PLAINS EXPLORATION & PRODUCTION CO - 10-Q Quarterly Report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2004

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-31470

PLAINS EXPLORATION & PRODUCTION COMPANY

(Exact name of registrant as specified in its charter)

Delaware

33-0430755

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

700 Milam Street, Suite 3100

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(832) 239-6000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes x No ¨

77.1 million shares of Common Stock, $0.01 par value, issued and outstanding at October 29, 2004.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


PART I. FINANCIAL INFORMATION

Item 1. Unaudited Financial Statements:

Consolidated Balance Sheets September 30, 2004 and December 31, 2003		1
Consolidated Statements of Operations For the three months and nine months ended September 30, 2004 and 2003		2
Consolidated Statements of Cash Flows For the nine months ended September 30, 2004 and 2003		3
Consolidated Statements of Comprehensive Income For the three months and nine months ended September 30, 2004 and 2003		4
Consolidated Statement of Changes in Stockholders’ Equity For the nine months ended September 30, 2004		5
Notes to Consolidated Financial Statements		6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		28

Item 3. Quantitative and Qualitative Disclosures About Market Risk		43

Item 4. Controls and Procedures		45

PART II. OTHER INFORMATION		46

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)


	September 30, 2004			December 31, 2003
ASSETS
Current Assets
Cash and cash equivalents	$	1,790		$	1,377
Accounts receivable—Plains All American Pipeline, L.P.		27,747			25,344
Other accounts receivable		91,777			25,267
Inventories		6,831			5,318
Deferred income taxes		90,718			21,807
Assets held for sale		43,612			—
Other current assets		9,615			3,019

		272,090			82,132

Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		2,420,467			1,074,302
Not subject to amortization		180,356			63,658
Other property and equipment		10,253			4,939

		2,611,076			1,142,899
Less allowance for depreciation, depletion and amortization		(272,972	)		(186,004	)

		2,338,104			956,895

Goodwill		221,499			147,251

Other Assets		30,087			19,641

	$	2,861,780		$	1,205,919

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	89,528		$	41,736
Commodity derivative contracts		274,749			55,123
Royalties payable		41,456			19,080
Stock appreciation rights		32,711			16,049
Interest payable		11,189			622
Deposit on assets held for sale		40,711			—
Other current liabilities		30,917			22,476

		521,261			155,086

Long-Term Debt
8.75% Senior Subordinated Notes		276,773			276,906
7.125% Senior Notes		248,718			—
Revolving credit facility		263,000			211,000

		788,491			487,906

Asset Retirement Obligation		163,144			33,235

Commodity Derivative Contracts		234,312			23,697

Other Long-Term Liabilities		7,962			8,497

Deferred Income Taxes		355,164			143,242

Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common stock		772			403
Additional paid-in capital		910,281			322,856
Retained earnings		52,879			71,566
Accumulated other comprehensive income		(172,091	)		(40,439	)
Treasury stock		(395	)		(130	)

		791,446			354,256

	$	2,861,780		$	1,205,919

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(in thousands, except per share data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	69,173		$	58,903		$	196,459		$	178,496
Other oil sales		122,540			5,366			185,722			7,002
Oil hedging		(43,046	)		(11,595	)		(84,679	)		(37,863	)
Gas sales		62,012			37,011			159,235			57,240
Gas hedging		(1,185	)		5,437			(2,246	)		5,436
Other operating revenues		867			260			1,601			667

		210,361			95,382			456,092			210,978

Costs and Expenses
Production costs
Lease operating expenses		44,501			18,606			92,066			49,168
Steam gas costs		14,309			686			22,620			2,147
Electricity		9,207			5,307			21,720			15,635
Production and ad valorem taxes		6,565			3,893			15,118			6,749
Gathering and transportation expenses		2,581			969			5,567			1,296
General and administrative
G&A excluding items below		12,073			5,517			30,916			14,274
Stock appreciation rights		15,023			4,670			28,449			7,317
Merger related costs		2,430			2,007			3,475			3,104
Depreciation, depletion, amortization and accretion		45,807			16,201			94,242			35,327

		152,496			57,856			314,173			135,017

Income from Operations		57,865			37,526			141,919			75,961
Other Income (Expense)
Interest expense		(10,969	)		(6,936	)		(26,506	)		(17,130	)
Debt extinguishment costs		—			(224	)		(19,691	)		(224	)
Gain (loss) on mark-to-market derivative contracts		(124,651	)		1,741			(125,842	)		3,207
Interest and other income		364			234			669			67

Income (Loss) Before Income Taxes and Cumulative Effect of Accounting Change		(77,391	)		32,341			(29,451	)		61,881
Income tax expense
Current		(463	)		(271	)		(607	)		(2,700	)
Deferred		29,876			(14,526	)		11,371			(24,134	)

Income (Loss) Before Cumulative Effect of Accounting Change		(47,978	)		17,544			(18,687	)		35,047
Cumulative effect of accounting change, net of tax		—			—			—			12,324

Net Income (Loss)	$	(47,978	)	$	17,544		$	(18,687	)	$	47,371

Earnings (Loss) Per Share (in dollars)
Basic
Income (loss) before cumulative effect of accounting change	$	(0.62	)	$	0.44		$	(0.32	)	$	1.13
Cumulative effect of accounting change		—			—			—			0.40

	$	(0.62	)	$	0.44		$	(0.32	)	$	1.53

Diluted
Income (loss) before cumulative effect of accounting change	$	(0.62	)	$	0.43		$	(0.32	)	$	1.12
Cumulative effect of accounting change		—			—			—			0.39

	$	(0.62	)	$	0.43		$	(0.32	)	$	1.51

Weighted Average Shares Outstanding
Basic		76,977			40,106			59,008			31,029
Diluted		76,977			40,726			59,008			31,415

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)


	Nine Months Ended September 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(18,687	)	$	47,371
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		94,242			35,327
Deferred income taxes		(11,371	)		24,134
Debt extinguishment costs		(4,453	)		—
Cumulative effect of adoption of accounting change		—			(12,324	)
Commodity derivative contracts
Loss (gain) on derivatives		66,206			(10,257	)
Reclassify financing derivative settlements		61,274			—
Noncash compensation
Stock appreciation rights		17,884			5,830
Other		6,736			2,069
Other noncash items		(92	)		352
Change in assets and liabilities from operating activities, net of effect of acquisitions		38,430			(4,555	)

Net cash provided by operating activities		250,169			87,947

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(142,099	)		(95,024	)
Acquisition of Nuevo Energy Company, net of cash acquired		(14,156	)		—
Acquisition of 3TEC Energy Corporation, net of cash acquired		—			(267,197	)
Proceeds from sales of properties		85,892			8,517
Other property and equipment		(5,739	)		(1,759	)

Net cash used in investing activities		(76,102	)		(355,463	)

CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		762,950			438,600
Repayments		(710,950	)		(248,200	)
Proceeds from issuance of 7.125% Senior Notes		248,695			—
Proceeds from issuance of 8.75% Senior Subordinated Notes		—			80,061
Retirement of debt assumed in acquisition of Nuevo Energy Company		(405,000	)		—
Costs incurred in connection with financing arrangements		(8,988	)		(4,143	)
Derivative settlements		(61,274	)		—
Other		913			174

Net cash (used in) provided by financing activities		(173,654	)		266,492

Net increase (decrease) in cash and cash equivalents		413			(1,024	)
Cash and cash equivalents, beginning of period		1,377			1,028

Cash and cash equivalents, end of period		1,790			4

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(in thousands of dollars)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Net Income (Loss)	$	(47,978	)	$	17,544		$	(18,687	)	$	47,371

Other Comprehensive Income (Loss)
Commodity hedging contracts, net of tax
Change in fair value		(110,721	)		(795	)		(186,495	)		(18,332	)
Reclassification adjustment for settled contracts		29,160			3,648			54,753			19,213
Other, net of tax		30			31			90			107

		(81,531	)		2,884			(131,652	)		988

Comprehensive Income (Loss)	$	(129,509	)	$	20,428		$	(150,339	)	$	48,359

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)


	Common Stock			Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income			Treasury Stock					Total
	Shares	Amount		Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income			Shares		Amount			Total
Balance, December 31, 2003	40,316	$	403	$	322,856	$	71,566		$	(40,439	)	(17	)	$	(130	)	$	354,256
Acquisition of Nuevo Energy Company
Issuance of common stock	36,486		365		574,658		—			—		—			—			575,023
Other	—		—		4,389		—			—		—			—			4,389
Net income (loss)	—		—		—		(18,687	)		—		—			—			(18,687	)
Other comprehensive income	—		—		—		—			(131,652	)	—			—			(131,652	)
Restricted stock awards	235		3		5,728		—			—		—			—			5,731
Additions to treasury stock	—		—		—		—			—		(15	)		(265	)		(265	)
Other	122		1		2,650		—			—		—			—			2,651

Balance, September 30, 2004	77,159	$	772	$	910,281	$	52,879		$	(172,091	)	(32	)	$	(395	)	$	791,446

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1—Organization and Significant Accounting Policies

Organization

The consolidated financial statements of Plains Exploration & Production Company (“Plains”, “PXP”, “us”, “our”, or “we”) include the accounts of our wholly owned subsidiaries. We are an independent energy company engaged in the “upstream” oil and gas business of acquiring, exploiting, developing, exploring for and producing oil and gas. Our activities are all located in the United States.

These consolidated financial statements and related notes present our consolidated financial position as of September 30, 2004 and December 31, 2003, the results of our operations and our comprehensive income for the three months and nine months ended September 30, 2004 and 2003, our cash flows for the nine months ended September 30, 2004 and 2003 and the changes in our stockholders’ equity for the nine months ended September 30, 2004. All adjustments, consisting only of normal recurring adjustments, that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior year statements to conform to the current year presentation. The results for the three months and nine months ended September 30, 2004, are not necessarily indicative of the final results to be expected for the full year.

These financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America for complete financial statements and should be read in conjunction with the audited consolidated financial statements included in our Annual Report on Form 10-K/A for the year ended December 31, 2003.

Accounting Policies

Asset Retirement Obligations. Effective January 1, 2003, we adopted Statement of Accounting Standards (SFAS) No. 143 “Accounting for Asset Retirement Obligations” (SFAS 143) which requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. When the liability is initially recorded, the entity is required to capitalize the retirement cost of the related long-lived asset. Each period the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is reflected in oil and gas properties. In prior periods we included estimated future costs of abandonment and dismantlement in our full cost amortization base and these costs were amortized as a component of our depletion expense.

At January 1, 2003, the present value of our future asset retirement obligation (ARO) for oil and gas properties and equipment was $26.5 million. The cumulative effect of our adoption of SFAS 143 and the change in accounting principle resulted in an increase in net income during 2003 of $12.3 million (reflecting a $30.8 million decrease in accumulated depreciation, depletion and amortization, partially offset by $10.6 million in accretion expense, and $7.9 million in income taxes). We recorded a liability of $26.5 million and an asset of $15.9 million in connection with the adoption of SFAS 143. Adopting SFAS 143 did not impact our cash flows.

The following table illustrates the changes in our asset retirement obligation (ARO) during the periods (in thousands):


	Nine Months Ended September 30,
	2004			2003
Asset retirement obligation—beginning of period	$	33,735		$	26,540
Liabilities incurred
Nuevo acquisition		128,053			—
3TEC acquisition		—			4,577
Other		386			579
Accretion expense		5,591			1,906
Asset retirement cost of properties sold		(3,647	)		(654	)

Asset retirement obligation—end of period	$	164,118	⁽¹⁾	$	32,948

(1)

$974 included in current liabilities.

Goodwill. In 2004, as a result of our acquisitions of Nuevo Energy Company (“Nuevo”) (see Note 2) and 3TEC Energy Corporation (“3TEC”), goodwill increased by $76.5 million and $0.2 million, respectively. As a result of the sale of our Illinois properties in the first quarter of 2004, goodwill was decreased by $2.4 million which was considered in the disposition and recognized as an adjustment to oil and gas properties subject to amortization.

Stock-based Employee Compensation. SFAS 123 “Accounting for Stock-Based Compensation” (SFAS 123), as amended by SFAS 148 “Accounting for Stock Based Compensation—Transition and Disclosure”, established financial accounting and reporting standards for stock-based employee compensation. SFAS 123 defines a fair value based method of accounting for an employee stock option or similar equity instrument. SFAS 123 also allows an entity to continue to measure compensation cost for those instruments using the intrinsic value-based method of accounting prescribed by Accounting Principles Bulletin No. 25 “Accounting for Stock Issued to Employees” (APB 25). We have elected to follow APB 25 and related interpretations in accounting for our stock-based employee compensation. The compensation expense recorded under APB 25 for our stock appreciation rights and restricted stock awards is the same as that determined under SFAS 123.

All of our stock options consist of vested stock options assumed in the Nuevo acquisition, accordingly, no compensation expense will be recognized on such options.

Earnings Per Share. For the three months and nine months ended September 30, 2004 and 2003 the weighted average shares outstanding for computing basic and diluted earnings per share were (in thousands):


	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
Common shares outstanding—basic	76,977	40,106	59,008	31,029
Unvested restricted stock, restricted stock units and stock options	—	620	—	386

Common shares outstanding—diluted	76,977	40,726	59,008	31,415

In 2004 our unvested restricted stock, restricted stock units and stock options were not included in computing earnings per share because the effect was antidilutive. In computing earnings per share, no adjustments were made to reported net income.

