquired.
The information presented is not necessarily indicative of the results of future
operations of the combined companies.
<Table>
<Caption>
2002 2001
----------- -----------
(IN THOUSANDS, EXCEPT PER
SHARE DATA)
Revenues.................................................... $327,458 $344,256
Income (loss) from continuing operations.................... 24,952 (82,432)
Net income (loss)........................................... 14,148 (70,228)
Earnings per share
Basic
Income (loss) from continuing operations............... 1.31 (4.41)
Net income (loss)...................................... 0.74 (3.75)
Diluted
Income (loss) from continuing operations............... 1.30 (4.41)
Net income (loss)...................................... 0.74 (3.75)
</Table>
13. COMMITMENTS AND CONTINGENCIES
LEGAL PROCEEDINGS AND OTHER MATTERS
We acquired properties from Unocal in 1996 and are obligated to make a
contingent payment based on net proceeds received, less certain deductions, on
oil sold through 2004 if oil prices exceed thresholds set forth in the purchase
and sale agreement with Unocal. Any contingent payments paid or accrued are
accounted for as a purchase price adjustment to oil and gas properties. We paid
$10.8 million to Unocal in 2002 attributable to calendar year 2001 and recorded
the payment as an increase in oil and gas properties. In March 2003, we advised
Unocal that we had failed to take deductions to proceeds received that we
believe are permitted by the agreement. Application of these deductions results
in no payment due for either calendar year 2001 or 2002. Unocal disputes this
position for both years. We filed suit against Unocal to recover the 2001
payment, secure a declaration of the appropriate deduction methodology to be
applied for 2002 through 2004 and to recover attorneys' fees. Unocal has
answered and filed a counterclaim claiming breach of contract and anticipatory
breach of contract seeking $16.0 million for 2002, a declaration of the
appropriate deduction methodology payment of amounts attributable to 2003 and
2004 and attorneys' fees. While the outcome of this matter is not presently
determinable, its resolution is not expected to have a material impact on our
results of operations, financial condition or liquidity.
We have asserted a claim against Torch Energy Advisors for matters arising
out of our former outsourcing arrangement. Among other demands, we have
requested the return of a $2.0 million working capital advance. Torch has
asserted claims for indemnity and payment of certain fees it asserts are owed to
them. These outstanding issues will be arbitrated and are not expected to have a
material impact on our results of operations, financial condition or liquidity.
On December 18, 2002, a lawsuit was filed by Hills for Everyone, a
non-profit corporation, against Orange County and Nuevo Energy Company
challenging the adequacy of the Environment Impact Report for our Tonner Hills
project. The suit sought to compel Orange County to set aside its decision to
adopt the Environment Impact Report and sought additional environmental analysis
and mitigation measures. We contested the litigation. During the second quarter
of 2003, we entered into a settlement agreement with Hills for Everyone and
Orange County ending the litigation. The settlement did not have a material
impact on the project or our results of operations, financial condition or
liquidity.
F-29
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
COMMITMENTS AND CONTINGENCIES
On December 30, 2003, we sold our Tonner Hills residential development
property for approximately $47 million. We received $16 million of the purchase
price on the date of the sale and anticipate receiving an additional $22.5
million on March 29, 2004. The $16 million is currently reported in other
liabilities, and the $22.5 million will be reported in other liabilities as
these amounts are accounted for as deposits until certain habitat restoration
outlined in the purchase and sales agreement completed by us.
On September 14, 2001, during an annual inspection, we discovered fractures
in the heat affected zone of certain flanges on our pipeline that connects the
Point Pedernales field with onshore processing facilities. We voluntarily
elected to shut-in production in the field while repairs were being made. The
daily net production from this field was approximately 5,000 barrels of crude
oil and 1.2 MMcf of natural gas, representing approximately 11% of our daily
production. We replaced the damaged flanges, as well as others which had not
shown signs of damage. We resumed production in January 2002. During the third
quarter 2002 we reached a final agreement with our underwriters with respect to
our business interruption claim. Accordingly, we recognized $3.0 million of
business interruption recoveries during the third quarter 2002 which is
classified in other revenue and received payment on this claim by year-end 2002.
As of December 31, 2003, all outstanding claims have been settled.
On June 15, 2001, we experienced a failure of a carbon dioxide treatment
vessel at the Rincon Onshore Separation Facility ("ROSF") located in Ventura
County, California. There were no injuries associated with this event. Crude oil
and natural gas produced from three fields offshore California are transported
onshore by pipeline to the ROSF plant where crude oil and water are separated
and treated, and carbon dioxide is removed from the natural gas stream. The
daily net production associated with these fields at the time of the incident
was approximately 3,000 barrels of crude oil and 2.4 MMcf of natural gas,
representing approximately 6% of our daily production. In early July 2001, crude
oil production resumed and full gas sales resumed by mid August 2001. Insurance
claims relating to the cost of repair and business interruption (less a 30-day
waiting period) were settled in the second quarter of 2003, and we recognized
income of $2.3 million in connection with the insurance settlement.
On September 22, 2000, we were named as a defendant in the lawsuit Thomas
Wachtell et al. versus Nuevo Energy Company in the Superior Court of Los Angeles
County, California. We settled this lawsuit in June 2002 for, among other
matters, making a payment to plaintiffs of $3.4 million, and receiving from
plaintiffs certain interests in properties and extinguishing certain contract
rights of plaintiffs. We established a reserve for this contingency in 2001 and
the settlement payment did not have a material impact on our results of
operations or financial position.
On April 5, 2000, we filed a lawsuit against ExxonMobil Corporation in the
United States District Court for the Central District of California, Western
Division regarding our 50% interest in the Sacate field, offshore Santa Barbara
County, California. We settled this lawsuit in June 2002. Under the terms of the
settlement agreement, we received $16.5 million from ExxonMobil and conveyed to
them our interest in the Santa Ynez Unit, our non-consent interest in the
adjacent Pescado field and relinquished our right to participate in the Sacate
field and recorded a $15.3 million gain related to the sale of this unproved
property.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects our Point Pedernales field with
shore-based processing facilities. The volume of the spill was estimated to be
163 barrels of oil. Repairs were completed by the end of 1997, and production
recommenced in December 1997. The costs of the clean up and the cost to repair
the pipeline were covered by our insurance, less a deductible of $0.1 million.
As of December 31, 2003 all significant outstanding claims have been settled. We
expect that the final insurance settlements related to these claims will be
insignificant. We are awaiting final disposition of certain insurance claims
that have been submitted to our carriers.
F-30
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Our acquisition agreement to purchase the two subsidiaries owning interests
in the Yombo field offshore Congo contains a provision for contingent royalty to
be paid by us to the seller if certain conditions are met. Under this provision
we will pay to the seller an amount equal to $2.8 million, increased by 7% per
year from 1995, if we recover from our Yombo field production an amount greater
than the sum of our capital costs, our operating costs, and $27.0 million, which
entire amount increases 27% annually. We currently estimate that we could reach
payout as early as 2005.
Our foreign investments involve risks typically associated with investments
in emerging markets such as an uncertain political, economic, legal and tax
environment and expropriation and nationalization of assets. In addition, if a
dispute arises in our foreign operations, we may be subject to the exclusive
jurisdiction of foreign courts or may not be successful in subjecting foreign
persons to the jurisdiction of the United States. We attempt to conduct our
business and financial affairs so as to protect against political and economic
risks applicable to operations in the various countries where we operate, but
there can be no assurance that we will be successful in so protecting ourselves.
A portion of our investment in the Congo is insured through political risk
insurance provided by Overseas Private Investment Company ("OPIC"). The
political risk insurance through OPIC covers up to $25.0 million relating to
expropriation, which is the maximum coverage available through OPIC. During
1997, a new government was established in the Congo. Although the political
situation in the Congo has not to date had a material adverse effect on our
operations in the Congo, no assurances can be made that continued political
unrest in West Africa will not have a material adverse effect on us or our
operations in the Congo in the future.
In connection with our February 1995 acquisitions of two subsidiaries
owning interests in the Yombo field offshore Congo, we and a wholly-owned
subsidiary of CMS NOMECO Oil & Gas Co. ("CMS") agreed with the seller of the
subsidiaries not to claim certain tax losses ("dual consolidated losses")
incurred by such subsidiaries prior to the acquisitions. Under the tax law in
the Congo, as it existed when this acquisition took place, if an entity is
acquired in its entirety and that entity has certain tax attributes, for example
tax loss carryforwards from operations in the Republic of Congo, the subsequent
owners of that entity can continue to utilize those losses without restriction.