Inventory. Oil inventories are carried at the lower of the cost to produce or market value. Materials and supplies inventory is stated at the lower of cost or market with cost determined on an average cost method. Inventory consists of the following (in thousands):


	September 30, 2004		December 31, 2003
Materials and supplies	$	5,982	$	4,455
Oil		849		863

	$	6,831	$	5,318

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include (1) oil and natural gas reserves; (2) depreciation, depletion and amortization, including future abandonment costs; (3) assigning fair value and allocating purchase price in connection with business combinations, including goodwill; (4) income taxes; (5) accrued liabilities; and (6) valuation of derivative instruments. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Recent Accounting Pronouncements. In September 2004 the SEC published Staff Accounting Bulletin No. 106 (SAB 106), which is effective January 1, 2005. SAB 106 relates to the Staff’s views regarding the application of SFAS 143 by oil and gas producing companies following the full cost accounting method. SAB 106 requires that the future outflows associated with settling AROs that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling test calculation. SAB 106 also requires that to the extent that estimated dismantlement and abandonment costs, net of estimated salvage values, have not been included as capitalized costs in the base for computing depletion, depreciation and amortization (DD&A) because they have not yet been capitalized as asset retirement costs under SFAS 143, such costs that will be incurred as a result of future development activities on proved reserves should be estimated and included in the costs to be amortized. We are currently evaluating the guidelines with respect to our full cost ceiling test calculation and the computation of our DD&A rates. We do not believe any required changes in our calculations would have resulted in a ceiling test writedown at September 30, 2004 or a significant change in our DD&A expense.

Note 2—Acquisition of Nuevo Energy Company

The calculation of the purchase price and the preliminary allocation to assets and liabilities as of May 14, 2004 are shown below. The average PXP common stock price is based on the average closing price of PXP common stock during the five business days commencing two days before the merger was announced. The purchase price allocation is preliminary because certain items such as the determination of the final tax bases and fair value of the assets and liabilities as of the acquisition date have not been completed.


	(in thousands, except share price)
Shares of PXP common stock issued		36,486
Average PXP stock price	$	15.76

Fair value of PXP common stock issued	$	575,023
Fair value of Nuevo stock options assumed by Plains		4,389
Tender offer for Nuevo stock options		17,056
Estimated merger expenses		36,652

Total estimated purchase price before liabilities assumed		633,120
Fair value of liabilities :
Senior Subordinated Notes		162,945
Bank Credit Facility		140,000
TECONS		103,815
Current liabilities⁽¹⁾		203,798
Other noncurrent liabilities		33,583
Deferred income tax liabilities		270,425
Asset retirement obligation		128,053

Total estimated purchase price plus liabilities assumed	$	1,675,739

Fair value of assets acquired:
Current assets (including deferred income taxes of $42,367)	$	246,595
Oil and gas properties
Subject to amortization		1,208,020
Not subject to amortization		137,457
Other noncurrent assets		7,214
Goodwill		76,453

Total estimated fair value of assets acquired	$	1,675,739

(1)

$47,776,000 of accrued liabilities are included under the captions tender offer for Nuevo stock options and estimated merger expenses.

We acquired Nuevo to allow us to take advantage of the synergies that will result in significant cost savings and because of the complementary nature of Nuevo’s assets and operations onshore and offshore California to our existing asset base. The preliminary allocation of purchase price includes $76.5 million of goodwill. The goodwill is related to deferred income tax liabilities to be recorded due to the non-taxable nature of the merger. The allocation of purchase price to oil and gas properties is based on our estimate of the fair value of such properties on a discounted, after-tax basis.

allocation with respect to the acquisition of Nuevo. The credits are subject to various risks, including possible future legislative changes, possible phase out of the credit as a result of high crude oil prices, and audit positions that may be taken by taxing authorities. At this time we are unable to estimate the amount of EOR credits, if any, that may be claimed.

Pro Forma Financial Information

The following unaudited pro forma information for the three and nine months ended September 30, 2004 and 2003 shows the proforma effect of the acquisition of Nuevo by PXP, the issuance by PXP of $250 million of 7.125% Senior Notes due 2014 and the retirement of Nuevo’s 9³/8% Senior Subordinated Notes and TECONS as discussed in Note 4, the sale of Nuevo’s Congo operations as discussed in Note 8, PXP’s acquisition of 3TEC Energy Corporation (“3TEC”), which was completed on June 4, 2003, and PXP’s issuance of $75 million of 8.75% senior subordinated notes on May 30, 2003. This unaudited pro forma information assumes the acquisition of Nuevo by PXP, the issuance of the 7.125% Senior Notes and the sale of Nuevo’s Congo operations occurred on January 1 of the year presented. PXP’s acquisition of 3TEC and the issuance of the $75 million of 8.75% senior subordinated notes are assumed to have occurred on January 1, 2003.

This unaudited pro forma information has been prepared based on our historical consolidated statements of income and the historical consolidated statements of income of Nuevo and 3TEC. We believe the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to the pro forma transactions. This pro forma financial information does not purport to represent what our results of operations would have been if such transactions had occurred on such dates.


	Three Months Ended September 30, 2003		Nine Months Ended September 30,
	Three Months Ended September 30, 2003		2004			2003
	(in thousands, except per share data)
Revenues	$	178,238	$	591,023		$	534,377
Income from operations		40,948		161,472			138,442
Income (loss) from continuing operations		19,121		(22,515	)		28,851
Discontinued operations and cumulative effect of accounting changes		640		—			26,784
Net income (loss)		19,761		(22,515	)		55,635

Basic earnings per share
Income (loss) from continuing operations	$	0.25	$	(0.29	)	$	0.38
Discontinued operations and cumulative
effect of accounting changes		0.01		—			0.35
Net income (loss)		0.26		(0.29	)		0.73

Diluted earnings per share
Income (loss) from continuing operations	$	0.25	$	(0.29	)	$	0.37
Discontinued operations and cumulative effect of accounting changes		0.01		—			0.35
Net income (loss)		0.26		(0.29	)		0.72
Weighted average shares outstanding
Basic		76,592		76,854			76,589
Diluted		77,293		76,854			77,056

Income from continuing operations has been reduced by debt extinguishment costs of $22.7 million and $11.1 million in the nine months ended September 30, 2004 and 2003, respectively.

Note 3—Derivative Instruments and Hedging Activities

General

We actively manage our exposure to commodity price fluctuations by hedging portions of our oil and gas production through the use of derivative instruments. The derivative instruments currently consist of oil and gas swaps, collars and option contracts entered into with financial institutions. We do not enter into derivative instruments for speculative trading purposes. Derivative instruments utilized to manage commodity price risk are accounted for in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, as amended. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value are recognized currently in our statement of operations as gain (loss) on mark-to-market derivative contracts. If a derivative is designated as a cash flow hedge and qualifies for hedge accounting, the unrealized gain or loss on the derivative is deferred in accumulated Other Comprehensive Income (“OCI”), a component of Stockholders’ Equity until the sale of the hedged oil and gas production. Realized gains and losses on derivative instruments that are designated as a hedge and qualify for hedge accounting are generally included in oil and gas revenues in the period the hedged volumes are sold. However, in the case of the derivatives acquired in connection with our acquisitions of Nuevo and 3TEC, only changes in fair value subsequent to the acquisition date will be reflected in our oil and gas revenues (see discussion below).

To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain unchanged until the related product has been delivered. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. Hedge effectiveness is measured on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

We assumed certain liabilities related to open derivative positions in connection with the Nuevo acquisition. In accordance with SFAS 141 and supported by Derivative Implementation Group, or DIG, issues related to SFAS 133 these derivative positions were recorded at fair value in the purchase price allocation as a liability of $132.5 million. The recognition of the derivative liability as do other liabilities assumed in connection with the acquisition resulted in an increase in the total purchase price which is allocated to the assets acquired, including any goodwill. The amounts allocated to oil and gas properties will result in higher DD&A expense to be charged to earnings over the life of our reserves. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed will result in adjustments to our oil and gas revenues upon settlement. For example, if the fair value of the derivative positions assumed do not change then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no reduction to oil and gas revenues related to the derivative positions. If, however, the actual sales price is different than the price assumed in the original fair value calculation the difference would be reflected as either a decrease or increase in oil and gas revenues, depending upon whether the sales price was higher or lower, respectively, than the price assumed in the original fair value calculation.

Pursuant to SFAS 149 “Amendment of SFAS 133 on Derivative Instruments and Hedging Activities”, the derivative instruments assumed in connection with the Nuevo acquisition are deemed to contain a significant financing element and all cash flows associated with these positions are reported as a financing activity in the statement of cash flows.

Hedge Restructuring

In September 2004 we entered into new oil price collars for the period 2005 through 2008 and eliminated approximately 80% of our 2005 fixed price crude oil swaps. We exchanged existing 2005 oil price swaps with respect to 22,000 barrels of oil per day at an average price of $24.25 for new oil price collars relating to 22,000 barrels of oil per day during the period 2005 through 2008 that have a floor price of $25.00 and an average ceiling price of $34.76. The Company’s only remaining 2005 crude oil swaps involve 13,000 barrels of oil per day in the first quarter and 10,000 barrels of oil per day in the second quarter, at fixed prices averaging $25.82 and $25.80, respectively.

The new collars do not qualify for hedge accounting because they incorporate a net liability position associated with the cancelled swaps. As a result, changes to the market value of the collars will be recorded quarterly on the statement of operations as gain (loss) on mark-to-market derivative contracts. We recognized a pre-tax derivative mark-to-market loss of $113.9 million in the third quarter of 2004. Any cash flow impact associated with the new collars will be reported as a financing activity in the statement of cash flows rather than an operating cash flow because the collars are deemed to contain a significant financing element. OCI at September 30, 2004 includes $106.0 million of deferred losses representing the mark-to-market value of the cancelled 2005 swaps as of the date of the restructuring. These deferred losses will remain in OCI until the hedged production is delivered during 2005, at which time they will be recognized as a reduction to oil revenues.

Derivative Instruments Designated as Cash Flow Hedges.

During the three months and nine months ended September 30, 2004, deferred losses of $43.9 million and $86.4 million, respectively, were reclassified from OCI and charged to income as a reduction of oil and gas revenues and steam gas costs and we recognized $1.1 million and $1.3 million, respectively, for ineffectiveness of derivatives that qualify for hedge accounting. As of September 30, 2004, $214.8 million ($136.3 million, net of tax) of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period. The amounts ultimately reclassified to earnings will vary due to changes in the fair value of the open derivative contracts prior to settlement.

At September 30, 2004, we had the following open commodity derivative positions designated as cash flow hedges:


Period	Commodity	Instrument Type	Daily Volumes	Average Price		Index
Sales of Production
2004
4th Quarter	Crude oil	Swap	39,500 /Barrels	$	25.00	WTI
4th Quarter	Natural gas	Swap	20,000 /MMBtu	$	4.45	Henry Hub
4th Quarter	Natural gas	Swap	14,500 /MMBtu	$	4.64	Waha Socal
4th Quarter	Natural gas	Collar	10,000 /MMBtu	$	4.75 Floor—$5.67 Ceiling	Henry Hub
2005
1st Quarter	Crude oil	Swap	13,000 /Barrels	$	25.82	WTI
2nd Quarter	Crude oil	Swap	10,000 /Barrels	$	25.80	WTI
1st Quarter	Natural gas	Swap	13,000 /MMBtu	$	4.75	Waha Socal
2nd Quarter	Natural gas	Swap	9,500 /MMBtu	$	4.66	Waha
3rd Quarter	Natural gas	Swap	5,000 /MMBtu	$	4.40	Waha
4th Quarter	Natural gas	Swap	5,000 /MMBtu	$	4.40	Waha
2006
January–December	Crude oil	Swap	15,000 /Barrels	$	25.28	WTI

Purchases of Natural Gas
2004
4th Quarter	Natural gas	Swap	8,000 /MMBtu	$	3.91	Socal
2005
January–December	Natural gas	Swap	8,000 /MMBtu	$	3.85	Socal

Location and quality differentials attributable to our properties are not included in the foregoing prices. Because of the quality and location of our oil and gas production, these adjustments will affect our net price. We have locked in an average fixed price differential to NYMEX of approximately $4.50 per barrel on approximately 16,000-17,000 barrels per day of production for 2004 under the terms of our crude oil sales contracts. In addition, substantially all of the California crude oil production from the properties acquired from Nuevo is sold under a contract that provides for pricing based on a fixed percentage of the NYMEX crude oil price for each type of crude oil produced. Consequently, the actual price received for production from the properties acquired from Nuevo will vary with the production mix. The selling price for the crude oil production sold under this contract is expected to result in a net realized price of approximately 82% of NYMEX for the remainder of 2004, therefore, each WTI barrel hedges 1.22 barrels of physical production sold under this contract. At September 30, 2004 19,800 WTI barrels per day of production were designated as hedges of production under this sales contract.

Derivative Instruments Not Designated as Hedging Instruments.

The restructured collars discussed above as well as certain other commodity derivative contracts to which we are a party, do not qualify for hedge accounting. Consequently, these contracts are marked-to-market each quarter with changes in fair value recognized currently as gain (loss) on mark-to-market derivative contracts in the statement of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

During the three and nine months ended September 30, 2004 we recognized pre-tax losses of $124.7 million and $125.8 million, respectively, from derivatives that do not qualify for hedge accounting. The foregoing amounts consist of mark-to-market losses of $113.9 million and $109.5 million for the three and nine months ended September 30, 2004, respectively, and cash settlements of $10.8 million and $16.3 million for these same periods.