Pursuant to the agreement, we and CMS may be liable to the seller for the
recapture of dual consolidated losses (net operating losses of any domestic
corporation that are subject to an income tax of a foreign country without
regard to the source of its income or on a residence basis) utilized by the
seller in years prior to the acquisitions if certain triggering events occur,
including: (i) a disposition by either us or CMS of its respective Congo
subsidiary, (ii) either Congo subsidiary's sale of its interest in the Yombo
field, (iii) the acquisition of us or CMS by another consolidated group or (iv)
the failure of CMS's Congo subsidiary or us to continue as a member of its
respective consolidated group.
A triggering event will not occur, however, if a subsequent purchaser
enters into certain agreements specified in the consolidated return regulations
intended to ensure that such dual consolidated losses will not be claimed. The
only time limit associated with the occurrence of a triggering event relates to
the utilization of a dual consolidated loss in a foreign jurisdiction. A dual
consolidated loss that is utilized to offset income in a foreign jurisdiction is
only subject to recapture for 15 years following the year in which the dual
consolidated loss was incurred for U.S. income tax purposes. We and CMS have
agreed among ourselves that the party responsible for the triggering event shall
indemnify the other for any liability to the seller as a result of such
triggering event. Our potential direct liability could be as much as $25.1
million if a triggering event with respect to us occurs. Additionally, we
believe that CMS's liability (for which we would be jointly liable with an
indemnification right against CMS) could be as much as $42.8 million. CMS sold
their interest in the Yombo field in 2002, to a U.S. subsidiary of Perenco, S.A.
(Perenco). The sale was not a triggering event as both CMS and Perenco filed a
request for a Closing Agreement with the Internal Revenue Service in accordance
with the U.S. consolidated tax return regulations prior to the sale. Further, we
do not expect a triggering event to occur with respect to Nuevo, CMS or Perenco,
and do not believe the agreement will have a material adverse effect upon us. We
do not expect that the proposed merger with Plains will be a triggering event.
F-31
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In 1996, the Congo government requested that the convention governing the
Marine I Exploitation Permit be converted to a Production Sharing Agreement
("PSA"). We are under no obligation to convert to a PSA, and our existing
convention is valid and protected by law. Our position is that any conversion to
a PSA should have no detrimental impact to us, otherwise, we will not agree to
any such conversion. Discussions with the government have been ongoing
intermittently since early 1997. To date, no final agreement has been reached
concerning conversion to a PSA.
We have been named as a defendant in certain other lawsuits incidental to
our business. These actions and claims in the aggregate seek damages against us
and are subject to the inherent uncertainties in any litigation. We are
defending ourselves vigorously in all such matters. We have reserved an amount
that we deem adequate to cover any potential losses related to these matters to
the extent the losses are deemed probable and estimable. This amount is reviewed
periodically and changes may be made, as appropriate. Any additional costs
related to these potential losses are not expected to be material to our
operating results, financial condition or liquidity.
GUARANTEES RELATED TO ASSETS OR OBLIGATIONS OF THIRD PARTIES.
We have indemnified certain third parties for future environmental
remediation costs that may be incurred for properties that we purchased or
properties that we sold to a third party. The properties may or may not require
environmental remediation and if we are determined to be responsible, our
indemnities may require us, among other matters, to pay for the remediation
costs. We are not able to determine the maximum potential amount, if any, of
future payments that we could be required to make under these indemnifications
primarily due to the following: the indefinite term of the majority of these
indemnities; the unknown extent of possible contamination; the conditional
nature of our responsibility under certain indemnities; uncertainties related to
the timing of the remediation work; possible changes in laws governing the
remediation process; the unknown number of claims that may be made and changes
in remediation technology.
We have performance obligations in the ordinary course of business that are
secured by surety bonds or letters of credit. These surety bonds and letters of
credit are issued by financial institutions and are required to be reimbursed if
drawn upon. At December 31, 2003, we had surety bonds of $39.7 million and
letters of credit of $1.6 million.
We have guaranteed the payment of the Nuevo Financing I TECONS issued
December 1996. The TECONS are supported by our 5 3/4% Convertible Debentures,
which are included on our balance sheet as long-term liabilities to
unconsolidated affiliate.
In the ordinary course of business, we have provided indemnifications and
guarantees that are not explicitly defined whose terms range in duration. We do
not believe that these will have a material effect on our results of operation,
financial condition or liquidity.
OPERATING LEASES
We have operating leases in the normal course of business, which include
those for office space, operating facilities and office equipment, with varying
terms from 2004 to 2009. Total rental expense under the agreements was $1.5
million in 2003, $1.3 million in 2002 and $1.1 million in 2001. The rental
expense is recorded in general and administrative expense. At December 31, 2003,
our total commitments under operating leases were approximately $6.1 million.
F-32
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Minimum annual rental commitments at December 31, 2003, were as follows:
<Table>
<Caption>
OPERATING
LEASES
----------
(IN
THOUSANDS)
2004........................................................ $1,492
2005........................................................ 1,487
2006........................................................ 1,214
2007........................................................ 808
2008........................................................ 808
Thereafter.................................................. 270
------
Total..................................................... $6,079
======
</Table>
14. FINANCIAL INSTRUMENTS
We have entered into commodity swaps, collars, put options and interest
rate swaps. The commodity swaps, collars and put options are designated as cash
flow hedges and the interest rate swaps are designated as fair value hedges in
accordance with SFAS 133. Quantities covered by crude hedges are based on West
Texas Intermediate ("WTI") barrels. Our production is expected to average 82% of
WTI, therefore, each WTI barrel hedges 1.22 barrels of our production.
DERIVATIVE INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES
At December 31, 2003, we had entered into the following cash flow hedges:
<Table>
<Caption>
CRUDE OIL NATURAL GAS
------------------------- ----------------------------------
BBLS/ DAY $/BBL INDEX MMBTU/DAY $/MMBTU INDEX
--------- ----- ----- --------- ------- ------------
Swaps for Sales
2004
1st Qtr.................... 19,800 25.71 WTI 16,500 4.93 Waha & Socal
2nd Qtr.................... 19,500 25.71 WTI 14,500 4.65 Waha & Socal
3rd Qtr.................... 19,800 25.71 WTI 10,500 4.50 Waha & Socal
4th Qtr.................... 21,000 25.98 WTI 14,500 4.64 Waha & Socal
2005
1st Qtr.................... 17,500 24.88 WTI 13,000 4.75 Waha & Socal
2nd Qtr.................... 14,500 24.67 WTI 9,500 4.66 Waha
3rd Qtr.................... 4,500 22.14 WTI 9,500 4.40 Waha
4th Qtr.................... 4,500 22.14 WTI 9,500 4.40 Waha
Swaps for Purchases
2004....................... 8,000 3.91 Socal
2005....................... 8,000 3.85 Socal
</Table>
At December 31, 2003, the fair market value of these hedge positions is a
loss of $40.5 million. All of these agreements expose us to counterparty credit
risk to the extent that the counterparty is unable to meet its settlement
commitments.
F-33
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DERIVATIVE INSTRUMENTS DESIGNATED AS FAIR VALUE HEDGES
In late December 2001 and early 2002, we entered into three interest rate
swap agreements with notional amounts totaling $200 million to hedge the fair
value of our 9 1/2% Notes due 2008 and our 9 3/8% Notes due 2010. These swaps
were designated as fair value hedges and as interest rates fluctuated, the
change in value of these instruments was reflected as an increase or decrease of
long-term debt with a corresponding increase in long-term assets or liabilities.
In late August and early September 2002, we terminated our swap
transactions relating to these Notes. As a result of these terminations, we
received accrued interest of $2.2 million and the present value of the swap
option of $9.6 million on our 9 3/8% Notes and $0.5 million in accrued interest
and the present value of the swap option of $2.5 million on our 9 1/2% Notes.
The gain of $9.6 million on our 9 3/8% Notes and $2.5 million on our 9 1/2%
Notes is reflected as an increase of long-term debt and will be amortized as a
reduction to interest expense over the life of the Notes. During the twelve
months ended December 31, 2003, we amortized $1.3 million as a reduction of
interest expense.