At September 30, 2004, we had the following open commodity derivative positions that were not designated as hedging instruments:


Period	Commodity	Instrument Type	Daily Volumes	Average Price	Index
Sales of Production
2004
4th Quarter	Crude oil	Three Way Collar	8,000 /Barrels	$19.28–$24.00–$31.00	WTI
4th Quarter	Natural gas	Collar	20,000 /MMBtu	$4.00 Floor–$5.15 Ceiling	Henry Hub
2005
1st Quarter	Crude oil	Collar	4,300 /Barrels	$27.00 Floor–$31.75 Ceiling	WTI
2nd Quarter	Crude oil	Collar	6,800 /Barrels	$27.00 Floor–$30.40 Ceiling	WTI
3rd Quarter	Crude oil	Collar	14,400 /Barrels	$26.00 Floor–$30.03 Ceiling	WTI
4th Quarter	Crude oil	Collar	14,000 /Barrels	$26.00 Floor–$29.33 Ceiling	WTI
January–December	Crude oil	Collar	22,000 /Barrels	$25.00 Floor–$34.76 Ceiling	WTI
2006
January–December	Crude oil	Collar	22,000 /Barrels	$25.00 Floor–$34.76 Ceiling	WTI
2007
January–December	Crude oil	Collar	22,000 /Barrels	$25.00 Floor–$34.76 Ceiling	WTI
2008
January–December	Crude oil	Collar	22,000 /Barrels	$25.00 Floor–$34.76 Ceiling	WTI

Physical Purchase Contracts. We also have the following contracts for the purchase of natural gas utilized in our steam flood operations:

Period	Commodity	Instrument Type	Daily Volumes	Average Price	Index
Purchases of Natural Gas
2004
October–December	Natural gas	Physical purchase	10,000 /MMBtu	$4.19	Socal
2005
January–December	Natural gas	Physical purchase	10,000 /MMBtu	$4.19	Socal

Note 4—Long-Term Debt

At September 30, 2004 long-term debt consisted of (in thousands):


Revolving credit facility	$	263,000
8.75% senior subordinated notes, including unamortized premium of $1.8 million		276,773
7.125% senior notes, including unamortized discount of $1.3 million		248,718

	$	788,491

In connection with our acquisition of Nuevo, we completed a series of steps described below to refinance a portion of our and all of Nuevo’s outstanding debt (the “Recapitalization Transactions”). In connection with the Recapitalization Transactions we recognized a $19.7 million pre-tax loss on early extinguishment of debt in the second quarter of 2004.

Senior Revolving Credit Facility. On May 14, 2004 and on May 28, 2004 we amended our three-year, $500 million senior revolving credit facility, or credit facility, with a group of lenders and with JPMorgan Chase Bank serving as administrative agent. This credit facility provides for a current borrowing base of $650 million that will be redetermined on a semi-annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on the Company’s oil and gas properties, reserves, other indebtedness and other relevant factors. The credit facility has commitments for up to $500 million in borrowings. Additionally, the credit facility contains a $50.0 million sub-limit on letters of credit. This amended credit facility matures on April 4, 2007. To secure borrowings, we pledged 100% of the shares of stock of our domestic subsidiaries and gave mortgages covering at least 80% of the total present value of our domestic oil and gas properties.

Amounts borrowed under the credit facility bear an annual interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus a margin ranging from 1.25% to 1.875%; or (ii) the greatest of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds rate, plus 0.5%; plus an additional variable amount ranging from 0% to 0.625% for each of (1)-(3). The additional variable amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the credit facility to the borrowing base and (2) our long-term debt rating. Commitment fees and letter of credit fees under the credit facility are based on the utilization rate and our long-term debt rating. Commitment fees range from 0.3% to 0.5% of the amount available for borrowing. Letter of credit fees range from 1.25% to 1.875%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount. The effective interest rate on our borrowings under this revolving credit facility was 3.1% at September 30, 2004.

The credit facility contains negative covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, the credit facility requires us to maintain a current ratio, which includes availability under the credit facility, of at least 1.0 to 1.0 and a minimum tangible net worth requirement.

At September 30, 2004, we had $263.0 million in borrowings and $6.9 million in letters of credit outstanding under the credit facility. At that date we were in compliance with the covenants contained in the credit facility and could have borrowed the full amount available under the credit facility.

$250 Million Senior Notes Offering. On June 30, 2004 we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of ten year senior unsecured notes (the “7.125% Notes”). The 7.125% Notes were issued at 99.478% and bear interest at 7.125% with a yield to maturity of 7.2%. Proceeds from the 7.125% Notes plus borrowings under our credit facility were used to repurchase Nuevo’s 9³/8% senior subordinated notes due 2010 (the 9³/8% Notes), and redeem Nuevo’s 5.75% convertible subordinated debentures due December 15, 2026 (which resulted in the redemption of the outstanding $2.875 term convertible securities, Series A, issued by a financing trust owned by Nuevo). In October 2004 we completed an exchange of the 7.125% Notes issued in June for 7.125% Notes with substantially identical terms except that they are freely transferable and free of any covenants regarding exchange and registration rights.

The 7.125% Notes and subsidiary guarantees are senior obligations of ours and our subsidiary guarantors. Accordingly, they rank:

•

pari passu in right of payment to our and our subsidiary guarantors’ existing and future senior unsecured indebtedness;

•

senior in right of payment to our and our subsidiary guarantors’ existing and future subordinated indebtedness;

•

effectively junior in right of payment to our and our subsidiary guarantors’ senior secured indebtedness to the extent of the value of the collateral securing that indebtedness; and

•

effectively subordinated in right of payment to all existing and future indebtedness and other liabilities of non-guarantor subsidiaries (other than indebtedness and other liabilities owed to us, if any).

The indenture governing the 7.125% Notes contains covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional indebtedness, make certain investments, pay dividends, or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, sell assets, incur dividends or other payment restrictions affecting subsidiaries, enter into transactions with affiliates, create liens, merge, consolidate and transfer assets and enter into different lines of business. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.

On and after June 15, 2009, we may redeem all or part of the 7.125% Notes at our option, at 103.563% of the principal amount for the twelve-month period beginning June 15, 2009, at 102.375% of the principal amount for the twelve-month period beginning June 15, 2010, at 101.188% of the principal amount for the twelve-month period beginning June 15, 2011 and at 100% of the principal amount thereafter. In each case, accrued interest is payable to the date of redemption. In addition, before June 15, 2009, we may redeem all or part of the 7.125% Notes at the make-whole price set forth under the indenture. At any time prior to June 15, 2007, we may redeem up to 35% of the 7.125% Notes with the net cash proceeds of certain equity offerings at the redemption price set forth under the indenture.