Following the termination of the three interest rate swaps referenced
above, in late August and early November 2002, we entered into two new interest
rate swap agreements with notional amounts totaling $100.0 million, to hedge a
portion of the fair value of our 9 3/8% Notes due 2010. These swaps were also
designated and accounted for as fair value hedges.
In May 2003, we terminated our swap transactions relating to these Notes.
As a result of these terminations, we received accrued interest of $0.4 million
and the present value of the swap option of $4.1 million. The remaining gain of
$4.1 million continues to be reflected as an increase of long-term debt and is
being amortized as a reduction to interest expense over the life of the Notes.
Through December 31,2003, we had amortized $0.2 million.
In late October 2003, we entered into an interest rate swap agreement with
a notional amount of $100 million, to hedge a portion of the fair value of our
9 3/8% Notes due 2010. This swap is designated as a fair value hedge and is
reflected as a decrease in long-term debt of $0.2 million as of December
31,2003, with a corresponding increase in long-term liabilities. Under the terms
of the agreement, the counterparty pays us a weighted average fixed annual rate
of 9 3/8% on total notional amount of $100 million, and we pay the counterparty
a variable annual rate equal to the six-month LIBOR rate plus a weighted average
rate of 5.02%.
DERIVATIVE INSTRUMENTS NOT DESIGNATED AS HEDGES
In December 2001, Enron Corp. ("Enron") and certain of its affiliates filed
voluntary petitions for reorganization under Chapter 11 of the United States
Bankruptcy Code. As a result, we recorded a $7.6 million charge in the fourth
quarter of 2001: $1.2 million related to the November and December 2001 crude
oil price swaps, $0.9 million related to the Enron call spread (see below), and
$5.5 million related to the fair value of open hedges of second, third and
fourth quarter 2002 crude oil production. Once a deterioration in
creditworthiness creates uncertainty as to whether the future cash flows from
the hedging instrument will be highly effective in offsetting the hedged risk,
the derivative instrument is no longer considered highly effective and no longer
qualifies for hedge accounting treatment. At such time, the fair value of the
derivative asset or liability is adjusted to its new fair value, with the change
in value being charged to current earnings. The net gain or loss of the
derivative instruments previously reported in other comprehensive income remains
in accumulated other comprehensive income and is reclassified into earnings
during the period in which the originally designated hedge items affect
earnings. The $2.2 million deferred gain in Other Comprehensive Income at
December 31, 2001 was reclassified into earnings in 2002.
In 2001 and 2000, we entered into call spreads with the anticipation of
using the proceeds to offset the Unocal Contingent payment. (See Note 13.)
Subsequent to entering into the call spreads, the market fell and as a result,
offsetting call spreads were purchased to economically nullify the trade. All of
our existing call
F-34
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
spreads had been offset through the purchase of a mirror spread, however, the
call spread with Enron was cancelled. (See above discussion). The remaining
mirror call spread is not designated as a hedging instrument and is
marked-to-market with changes in fair value recognized currently as derivative
gain/loss. For the twelve months ended December 31, 2003, we recognized $1.8
million as a derivative loss. At December 31, 2003, the call spread matured for
$4.6 million.
In August 2003, we entered into three-way collars that are not designated
as hedging instruments and are marked-to-market with changes in fair value
recognized currently as a derivative gain/loss. During the twelve months ended
December 31, 2003, we recorded a $4.1 million derivative loss and recorded the
fair value of the derivative loss at December 31, 2003, totaling $4.1 million as
a liability.
<Table>
<Caption>
BBLS/ DAY INDEX WEIGHTED AVERAGE PRICE
--------- ----- ----------------------
Three-Way Collars(1)
2004
(Jan - Dec)................................... 8,000 WTI $19.28 -- 24.00 -- 31.00
</Table>
- ---------------
(1) A "Three-Way Collar" combines a sold put, a purchased put and a sold call.
The purchased put and sold put establish a floating minimum price and the
sold call establishes a maximum price we will receive for the volumes under
contract.
FAIR VALUES OF FINANCIAL INSTRUMENTS
Fair value for cash, short-term investments, receivables and payables
approximates carrying value. The following table details the carrying values and
approximate fair values of our other investments, derivative financial
instruments and long-term debt at December 31, 2003 and 2002.
<Table>
<Caption>
DECEMBER 31, 2003 DECEMBER 31, 2002
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN THOUSANDS)
Derivative Instruments
Commodity price swaps............................ $(40,484) $(40,484) $(22,311) $(22,311)
Interest rate swaps.............................. (153) (153) 2,161 2,161
Long-term debt (see Note 9)(1)..................... 340,000 338,894 409,577 415,833
TECONS............................................. -- -- 115,000 64,400
</Table>
- ---------------
(1) As a result of adopting FIN46R, Consolidation of Variable Interest Entities,
at December 31, 2003, we are required to deconsolidate our wholly owned
Nuevo Financing I business trust which issued our TECONS. We are including
the long-term liability to unconsolidated affiliate in long-term debt.
The fair value of our long-term debt and TECONS were determined based upon
interest rates currently available to us for borrowing with similar terms at
December 31, 2003 and 2002.
15. SUPPLEMENTAL INFORMATION (UNAUDITED)
OIL AND GAS PRODUCING ACTIVITIES
Included herein is information with respect to oil and gas acquisition,
exploration, development and production activities, which is based on estimates
of year-end oil and gas reserve quantities and estimates of future development
costs and production schedules. Reserve quantities and future production as of
December 31, 2003, and for previous years, are based primarily on reserve
reports prepared by the independent
F-35
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
petroleum engineering firm of Ryder Scott Company L.P. These estimates are
inherently imprecise and subject to substantial revision.
Estimates of future net cash flows from proved reserves of gas, oil,
condensate and natural gas liquids ("NGL") were made in accordance with SFAS No.
69, Disclosures about Oil and Gas Producing Activities. The estimates are based
on the NYMEX cash price at year-end 2003, of $32.55 per Bbl and $5.97 per MMbtu
adjusted for basis differences, and are adjusted for the effects of contractual
agreements with Unocal and Amoco in connection with the California and Congo
property acquisitions (see Note 13).
Estimated future cash inflows are reduced by estimated future development
and production costs based on year-end cost levels, assuming continuation of
existing economic conditions, and by estimated future income tax expense. Tax
expense is calculated by applying the existing statutory tax rates, including
any known future changes, to the pre-tax net cash flows, less depreciation of
the tax basis of the properties and depletion allowances applicable to the gas,
oil, condensate and NGL production. Because the disclosure requirements are
standardized, significant changes can occur in these estimates based upon oil
and gas prices currently in effect. The results of these disclosures should not
be construed to represent the fair market value of our oil and gas properties. A
market value determination would include many additional factors including: (i)
anticipated future increases or decreases in oil and gas prices and production
and development costs; (ii) an allowance for return on investment; (iii) the
value of additional reserves, not considered proved at the present, which may be
recovered as a result of further exploration and development activities; and
(iv) other business risks.
COSTS INCURRED
The following table sets forth the costs incurred in property acquisition
and development activities:
<Table>
<Caption>
DOMESTIC FOREIGN TOTAL
-------- ------- --------
(IN THOUSANDS)
2003
Property acquisition................................ $ 830 $ -- $ 830
Exploration......................................... 100 926 1,026
Development......................................... 55,788 1,206 56,994
Asset retirement obligation......................... 3,374 -- 3,374
-------- ------- --------
$ 60,092 $ 2,132 $ 62,224
======== ======= ========
2002
Property acquisition................................ $107,064 $ -- $107,064
Exploration......................................... 357 1,244 1,601
Development......................................... 52,531 1,527 54,058
-------- ------- --------
$159,952 $ 2,771 $162,723
======== ======= ========
2001
Property acquisition................................ $ 47,266 $ 47 $ 47,313
Exploration......................................... 16,004 4,703 20,707
Development......................................... 100,721 20,222 120,943
-------- ------- --------
$163,991 $24,972 $188,963
======== ======= ========
</Table>
F-36
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pro forma costs incurred for the years ended December 31, 2002 and 2001,
for the change in accounting had SFAS No. 143 been implemented during these
periods would have been $0.4 million and $0.9 million respectively, associated
with property acquisitions and new domestic wells drilled.
- ---------------
(1) Includes capitalized interest directly related to development activities of
$1.6 million, $1.9 million and $2.5 million in 2003, 2002 and 2001,
respectively.