Tender Offer for Nuevo’s 9³/8% Senior Subordinated Notes due 2010. On June 30, 2004, Nuevo completed the repurchase of all $150 million of its outstanding 9³/8% Senior Subordinated Notes. Nuevo paid $1,150.08 per $1,000 principal amount of 9³/8% Notes tendered (comprising the tender offer price of $1,107.16, plus accrued interest through June 29, 2004 of $22.92, plus the consent payment of $20.00). The tender offer and consent payment totaled $169.1 million.

Nuevo had an interest rate swap with a notional amount of $100.0 million to hedge a portion of the fair value of the 9³/8% Notes which was cancelled for total consideration of $1.7 million.

Redemption of TECONS. On June 30, 2004, Nuevo completed the redemption of all outstanding $118 million aggregate principal amount of its 5.75% Convertible Subordinated Debentures due December 15, 2026 (the “TECON Debentures”), the proceeds of which were used by Nuevo’s wholly controlled financing trust to redeem all of the trust’s outstanding $115.0 million of TECONS for total consideration of $117.0 million, which were publicly held, and all outstanding $3.0 million of $2.875 term convertible securities held by Nuevo.

Consent Solicitation for Our 8.75% Senior Subordinated Notes. We solicited consents from the holders of our 8.75% Senior Subordinated Notes due 2012 (the “8.75% Notes”) to amend the indenture under which the 8.75% Notes were issued to make certain provisions more consistent with the indenture under which the 7.125% Notes were issued. The consent solicitation expired on June 18, 2004 and, having received the requisite consents, we executed an amended and restated indenture governing the 8.75% Notes, reflecting among other things, the changes for which consent was requested from the bond holders. We paid a consent payment of $7.50 per $1,000 of principal amount to holders of the 8.75% Notes ($2.1 million).

At September 30, 2004, we had $275.0 million principal amount of 8.75% Notes outstanding. The 8.75% Notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries. The 8.75% Notes are not redeemable until July 1, 2007. On or after that date they are redeemable, at our option, at 104.375% of the principal amount for the twelve-month period ending June 30, 2008, at 102.917% of the principal amount for the twelve-month period ending June 30, 2009, at 101.458% of the principal amount for the twelve-month period ending June 30, 2010 and at 100% of the principal amount

thereafter. In each case, accrued interest is payable to the date of redemption. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.

Short-term Credit Facility. In August 2004 we entered into an uncommitted short-term credit facility with a bank under which we may make borrowings from time to time until August 14, 2005, not to exceed at any time the maximum principal amount of $15.0 million. No advance under the short-term facility may have a term exceeding fourteen days and all amounts outstanding are due and payable no later than August 15, 2005. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and the Company. At all times an advance is outstanding, the Company must have $100 million in availability under its senior revolving credit facility. No amounts were outstanding under the short-term credit facility at September 30, 2004.

Note 5—Related Party Transactions

Our Chief Executive Officer is a director of Vulcan Energy Inc., or Vulcan. We entered into certain agreements with Vulcan, including a master separation agreement; the Plains Exploration & Production transition services agreement that expired June 16, 2004; the Vulcan transition services agreement that expired June 8, 2004; and a technical services agreement that expired June 30, 2004. For the nine months ended September 30, 2004 and 2003 we billed Vulcan $0.4 million and $0.4 million, respectively, for services provided by us under these agreements and for the nine months ended September 30, 2003 Vulcan billed us $0.1 for services they provided to us under these agreements. In addition, for the nine months ended September 30, 2004 we billed Vulcan $0.2 million for administrative costs associated with certain special projects performed on their behalf.

In June 2004, based on third party valuations the Company acquired two aircraft from Cypress Aviation LLC, or Cypress, for $4.5 million. Our Chief Executive Officer is a member of Cypress. Prior to acquiring the aircraft, we chartered private aircraft from Gulf Coast Aviation Inc. (“Gulf Coast”), a corporation that from time-to-time leased aircraft owned by Cypress. In the nine months ended September 30, 2004 and 2003, we paid Gulf Coast $0.5 million and $0.7 million, respectively, in connection with such services. The charter services were arranged with market-based rates.

Plains All American Pipeline, L.P. (“PAA”), a publicly traded master limited partnership, is an affiliate of Vulcan. PAA is the marketer/purchaser for a significant portion of our oil production, including the royalty share of production. The marketing agreement provides that PAA will purchase for resale at market prices certain of our oil production for which PAA charges a marketing fee of either $0.20 or $0.15 per barrel based upon the contract the barrels are resold under. During the three months and nine months ended September 30, 2004 and 2003, the following amounts were recorded with respect to such transactions (in thousands of dollars).


	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
Sales of oil to PAA
PXP’s share	$	69,173	$	58,903	$	196,459	$	178,496
Royalty owners’ share		13,912		11,011		39,388		33,796

	$	83,085	$	69,914	$	235,847	$	212,292

Charges for PAA marketing fees	$	347	$	437	$	1,097	$	1,294

Note 6—Commitments and Contingencies

We are a defendant in various lawsuits arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty and could have a material adverse effect on our financial position, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

Note 7—Supplemental Cash Flow Information


	Nine Months Ended September 30,
	2004		2003
	(amounts in thousands)
Cash payments for interest	$	18,423	$	21,770

Cash payments for taxes	$	2,880	$	3,581

Stock compensation plans—common stock issued for no cash payment
Shares		235		17

Amount	$	3,430	$	183

The acquisition of Nuevo involved non-cash consideration as follows (in thousands of dollars):


Common stock issued	$	575,023
Stock options assumed		4,389
Senior Subordinated Notes		162,945
Bank Credit Facility		140,000
TECONS		103,815
Current liabilities		251,574
Other noncurrent liabilities		33,583
Deferred income tax liabilities		270,425
Asset retirement obligation		128,053

	$	1,669,807

Note 8—Property Divestments

On September 30, 2004, we announced that we intend to divest various properties located offshore California and onshore South Texas and New Mexico. These transactions are expected to close by the end of 2004.

A purchase and sale agreement has been executed with privately held Dos Cuadras Offshore Resources, LLC (“Dos Cuadras”) to sell 11 platforms in federal and state waters off the coast of California and three related onshore facilities for $112.5 million. In addition, Dos Cuadras, which currently has ownership interests in several of these properties, will assume certain decommissioning costs. As of December 31, 2003 these properties had proven developed producing reserves of approximately 26 million equivalent barrels and approximately 10 million equivalent barrels of proved developed non-producing and proved undeveloped reserves. The transaction is subject to regulatory approvals and other conditions.

Additionally, we are in the process of divesting essentially all our assets in South Texas and New Mexico. These properties had proven reserves of 5.6 million equivalent barrels as of December 31, 2003. These sales will be conducted in a combination of negotiated and auction transactions.

In the first nine months of 2004 we completed the sale of our interest in certain non-core producing properties in New Mexico, Texas, Mississippi, Louisiana and Illinois for proceeds of approximately $27.8 million. Our oil and gas interests in the Illinois Basin fell outside of our core areas of operation and as a result did not compete well for capital with the properties within our core areas. The Illinois properties also carried with them high operating costs. These factors led to the sale of our Illinois properties through an extensive auction process. The sale was completed through a stock purchase agreement with standard terms, including typical purchase price adjustments, representations and warranties, and assumption of liabilities by the purchaser for an adjusted purchase price of $14.2 million. The reserves attributable to our Illinois properties were not material in relation to our total reserves. As a result, we do not expect the sale of these properties to have a significant impact on future operations or our stockholders.

On April 8, 2004, Nuevo entered into definitive agreements for the sale of the stock of its subsidiaries that hold oil and gas interests in the Republic of Congo. The sale closed on July 30, 2004 and we received cash consideration, net of certain related expenses, of $53.9 million.

In December 2003, Nuevo sold its Tonner Hills residential development property for approximately $47.0 million. To date $40.7 of the purchase price has been received and the remainder is due upon completion of certain habitat restoration activities. The fair value of our investment in the property is reflected on the balance sheet in current assets under the caption assets held for sale. The $40.7 million that has been received to date is reflected on the balance sheet in current liabilities, as these amounts are accounted for as deposits until the completion of the habitat restoration activities.

We have also received $4.1 million in proceeds from the sales of certain parcels of real estate acquired in the merger.

Note 9—Consolidating Financial Statements

We are the issuer of the 8.75% Notes and 7.125% Notes discussed in Note 4. The 8.75% Notes and 7.125% Notes are jointly and severally guaranteed on a full and unconditional basis by our wholly owned subsidiaries (referred to as “Guarantor Subsidiaries”).

The following financial information presents consolidating financial statements, which include:

•

PXP (the “Issuer”);

•

the guarantor subsidiaries on a combined basis (“Guarantor Subsidiaries”);

•

elimination entries necessary to consolidate the Issuer and Guarantor Subsidiaries; and

•

the Company on a consolidated basis.

In August 2004, Nuevo Energy Company, a wholly owned subsidiary that held all of the California properties we acquired in the Nuevo acquisition, was merged into PXP. In our Form 10-Q for the quarter ended June 30, 2004 Nuevo Energy Company was included in the consolidating financial statements as a Guarantor Subsidiary. The accompanying financial statements have been prepared as though the merger of Nuevo Energy Company into PXP occurred on May 14, 2004, the effective date of our acquisition of Nuevo.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

SEPTEMBER 30, 2004

(in thousands)


	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1,789		$	1		$	—		$	1,790
Accounts receivable		88,277			31,247			—			119,524
Deferred income taxes		67,940			22,778			—			90,718
Other current assets		58,778			1,280			—			60,058

		216,784			55,306			—			272,090

Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		1,874,008			546,459			—			2,420,467
Not subject to amortization		143,404			36,952			—			180,356
Other property and equipment		9,712			541			—			10,253

		2,027,124			583,952			—			2,611,076
Less allowance for depreciation, depletion and amortization		(180,955	)		(92,017	)		—			(272,972	)

		1,846,169			491,935			—			2,338,104

Investment in and Advances to Subsidiaries		491,028			—			(491,028	)		—

Goodwill		76,453			145,046			—			221,499

Other Assets		27,361			2,726			—			30,087

	$	2,657,795		$	695,013		$	(491,028	)	$	2,861,780

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	73,579		$	15,949		$	—		$	89,528
Commodity hedging contracts		191,337			83,412			—			274,749
Other current liabilities		137,790			19,194			—			156,984

		402,706			118,555			—			521,261

Long-Term Debt		788,491			—			—			788,491

Other Long-Term Liabilities		350,477			54,941			—			405,418

Payable to Parent		—			210,471			(210,471	)		—

Deferred Income Taxes		324,675			30,489			—			355,164

Stockholders’ Equity
Stockholders’ equity		963,537			341,083			(341,083	)		963,537
Accumulated other comprehensive income		(172,091	)		(60,526	)		60,526			(172,091	)

		791,446			280,557			(280,557	)		791,446

	$	2,657,795		$	695,013		$	(491,028	)	$	2,861,780

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2003

(in thousands)


	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	403		$	974		$	—		$	1,377
Deferred income taxes		11,782			10,025			—			21,807
Accounts receivable and other current assets		32,018			21,612			—			53,630
Inventories		3,800			1,518			—			5,318

		48,003			34,129			—			82,132

Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		570,639			503,663			—			1,074,302
Not subject to amortization		21,370			42,288			—			63,658
Other property and equipment		4,330			609			—			4,939

		596,339			546,560			—			1,142,899
Less allowance for depreciation, depletion and amortization		(64,470	)		(121,534	)		—			(186,004	)

		531,869			425,026			—			956,895

Investment in and Advances to Subsidiaries		531,142						(531,142	)		—

Other Assets		20,292			146,600			—			166,892

	$	1,131,306		$	605,755		$	(531,142	)	$	1,205,919

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	76,540		$	22,912		$	—		$	99,452
Commodity hedging contracts		29,782			25,341			—			55,123
Current maturities on long-term debt		511			—			—			511

		106,833			48,253			—			155,086

Long-Term Debt		487,906			—			—			487,906

Other Long-Term Liabilities		43,317			22,112			—			65,429

Payable to Parent		—			511,783			(511,783	)		—

Deferred Income Taxes		138,994			4,248			—			143,242

Stockholders’ Equity
Stockholders’ equity		394,695			30,292			(30,292	)		394,695
Accumulated other comprehensive income		(40,439	)		(10,933	)		10,933			(40,439	)

		354,256			19,359			(19,359	)		354,256

	$	1,131,306		$	605,755		$	(531,142	)	$	1,205,919

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

THREE MONTHS ENDED SEPTEMBER 30, 2004

(in thousands)


	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	135,840		$	12,827		$	—		$	148,667
Gas sales		13,865			46,962			—			60,827
Other operating revenues		663			204			—			867

		150,368			59,993			—			210,361

Costs and Expenses
Production costs		59,924			17,239			—			77,163
General and administrative		28,322			1,204			—			29,526
Depreciation, depletion, amortization and accretion		25,099			20,708			—			45,807

		113,345			39,151			—			152,496

Income from Operations		37,023			20,842			—			57,865
Other Income (Expense)
Equity in earnings of subsidiaries		6,837			—			(6,837	)		—
Debt extinguishment costs		—			—			—			—
Gain (loss) on mark-to-market derivative contracts		(125,153	)		502			—			(124,651	)
Interest expense		(5,109	)		(5,860	)		—			(10,969	)
Interest and other income (expense)		364			—			—			364

Income (Loss) Before Income Taxes		(86,038	)		15,484			(6,837	)		(77,391	)
Income tax (expense) benefit
Current		3,348			(3,811	)		—			(463	)
Deferred		34,712			(4,836	)		—			29,876