CAPITALIZED COSTS
The following table sets forth the capitalized costs relating to oil and
gas activities and the associated accumulated depreciation, depletion and
amortization:
<Table>
<Caption>
DOMESTIC FOREIGN TOTAL
--------- -------- ----------
(IN THOUSANDS)
2003
Proved properties................................ $ 911,722 $ 93,166 $1,004,888
Unproved properties.............................. 26,314 -- 26,314
--------- -------- ----------
Total capitalized costs....................... 938,036 93,166 1,031,202
Accumulated depreciation, depletion and
amortization................................ (294,833) (50,258) (345,091)
--------- -------- ----------
Net capitalized costs....................... $ 643,203 $ 42,908 $ 686,111
========= ======== ==========
2002
Proved properties................................ $ 829,839 $ 92,964 $ 922,803
Unproved properties.............................. 28,369 86 28,455
--------- -------- ----------
Total capitalized costs....................... 858,208 93,050 951,258
Accumulated depreciation, depletion and
amortization................................ (304,740) (44,155) (348,895)
--------- -------- ----------
Net capitalized costs....................... $ 553,468 $ 48,895 $ 602,363
========= ======== ==========
2001
Proved properties................................ $ 893,215 $ 91,437 $ 984,652
Unproved properties.............................. 27,117 2,660 29,777
--------- -------- ----------
Total capitalized costs....................... 920,332 94,097 1,014,429
Accumulated depreciation, depletion and
amortization................................ (378,644) (37,693) (416,337)
--------- -------- ----------
Net capitalized costs....................... $ 541,688 $ 56,404 $ 598,092
========= ======== ==========
</Table>
We have included asset retirement costs in total capitalized costs and the
related accumulated allocation of the asset retirement costs in accumulated
depreciation, depletion and amortization for the year ended December 31, 2003.
Pro forma basis as required by SFAS No. 143, had we adopted the provisions of
SFAS No. 143 prior to January 1, 2003, net capitalized costs would have been as
follows:
<Table>
<Caption>
PRO FORMA ASSET
ADOPTION DATE RETIREMENT OBLIGATION
- ------------- ---------------------
(IN THOUSANDS)
December 31, 2002........................................... $92,680
December 31, 2001........................................... 84,182
January 1, 2001............................................. 76,461
</Table>
F-37
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
<Table>
<Caption>
DOMESTIC FOREIGN TOTAL
--------- -------- ---------
(IN THOUSANDS)
2003
Revenues from oil and gas producing activities... $ 327,009 $ 42,966 $ 369,975
Production costs................................. (149,261) (10,571) (159,832)
Exploration costs................................ (689) (1,426) (2,115)
Depreciation, depletion, amortization and
accretion..................................... (62,919) (5,847) (68,766)
--------- -------- ---------
Income (loss) before income tax.................. 114,140 25,122 139,262
Income tax (provision) benefit................... (43,830) (9,647) (53,477)
--------- -------- ---------
Results of operations from producing
activities (excluding corporate overhead and
interest costs)............................. $ 70,310 $ 15,475 $ 85,785
========= ======== =========
2002
Revenues from oil and gas producing activities... $ 275,853 $ 31,978 $ 307,831
Production costs................................. (122,207) (10,747) (132,954)
Exploration costs................................ (1,024) (3,517) (4,541)
Depreciation, depletion and amortization......... (64,562) (6,198) (70,760)
--------- -------- ---------
Income (loss) before income tax.................. 88,060 11,516 99,576
Income tax (provision) benefit................... (36,721) (4,802) (41,523)
--------- -------- ---------
Results of operations from producing
activities (excluding corporate overhead and
interest costs)............................. $ 51,339 $ 6,714 $ 58,053
========= ======== =========
2001
Revenues from oil and gas producing activities... $ 274,786 $ 36,020 $ 310,806
Production costs................................. (146,058) (14,028) (160,086)
Exploration costs................................ (16,170) (5,888) (22,058)
Depreciation, depletion and amortization......... (58,347) (10,381) (68,728)
Provision for impairment of oil and gas
properties.................................... (89,466) (14,024) (103,490)
--------- -------- ---------
Income (loss) before income tax.................. (35,255) (8,301) (43,556)
Income tax (provision) benefit................... 14,148 3,318 17,466
--------- -------- ---------
Results of operations from producing
activities (excluding corporate overhead and
interest costs)............................. $ (21,107) $ (4,983) $ (26,090)
========= ======== =========
</Table>
Pro forma results of operations from producing activities for 2002 and 2001
for the change in accounting had SFAS No. 143 been implemented during these
periods would have been $60,577 and $(22,526), respectively.
- ---------------
* Results of operations represent results from continuing operations.
F-38
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Our estimated total proved and proved developed reserves of oil and gas are
as follows:
<Table>
<Caption>
CRUDE OIL AND LIQUIDS (MBBL)(1) NATURAL GAS (MMCF)(1)
------------------------------- ----------------------------
DOMESTIC FOREIGN TOTAL DOMESTIC FOREIGN TOTAL
--------- -------- -------- -------- ------- -------
2003
Proved reserves at beginning of
year............................. 206,237 14,100 220,337 173,844 841 174,685
Revisions of previous
estimates...................... 1,336 1,983 3,319 21,028 16 21,044
Extensions and discoveries....... 3,977 -- 3,977 10,746 -- 10,746
Production....................... (14,111) (1,764) (15,875) (14,394) (52) (14,446)
Sales of reserves in-place....... (35,636) -- (35,636) (25,531) -- (25,531)
Purchase of reserves in-place.... 3,949 -- 3,949 673 -- 673
------- ------ ------- ------- ----- -------
Proved reserves at end of year... 165,752 14,319 180,071 166,366 805 167,171
======= ====== ======= ======= ===== =======
Proved developed reserves
Beginning of year.............. 187,735 14,100 201,835 139,609 841 140,450
======= ====== ======= ======= ===== =======
End of year.................... 150,098 14,319 164,417 124,916 805 125,721
======= ====== ======= ======= ===== =======
2002
Proved reserves at beginning of
year........................... 199,014 15,844 214,858 111,363 1,129 112,492
Revisions of previous
estimates...................... 18,015 131 18,146 16,213 (236) 15,977
Extensions and discoveries....... -- -- -- 2,564 -- 2,564
Production....................... (14,640) (1,875) (16,515) (13,460) (52) (13,512)
Sales of reserves in-place....... (168) -- (168) (4,829) -- (4,829)
Purchase of reserves in-place.... 4,016 -- 4,016 61,993 -- 61,993
------- ------ ------- ------- ----- -------
Proved reserves at end of year... 206,237 14,100 220,337 173,844 841 174,685
======= ====== ======= ======= ===== =======
Proved developed reserves
Beginning of year.............. 169,507 15,844 185,351 92,890 1,129 94,019
======= ====== ======= ======= ===== =======
End of year.................... 187,735 14,100 201,835 139,609 841 140,450
======= ====== ======= ======= ===== =======
2001
Proved reserves at beginning of
year........................... 196,692 23,202 219,894 165,977 -- 165,977
Revisions of previous
estimates...................... 15,164 (5,478) 9,686 (55,422) -- (55,422)
Extensions and discoveries....... 311 -- 311 578 1,129 1,707
Production....................... (14,536) (1,880) (16,416) (12,750) -- (12,750)
Sales of reserves in-place....... -- -- -- -- -- --
Purchase of reserves in-place.... 1,383 -- 1,383 12,980 -- 12,980
------- ------ ------- ------- ----- -------
Proved reserves at end of year... 199,014 15,844 214,858 111,363 1,129 112,492
======= ====== ======= ======= ===== =======
Proved developed reserves
Beginning of year.............. 160,039 11,013 171,052 122,500 -- 122,500
======= ====== ======= ======= ===== =======
End of year.................... 169,507 15,844 185,351 92,890 1,129 94,019
======= ====== ======= ======= ===== =======
</Table>
- ---------------
(1) Reserves and production from discontinued operations are included in this
table
F-39
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DISCOUNTED FUTURE NET CASH FLOWS
The standardized measure of discounted future net cash flows and changes
therein are shown below:
<Table>
<Caption>
DOMESTIC FOREIGN TOTAL
----------- --------- -----------
(IN THOUSANDS)
2003
Future cash inflows.......................... $ 5,104,116 $ 347,147 $ 5,451,263
Future production costs...................... (2,274,483) (210,207) (2,484,690)
Future development costs(1).................. (415,090) (1,730) (416,820)
----------- --------- -----------
Future net inflows before income tax......... 2,414,543 135,210 2,549,753
Future income taxes.......................... (733,350) (35,750) (769,100)
----------- --------- -----------
Future net cash flows........................ 1,681,193 99,460 1,780,653
10% discount factor.......................... (632,055) (27,250) (659,305)
----------- --------- -----------
Standardized measure of discounted future net
cash flows................................ $ 1,049,138 $ 72,210 $ 1,121,348
=========== ========= ===========
2002
Future cash inflows.......................... $ 5,290,440 $ 343,406 $ 5,633,846
Future production costs...................... (2,435,730) (169,832) (2,605,562)
Future development costs..................... (392,746) (4,406) (397,152)
----------- --------- -----------
Future net inflows before income tax......... 2,461,964 169,168 2,631,132
Future income taxes.......................... (690,501) (48,777) (739,278)
----------- --------- -----------
Future net cash flows........................ 1,771,463 120,391 1,891,854
10% discount factor.......................... (693,830) (28,738) (722,568)
----------- --------- -----------
Standardized measure of discounted future net
cash flows................................ $ 1,077,633 $ 91,653 $ 1,169,286
=========== ========= ===========
2001
Future cash inflows.......................... $ 3,182,420 $ 248,569 $ 3,430,989
Future production costs...................... (1,773,397) (123,628) (1,897,025)
Future development costs..................... (382,412) (6,863) (389,275)
----------- --------- -----------
Future net inflows before income tax......... 1,026,611 118,078 1,144,689
Future income taxes.......................... (149,564) (25,237) (174,801)
----------- --------- -----------
Future net cash flows........................ 877,047 92,841 969,888
10% discount factor.......................... (366,050) (24,152) (390,202)
----------- --------- -----------
Standardized measure of discounted future net
cash flows................................ $ 510,997 $ 68,689 $ 579,686
=========== ========= ===========
</Table>
- ---------------
(1) Includes $162.8 million of undiscounted future asset retirement expenditures
estimated as of December 31, 2003, using current estimates of future
abandonment costs. At December 31, 2002 and at December 31, 2001 $168.9
million and $108.5 million, respectively, is included in undiscounted future
development costs for future abandonment costs. See Note 3 for corresponding
information regarding discounted asset retirement obligations.
F-40
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<Table>
<Caption>
DOMESTIC FOREIGN TOTAL
---------- -------- ----------
(IN THOUSANDS)
2003
Standardized measure -- beginning of year............... $1,077,633 $ 91,653 $1,169,286
Sales, net of production costs.......................... (177,748) (32,395) (210,143)
Purchases of reserves in-place.......................... 18,855 -- 18,855
Net change in prices and production costs............... 261,120 (17,894) 243,226
Extensions, discoveries and improved recovery, net of
future production and development costs.............. 31,001 -- 31,001
Changes in estimated future development costs........... (30,096) 1,428 (28,668)
Development costs incurred.............................. 37,499 1,206 38,705
Revisions of quantity estimates......................... 37,186 13,486 50,672
Accretion of discount................................... 130,558 12,127 142,685
Net change in income taxes.............................. (84,031) 12,036 (71,995)
Sales of reserves in-place.............................. (160,577) -- (160,577)
Changes in production rates and other................... (92,262) (9,437) (101,699)
---------- -------- ----------
Standardized measure -- end of year..................... $1,049,138 $ 72,210 $1,121,348
========== ======== ==========
2002
Standardized measure -- beginning of year............... $ 510,997 $ 68,689 $ 579,686
Sales, net of production costs.......................... (170,357) (21,368) (191,725)
Purchases of reserves in-place.......................... 119,143 -- 119,143
Net change in prices and production costs............... 560,784 45,408 606,192
Extensions, discoveries and improved recovery, net of
future production and development costs.............. 9,149 -- 9,149
Changes in estimated future development costs........... 29,946 449 30,395
Development costs incurred.............................. 31,123 1,527 32,650
Revisions of quantity estimates......................... 120,287 736 121,023
Accretion of discount................................... 51,100 7,782 58,882
Net change in income taxes.............................. (227,948) (20,484) (248,432)
Sales reserves in-place................................. (5,245) -- (5,245)
Changes in production rates and other................... 48,654 8,914 57,568
---------- -------- ----------
Standardized measure -- end of year..................... $1,077,633 $ 91,653 $1,169,286
========== ======== ==========
2001
Standardized measure -- beginning of year............... $1,149,562 $105,327 $1,254,889
Sales, net of production costs.......................... (154,785) (21,899) (176,684)
Purchases of reserves in-place.......................... 13,759 -- 13,759
Net change in prices and production costs............... (904,288) (56,360) (960,648)
Extensions, discoveries and improved recovery, net of
future production and development costs.............. 2,750 114 2,864
Changes in estimated future development costs........... (61,735) 16,455 (45,280)
Development costs incurred.............................. 62,817 16,100 78,917
Revisions of quantity estimates......................... 20,906 (25,804) (4,898)
Accretion of discount................................... 151,060 13,861 164,921
Net change in income taxes.............................. 361,041 24,150 385,191
Sales of reserves in-place.............................. -- -- --
Changes in production rates and other................... (130,090) (3,255) (133,345)
---------- -------- ----------
Standardized measure -- end of year..................... $ 510,997 $ 68,689 $ 579,686
========== ======== ==========
</Table>
F-41
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
16. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
<Table>
<Caption>
2003
------------------------------------------------
1ST QTR 2ND QTR 3RD QTR 4TH QTR YEAR
------- ------- ------- ------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Revenues.................................... $98,250 $94,521 $87,834 $90,732 $371,337
Income from operations...................... 32,947 32,966 23,380 25,398 114,691
Income from continuing operations........... 12,663 6,612 9,392 8,422 37,089
Income from discontinued operations, net of
income tax................................ 4,554 770 640 (70) 5,894
Cumulative effect of change in Accounting
Principle................................. 8,496 -- -- -- 8,496
Net Income.................................. 25,713 7,382 10,032 8,352 51,479
Basic earnings per share(1)
Continuing operations..................... $ 0.66 $ 0.34 $ 0.49 $ 0.43 $ 1.92
Discontinued operations................... 0.24 0.04 0.03 -- 0.30
Cumulative effect of change in Accounting
Principle net of income tax............ 0.44 -- -- -- 0.44
------- ------- ------- ------- --------
Net income................................ $ 1.34 $ 0.38 $ 0.52 $ 0.43 $ 2.66
======= ======= ======= ======= ========
Diluted earnings per share(1)
Continuing operations..................... $ 0.65 $ 0.34 $ 0.48 $ 0.42 $ 1.89
Discontinued operations................... 0.24 0.04 0.03 -- 0.30
Cumulative effect of change in Accounting
Principle net of income tax............ 0.44 -- -- -- 0.43
------- ------- ------- ------- --------
Net income................................ $ 1.33 $ 0.38 $ 0.51 $ 0.42 $ 2.62
======= ======= ======= ======= ========
</Table>
<Table>
<Caption>
2002(2)
---------------------------------------------------------------
1ST QTR 2ND QTR 3RD QTR 4TH QTR(3) YEAR
---------- ---------- ---------- ------------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Revenues................................... $70,968 $77,491 $84,250 $79,192 $311,901
Income from operations..................... 11,929 35,511 20,982 20,384 88,806
Income from continuing operations.......... 373 14,587 3,857 4,262 23,079
Income (loss) from discontinued operations,
net of income tax........................ 1,089 1,979 2,298 (16,170) (10,804)
Net Income (loss).......................... 1,462 16,566 6,155 (11,908) 12,275
Basic earnings (loss) per share(1)
Continuing operations.................... $ 0.02 $ 0.85 $ 0.22 $ 0.22 $ 1.31
Discontinued operations.................. 0.07 0.12 0.13 (0.84) (0.61)
------- ------- ------- ------- --------
Net income (loss)........................ $ 0.09 $ 0.97 $ 0.35 $ (0.62) $ 0.70
======= ======= ======= ======= ========
Diluted earnings (loss) per share(1)
Continuing operations.................... $ 0.01 $ 0.84 $ 0.22 $ 0.22 $ 1.30
Discontinued operations.................. 0.07 0.12 0.13 (0.84) (0.61)
------- ------- ------- ------- --------
Net income (loss)........................ $ 0.08 $ 0.96 $ 0.35 $ (0.62) $ 0.69
======= ======= ======= ======= ========
</Table>
- ---------------
(1) The sum of the individual quarterly net income (loss) per common share may
not agree with year-to-date net income (loss) per common share as each
quarterly computation is based on the weighted average number of common
shares outstanding during that period.
(2) Components of the 2002 quarters were revised due to a reclassification of
sold properties to discontinued operations.
(3) Fourth quarter 2002 results include a $17.8 million after-tax write down of
assets held for sale in discontinued operations.
F-42
INDEPENDENT AUDITORS' REPORT ON
CONSOLIDATED FINANCIAL STATEMENT SCHEDULE
To the Board of Directors and Stockholders
Nuevo Energy Company:
Under date of March 5, 2004, we reported on the consolidated balance sheets
of Nuevo Energy Company as of December 31, 2003 and 2002, and the related
consolidated statements of income, stockholders' equity, cash flows and
comprehensive income for each of the years in the three-year period ended
December 31, 2003. In connection with our audits of the aforementioned
consolidated financial statements, we also audited the related consolidated
financial statement schedule. This consolidated financial statement schedule is
the responsibility of the Company's management. Our responsibility is to express
an opinion on the consolidated financial statement schedule based on our audits.
In our opinion, the consolidated financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as a
whole, presents fairly, in all material respects, the information set forth
therein.
KPMG LLP
Houston, Texas
March 5, 2004
F-43
SCHEDULE II
NUEVO ENERGY COMPANY
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(IN THOUSANDS)
<Table>
<Caption>
ADDITIONS
------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
---------- ---------- ---------- ---------- ----------
2003
Allowance for doubtful accounts....... $ 626 $ 18 $ -- $ 428 $ 216
Valuation allowance on deferred
taxes.............................. 804 -- -- 804 --
2002
Allowance for doubtful accounts....... 1,280 -- -- 654 626
Valuation allowance on deferred
taxes.............................. 1,777 -- -- 973 804
2001
Allowance for doubtful accounts....... 766 1,314 -- 800 1,280
Valuation allowance on deferred
taxes.............................. 1,777 -- -- -- 1,777
</Table>
F-44
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS
On February 12, 2004, Plains Exploration & Production Company, or Plains,
and Nuevo Energy Company, or Nuevo, announced they had entered into a definitive
agreement pursuant to which Plains will acquire Nuevo in a stock for stock
transaction. If completed, Plains will issue up to 38.8 million shares to Nuevo
shareholders and assume $234 million of net debt (as of December 31, 2003) and
$115 million of TECONs. Under the terms of the transaction, Nuevo stockholders
will receive 1.765 shares of Plains common stock for each share of Nuevo common
stock.
The following unaudited pro forma combined financial information shows the
pro forma effect of the merger. The unaudited pro forma combined statement of
income for the year ended December 31, 2003 has been prepared based on the
historical consolidated statements of income of Plains and Nuevo under the
assumptions set forth in the accompanying footnotes. The unaudited pro forma
combined balance sheet as of December 31, 2003 has been prepared based on the
historical consolidated balance sheets of Plains and Nuevo under the assumptions
set forth in the accompanying footnotes. This transaction has been accounted for
using the purchase method of accounting. The effect of this transaction is
reflected in the merger adjustments in the unaudited pro forma combined
statements of income.
The pro forma effects of the following transactions are presented in Note 4
to the pro forma combined financial statements:
o Plains acquisition of 3TEC Energy Corporation which was completed on
June 4, 2003; and
o Plains issuance of $75 million of 8.75% senior subordinated notes on
May 30, 2003.
The unaudited pro forma combined statement of income for the year ended
December 31, 2003 assumes the Nuevo merger transaction, 3TEC merger transaction
and the new notes offering occurred on January 1, 2003. Plains believes the
assumptions used provide a reasonable basis for presenting the significant
effects directly attributable to such transactions.
Plains has not reflected as an adjustment to the historical data annual
cost savings of at least $20 million that Plains and Nuevo expect to result from
the merger.
The unaudited pro forma combined financial statements do not purport to
represent what Plains results of operations would have been if such transactions
had occurred on such dates. These unaudited pro forma combined financial
statements should be read in conjunction with the Form 10-K of Plains for the
year ended December 31, 2003, the Consolidated Financial Statements and
Management's Discussion and Analysis of Financial Condition and Results of
Operations of 3TEC included in Plains Registration Statement on Form S-4 (No.
333-108407) filed August 29, 2003, and the Form 10-K of Nuevo for the year ended
December 31, 2003.
F-45
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED PRO FORMA COMBINED BALANCE SHEET
AT DECEMBER 31, 2003
(IN THOUSANDS OF DOLLARS)
PLAINS MERGER PLAINS
HISTORICAL ADJUSTMENTS(a) PROFORMA
----------- -------------- -----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents ........................... $ 1,377 $ 6,276 $ 7,653
Accounts receivable ................................. 50,611 39,729 90,340
Assets held for sale ................................ -- 38,290 38,290
Inventories ......................................... 5,318 5,741 11,059
Other current assets ................................ 3,019 4,489 7,508
----------- ----------- -----------
60,325 94,525 154,850
----------- ----------- -----------
PROPERTY AND EQUIPMENT, AT COST
Oil and natural gas properties--full cost method
Subject to amortization ............................. 1,074,302 1,037,995 2,112,297
Not subject to amortization ......................... 63,658 -- 63,658
Other property and equipment ........................ 4,939 -- 4,939
----------- ----------- -----------
1,142,899 1,037,995 2,180,894
Allowance for depreciation, depletion and
amortization ...................................... (186,004) -- (186,004)
----------- ----------- -----------
956,895 1,037,995 1,994,890
----------- ----------- -----------
GOODWILL .............................................. 147,251 239,525 386,776
----------- ----------- -----------
OTHER ASSETS .......................................... 19,641 5,425 25,066
----------- ----------- -----------
$ 1,184,112 $ 1,377,470 $ 2,561,582
=========== =========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities ...... $ 79,750 $ 94,968 $ 174,718
Commodity hedging contracts ......................... 55,123 35,005 90,128
Royalties payable ................................... 19,080 5,312 24,392
Interest payable .................................... 622 3,663 4,285
Current maturities on long-term debt ................ 511 -- 511
----------- ----------- -----------
155,086 138,948 294,034
----------- ----------- -----------
LONG-TERM DEBT ........................................ 487,906 401,713 889,619
----------- ----------- -----------
ASSET RETIREMENT OBLIGATION ........................... 33,235 137,925 171,160
----------- ----------- -----------
OTHER LONG-TERM LIABILITIES ........................... 32,194 12,067 44,261
----------- ----------- -----------
DEFERRED INCOME TAXES ................................. 121,435 97,934 219,369
----------- ----------- -----------
STOCKHOLDERS' EQUITY
Stockholders' equity ................................ 394,695 588,883 983,578
Accumulated other comprehensive income (loss) ....... (40,439) -- (40,439)
----------- ----------- -----------
354,256 588,883 943,139
----------- ----------- -----------
$ 1,184,112 $ 1,377,470 $ 2,561,582
=========== =========== ===========
F-46
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED PRO FORMA COMBINED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 2003
(IN THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
COMBINED
COMPANY
PLAINS PRO NUEVO MERGER PROFORMA
FORMA HISTORICAL ADJUSTMENTS ADJUSTED
---------- ---------- ----------- ---------
REVENUES
Oil, gas and plant revenues .............................. $ 376,797 $ 369,975 $ -- $ 746,772
Other operating revenues ................................. 888 1,362 -- 2,250
--------- --------- --------- ---------
377,685 371,337 -- 749,022
--------- --------- --------- ---------
COSTS AND EXPENSES:
Production expenses ...................................... 118,205 159,832 -- 278,037
Exploration costs ........................................ -- 2,115 (2,115)(b) --
General and administrative ............................... 29,424 28,457 -- 57,881
Stock appreciation rights ................................ 18,010 -- -- 18,010
Gain on disposition of properties ........................ -- (5,824) 4,551 (c) (1,273)
Depreciation, depletion, amortization and accretion ...... 64,999 70,810 47,623 (d) 183,432
Other .................................................... 1,256 -- 1,256
--------- --------- --------- ---------
230,638 256,646 50,059 537,343
--------- --------- --------- ---------
INCOME FROM OPERATIONS 147,047 114,691 (50,059) 211,679
OTHER INCOME (EXPENSE):
Interest expense ......................................... (27,075) (36,406) 1,612 (e) (61,869)
Gain (loss) on derivatives ............................... (37,084) (5,842) -- (42,926)
Loss on early extinguishment of debt ..................... -- (12,578) -- (12,578)
Interest and other income (expense) ...................... (100) 342 -- 242
--------- --------- --------- ---------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES ...... 82,788 60,207 (48,447) 94,548
Income tax benefit (expense) ............................. (34,342) (23,118) 16,083 (f) (41,377)
--------- --------- --------- ---------
INCOME FROM CONTINUING OPERATIONS .......................... $ 48,446 $ 37,089 $ (32,364) $ 53,171
========= ========= ========= =========
Earnings per share
Basic .................................................... $ 1.21 $ 1.92 -- $ 0.69
Diluted .................................................. $ 1.20 $ 1.89 -- $ 0.69
Average shares outstanding
Basic .................................................... 40,190 19,355 17,141 76,686
Diluted .................................................. 40,256 19,627 17,363 77,246
F-47
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS
NOTE 1--BASIS OF PRESENTATION AND ACCOUNTING FOR THE MERGER
The accompanying unaudited pro forma balance sheet and unaudited pro forma
statement of income presents the pro forma effects of the merger and the
transactions. The unaudited pro forma balance sheet is presented as though the
merger occurred on December 31, 2003. The unaudited pro forma combined statement
of income for year ended December 31, 2003 assumes the merger occurred on
January 1, 2003.
The merger has been accounted for using the purchase method of accounting
for business combinations. Under the purchase method of accounting, Nuevo's
assets and liabilities acquired or assumed are revalued and recorded at their
estimated fair values.
Plains follows the full cost method of accounting for oil and gas
properties while Nuevo follows the successful efforts method of accounting.
Certain costs that are capitalized under the full cost method are expensed under
the successful efforts method. These costs consist primarily of costs associated
with unsuccessful exploration drilling, geological and geophysical costs and
general and administrative costs associated with acquisition, exploration,
exploitation and development activities. Under full cost accounting proceeds
from the sale of oil and gas properties are reflected as reductions to
capitalized costs unless such sales involve a significant change in the
relationship between costs and the estimated value of proved reserves, in which
case a gain or loss is recognized. Pro forma entries include the
reclassification of certain of these items to conform Nuevo's accounting to the
full cost method.
NOTE 2--PRO FORMA ADJUSTMENTS RELATED TO THE MERGER
The unaudited pro forma balance sheet includes the following adjustments:
(a) This entry reflects the estimated preliminary pro forma allocation
of the purchase price as of December 31, 2003 using the purchase method of
accounting. The following is a calculation and allocation of the purchase
price to assets acquired and liabilities assumed based on their relative
fair value (in thousands, except as noted):
Shares of Plains common stock to be issued ........................... 36,496
Average Plains stock price ........................................... $ 15.76
----------
Fair value of Plains common stock to be issued ....................... $ 575,177
Fair value of Nuevo employee stock options to be assumed by Plains ... 13,706
Estimated merger expenses ............................................ 32,000
----------
Total purchase price before liabilities assumed ...................... 620,883
Fair value of liabilities:
Senior Subordinated Notes .......................................... 244,313
Bank Credit Facility ............................................... 15,000
TECONs ............................................................. 110,400
Current liabilities ................................................ 138,948
Other noncurrent liabilities ....................................... 12,067
Deferred income tax liabilities .................................... 97,934
Asset retirement obligation ........................................ 137,925
----------
Total purchase price plus liabilities assumed ........................ $1,377,470
==========
Fair value of assets acquired:
Current assets ....................................................... 94,525
Proved oil and gas properties ........................................ 1,037,995
Other noncurrent assets .............................................. 5,425
Goodwill ............................................................. 239,525
----------
$1,377,470
==========
F-48
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS--(CONTINUED)
The purchase price includes the value of Plains common stock to be issued
to Nuevo stockholders in the merger. The average Plains common stock price is
based on the average closing prices of Plains common stock during the five
business day period commencing two days before the merger was announced. Under
the terms of the merger agreement, Nuevo common stockholders will receive 1.765
shares of Plains common stock for each share of Nuevo common stock. It is
expected that Plains will issue 35.8 million common shares based on Nuevo's
outstanding common shares on February 12, 2004.
At least 30 days prior to the effective time of the merger, Nuevo will give
each holder of its restricted common stock issued pursuant to its stock
incentive or other equity award plans the opportunity to elect to have each such
share cancelled and redeemed immediately prior to the merger at the Nuevo market
price. However, at Plains' election, Plains may make such redemption payments to
named executives of Nuevo immediately after the merger. At the effective time of
the merger, each share of uncancelled Nuevo restricted stock will become 1.765
shares of restricted common stock of Plains on the same terms and conditions of
vesting as such Nuevo restricted stock. On a pro forma basis, Plains would issue
0.7 million common shares based on Nuevo's outstanding restricted shares on
February 12, 2004. If all outstanding restricted Nuevo common shares are
cancelled and redeemed, cash consideration of approximately $11.9 million would
be paid to restricted shareholders based on a Nuevo share price of $30.75, the
closing price on March 8, 2004. The accompanying pro forma statements assume
that no Nuevo restricted shares are redeemed prior to the merger.
At least 30 days prior to the effective time of the merger, Nuevo will give
each holder of any employee or director stock option of Nuevo the opportunity to
have each such option cancelled and redeemed immediately prior to the merger.
Upon consummation of the merger, Plains will assume each uncancelled option and
each such option will become an option (i) to purchase that number of shares of
Plains common stock obtained by multiplying the number of shares of Nuevo common
stock issuable upon the exercise of such option by 1.765, (ii) at an exercise
price per share equal to the per share exercise price of such option divided by
1.765, and (iii) otherwise upon the same terms and conditions as such
outstanding options. The accompanying pro forma statements assume that no Nuevo
stock options are redeemed prior to the merger, and that Plains issues 2.3
million options with an average exercise price of $10.59. If all outstanding
Nuevo stock options are cancelled and redeemed, cash consideration of
approximately $17.1 million would be paid to option holders based on a Nuevo
share price of $30.75, the closing price on March 8, 2004. The accompanying pro
forma statements assume that no Nuevo stock options are redeemed prior to the
merger.
If all restricted stock and stock options are redeemed for cash prior to
the closing of the merger, pro forma income from continuing operations would be
$52.7 million compared to the $53.2 million presented in the accompanying
statements for the year ended December 31, 2003. The earnings per share amounts
would not change.
The total purchase price also includes $32 million of estimated merger
costs. These costs include investment banking expenses, severance, legal and
accounting fees, printing expenses and other merger-related costs. These costs
have been added to long-term debt in the unaudited pro forma balance sheet.
The preliminary allocation of purchase price includes approximately $240
million of goodwill. Approximately $98 million of the goodwill is related to
deferred income tax liabilities to be recorded due to the non-taxable nature of
the merger. The significant factors that contributed to the recognition of
F-49
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS--(CONTINUED)
goodwill include but are not limited to expected economies of scale in
connection with our existing operations, improved financial flexibility with
more efficient access to lower cost capital and the ability to acquire an
established business with an assembled workforce.
The purchase price is preliminary and is subject to change due to several
factors including:
o Changes in the fair values of Nuevo's assets and liabilities as of the
effective time of the merger;
o The number of Nuevo common and restricted shares and stock options
outstanding as of the effective time of the merger;
o Actual merger costs incurred; and
o Tax basis of Nuevo assets at the effective time of the merger.
The unaudited pro forma statements of income include the following
adjustments:
(b) This entry reflects the reversal of Nuevo historical exploration
costs that are expensed under the successful efforts methods of accounting
and are capitalized under the full cost method of accounting.
(c) This entry reflects the reversal of the gain on disposition of oil
and gas properties and assets held for sale. Under full cost accounting,
proceeds from the sale of oil and gas properties are accounted for as
reductions to capitalized costs unless such sales involve a significant
change in the relationship between costs and the estimated value of proved
reserves, in which case a gain or loss is recognized. The remaining gain on
disposition of property relates to sales of non oil and gas properties.
(d) This entry adjusts depreciation, depletion, amortization and
accretion expense based on the fair value allocated to oil and gas
properties. Pro forma depreciation, depletion, amortization and accretion
for the combined company is calculated using the unit of production method
based on the oil and gas property costs, reserve volumes and future
development and abandonment costs of the combined companies. The pro forma
depreciation, depletion, amortization and accretion rate is $5.25 per
barrel of oil equivalent. Accretion expense has been adjusted to reflect
Plains' credit adjusted risk free interest rate and other assumptions.
(e) This entry adjusts historical interest expense for the effect of
debt assumed and incurred in connection with the merger.
(f) This entry reflects the adjustment of income tax expense based on
a post-merger effective rate of approximately 42% (44% including return to
provision adjustments included in Plains' historical income tax expense for
the year ended December 31, 2003).
F-50
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 3 - EARNINGS PER SHARE
Earnings per share for the year ended December 31, 2003 has been calculated
based on the pro forma weighted average number of shares outstanding as follows:
Year Ended
December 31,
2003
---------------
Weighted average shares outstanding .................................. 33,321
Pro forma increase assuming 3TEC merger occurred January 1, 2003 ..... 6,869
Nuevo outstanding shares ............................................. 20,678
Exchange ratio ....................................................... 1.765 36,497
------ ------
Pro forma basic shares outstanding ................................... 76,687
Plains restricted shares ............................................. 148
Nuevo options ........................................................ 411
------
Pro forma diluted shares outstanding ................................. 77,246
======
Diluted shares do not include the following because the inclusion would be
anti-dilutive:
YEAR ENDED
DECEMBER 31,
2002
------------
Shares issuable upon conversion of TECONs ............................ 3,419
Nuevo employee stock options with an exercise price greater than
the average market price of the common stock ....................... 477
NOTE 4 - PLAINS PRO FORMA RESULTS OF OPERATIONS
Plains' pro forma results of operations included in the accompanying
unaudited pro forma statement of operations include the effect of the following:
o Plains acquisition of 3TEC Energy Corporation which was completed on
June 4, 2003; and
o Plains issuance of $75 million of 8.75% senior subordinated notes on
May 30, 2003.
On June 4, 2003 Plains acquired 3TEC for approximately $312.9 million in
cash and common stock plus $90.0 million to retire outstanding debt and $14.7
million to retire outstanding 3TEC preferred stock. Under the terms of the
agreement 3TEC stockholders received $8.50 in cash and 0.85 shares of our common
stock for each share of 3TEC common stock. This transaction has been accounted
for using the purchase method of accounting. The effect of this transaction is
reflected in the 3TEC Merger Adjustments in the unaudited pro forma consolidated
statements of income.
The unaudited pro forma combined statement of income for the year ended
December 31, 2003 assumes the 3TEC merger transactions and the $75 million notes
offering occurred on January 1, 2003. Plains believes the assumptions used
provide a reasonable basis for presenting the significant effects directly
attributable to such transactions.
F-51
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 2003
(IN THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
PLAINS PLAINS
PLAINS OFFERING PRO FORMA 3TEC MERGER PRO FORMA
HISTORICAL ADJUSTMENTS OFFERING HISTORICAL(4) ADJUSTMENTS ADJUSTED
---------- ----------- ---------- ------------- ----------- ---------
REVENUES
Oil, gas and plant revenues ..... $ 303,202 $ -- $ 303,202 $ 73,664 $ (69)(5) $ 376,797
Gain (loss) on sale of
properties .................... -- -- -- 72 (72)(10) --
Gain (loss) on derivatives ...... -- -- -- (37,931) 37,931(12) --
Other operating revenues ........ 888 -- 888 59 (59)(12) 888
--------- --------- --------- --------- --------- ---------
304,090 -- 304,090 35,864 37,731 377,685
--------- --------- --------- --------- --------- ---------
COSTS AND EXPENSES
Production expenses ............. 104,819 -- 104,819 13,386 -- 118,205
Geological and geophysical ...... -- -- -- 5,023 (5,023)(10) --
Dry hole and impairments ........ -- -- -- 2,198 (2,198)(10) --
General and administrative ...... 25,148 -- 25,148 4,539 (263)(10) 29,424
Stock appreciation rights ....... 18,010 -- 18,010 -- -- 18,010
(17,954)(6)
Depreciation, depletion, 11,707(7)
amortization and accretion .... 52,484 32(1) 52,516 18,313 417(13) 64,999
--------- --------- --------- --------- --------- ---------
200,461 32 200,493 43,459 (13,314) 230,638
--------- --------- --------- --------- --------- ---------
INCOME FROM OPERATIONS ............ 103,629 (32) 103,597 (7,595) 51,045 147,047
OTHER INCOME (EXPENSE)
1,336(8)
Interest expense .................. (23,778) (2,408)(2) (26,186) (1,336) (889)(9) (27,075)
Gain (loss) on derivatives ........ 847 -- 847 -- (37,931)(12) (37,084)
Merger costs ...................... -- -- -- (11,108) 11,108(11) --
14(10)
Interest and other income
(expense) ....................... (159) -- (159) (14) 59(12) (100)
--------- --------- --------- --------- --------- ---------
INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES .. 80,539 (2,440) 78,099 (20,053) 24,742 82,788
Income tax benefit (expense) ...... (33,452) 965(3) (32,487) 7,820 (9,675)(14) (34,342)
--------- --------- --------- --------- --------- ---------
INCOME FROM CONTINUING
OPERATIONS ...................... $ 47,087 $ (1,475) $ 45,612 $ (12,233) $ 15,067 $ 48,446
========= ========= ========= ========= ========= =========
Earnings Per Share:
Basic ............................. $ 1.41 $ 1.21
========= =========
Diluted ........................... $ 1.41 $ 1.20
========= =========
Average Shares Outstanding:
Basic ............................. 33,321 6,869(15) 40,190
Diluted ........................... 33,469 6,787(15) 40,256
- ----------
Offering Adjustments
(1) Reflects amortization of debt issue costs for the period, on a straight
line basis that approximates the interest method, over the life of the
8.75% Notes.
(2) Reflects interest expense at a rate of 7.71% (net of premium on issuance)
for the period on the new notes, assuming that the new notes were issued on
January 1, 2003. A 1/8 of 1% change in the interest rate would result in a
$39,000 change in interest expense.
(3) Reflects the income tax effect of the Offering Adjustments based on Plains'
historical effective income tax rate.
F-52
Merger Adjustments
(4) 3TEC's historical results of operations for the five months ended May 31,
2003.
(5) Reflects the $0.20 per barrel marketing fee Plains pays to Plains All
American Pipeline, L.P.
(6) Reflects the reversal of 3TEC's historical DD&A expense related to oil and
gas properties.
(7) Reflects the effect of the merger on DD&A expense on oil and gas properties
under the full cost method.
(8) Reflects the reversal of 3TEC's amortization of deferred debt issue costs
and interest expense with respect to 3TEC's debt that was retired in the
merger.
(9) Reflects interest expense for the period on $189.2 million of debt incurred
in connection with the acquisition net of $1.6 million of capitalized
interest. Interest expense is based on an estimated borrowing rate under
Plains' senior revolving credit facility (3.1%). Capitalized interest is
based on the $61.1 million of purchase price allocated to oil and gas
properties not subject to amortization and Plains' effective average
interest rate (6.0% based on pro forma debt). A 1/8% change in the interest
rate would result in a $0.1 million change in interest expense.
(10) Reflects the reversal of certain 3TEC's income items that are charged or
credited to income under the successful efforts method of accounting that
are capitalized under the full cost method of accounting.
(11) Reflects the reversal of 3TEC expenses related to the merger.
(12) Reflects the reclassification of certain 3TEC revenue and expense items to
conform to the Plains presentation.
(13) Reflects amortization of estimated debt issue cost for the period, on a
straight-line basis that approximates the interest method over the life of
the agreement.
(14) Reflects the adjustment of income tax expense based on a post-merger
effective rate for current year earnings of approximately 41%.
(15) Reflects common shares issued in the 3TEC merger.
F-53
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Company has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
PLAINS EXPLORATION & PRODUCTION COMPANY
Date: March 17, 2004 By: /s/ CYNTHIA A. FEEBACK
------------------------------------
Cynthia A. Feeback
Senior Vice President--Accounting
and Treasurer
EXHIBIT INDEX
Exhibit
Number Description
------- -----------
23.1 Consent of KPMG LLP.