Net Income (Loss)	$	(47,978	)	$	6,837		$	(6,837	)	$	(47,978	)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

THREE MONTHS ENDED SEPTEMBER 30, 2003

(in thousands)


	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	34,085		$	18,589		$	—		$	52,674
Gas sales		3,921			38,527			—			42,448
Other operating revenues		—			260			—			260

		38,006			57,376			—			95,382

Costs and Expenses
Production costs		13,141			16,320			—			29,461
General and administrative		10,264			1,930			—			12,194
Depreciation, depletion, amortization and accretion		3,534			12,667			—			16,201

		26,939			30,917			—			57,856

Income from Operations		11,067			26,459			—			37,526
Other Income (Expense)
Equity in earnings of subsidiaries		15,971			—			(15,971	)		—
Debt extinguishment costs		(224	)		—			—			(224	)
Gain (loss) on mark-to-market derivative contracts		—			1,741			—			1,741
Interest expense		(5,641	)		(1,295	)		—			(6,936	)
Interest and other income (expense)		234			—			—			234

Income Before Income Taxes		21,407			26,905			(15,971	)		32,341
Income tax (expense) benefit
Current		3,864			(4,135	)		—			(271	)
Deferred		(7,727	)		(6,799	)		—			(14,526	)

Net Income	$	17,544		$	15,971		$	(15,971	)	$	17,544

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

NINE MONTHS ENDED SEPTEMBER 30, 2004

(in thousands)


	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	252,334		$	45,168		$	—		$	297,502
Gas sales		27,352			129,637			—			156,989
Other operating revenues		921			680			—			1,601

		280,607			175,485			—			456,092

Costs and Expenses
Production costs		109,563			47,528			—			157,091
General and administrative		58,799			4,041			—			62,840
Depreciation, depletion, amortization and accretion		43,242			51,000			—			94,242

		211,604			102,569			—			314,173

Income from Operations		69,003			72,916			—			141,919
Other Income (Expense)
Equity in earnings of subsidiaries		34,297			—			(34,297	)		—
Debt extinguishment costs		(19,691	)		—			—			(19,691	)
Gain (loss) on mark-to-market derivative contracts		(123,966	)		(1,876	)		—			(125,842	)
Interest expense		(14,203	)		(12,303	)		—			(26,506	)
Interest and other income (expense)		664			5			—			669

Income (Loss) Before Income Taxes		(53,896	)		58,742			(34,297	)		(29,451	)
Income tax (expense) benefit
Current		3,083			(3,690	)		—			(607	)
Deferred		32,126			(20,755	)		—			11,371

Net Income (Loss)	$	(18,687	)	$	34,297		$	(34,297	)	$	(18,687	)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

NINE MONTHS ENDED SEPTEMBER 30, 2003

(in thousands)


	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	97,871		$	49,764		$	—		$	147,635
Gas sales		12,150			50,526			—			62,676
Other operating revenues		—			667			—			667

		110,021			100,957			—			210,978

Costs and Expenses
Production costs		38,331			36,664			—			74,995
General and administrative		21,754			2,941			—			24,695
Depreciation, depletion, amortization and accretion		15,186			20,141			—			35,327

		75,271			59,746			—			135,017

Income from Operations		34,750			41,211			—			75,961
Other Income (Expense)
Equity in earnings of subsidiaries		24,588			—			(24,588	)		—
Debt extinguishment costs		(224	)		—			—			(224	)
Gain (loss) on mark-to-market derivative contracts		—			3,207			—			3,207
Interest expense		(13,015	)		(4,115	)		—			(17,130	)
Interest and other income (expense)		58			9			—			67

Income Before Income Taxes and Cumulative Effect of Accounting Change		46,157			40,312			(24,588	)		61,881
Income tax (expense) benefit
Current		4,734			(7,434	)		—			(2,700	)
Deferred		(15,199	)		(8,935	)		—			(24,134	)

Income Before Cumulative Effect of Accounting Change		35,692			23,943			(24,588	)		35,047
Cumulative effect of accounting change, net of tax		11,679			645			—			12,324

Net Income	$	47,371		$	24,588		$	(24,588	)	$	47,371

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2004

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	(18,687	)	$	34,297		$	(34,297	)	$	(18,687	)
Items not affecting cash flows from operating activities
Equity in earnings of subsidiaries		(34,297	)		—			34,297			—
Depreciation, depletion, amortization and accretion		43,242			51,000			—			94,242
Deferred income taxes		(32,126	)		20,755			—			(11,371	)
Debt extinguishment costs		(4,453	)		—			—			(4,453	)
Commodity derivative contracts
Loss (gain) on derivatives		74,024			(7,818	)		—			66,206
Reclassify financing derivative settlements		61,274			—			—			61,274
Noncash compensation
Stock appreciation rights		17,884			—			—			17,884
Other noncash compensation		6,736			—			—			6,736
Other noncash items		(92	)		—			—			(92	)
Change in assets and liabilities from operating activities net of effect of acquisition
Accounts receivable and other assets		1,139			(9,340	)		—			(8,201	)
Accounts payable and other liabilities		28,831			17,800			—			46,631

Net cash provided by operating activities		143,475			106,694			—			250,169


CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(67,632	)		(74,467	)		—			(142,099	)
Acquisition of Nuevo Energy Company, net of cash acquired		(14,156	)		—			—			(14,156	)
Proceeds from sales of oil and gas properties		58,076			27,816			—			85,892
Other		(5,382	)		(357	)		—			(5,739	)

Net cash used in investing activities		(29,094	)		(47,008	)		—			(76,102	)


CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facility		52,000			—			—			52,000
Proceeds from issuance of 7.125% Senior Notes		248,695			—			—			248,695
Retirement of debt assumed in acquisition of Nuevo Energy Company		(405,000	)		—			—			(405,000	)
Costs incurred in connection with financing arrangements		(8,988	)		—			—			(8,988	)
Advances/investments with affiliates		60,659			(60,659	)		—			—
Derivative settlements		(61,274	)		—			—			(61,274	)
Other		913			—			—			913

Net cash provided by (used in) financing activities		(112,995	)		(60,659	)		—			(173,654	)

Net increase (decrease) in cash and cash equivalents		1,386			(973	)		—			413
Cash and cash equivalents, beginning of period		403			974			—			1,377

Cash and cash equivalents, end of period	$	1,789		$	1		$	—		$	1,790

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2003

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	47,371		$	24,588		$	(24,588	)	$	47,371
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		15,186			20,141			—			35,327
Equity in earnings of subsidiaries		(24,588	)		—			24,588			—
Deferred income taxes		15,199			8,935			—			24,134
Cumulative effect of adoption of accounting change		(11,679	)		(645	)		—			(12,324	)
Commodity derivative contracts
Gain on derivatives		—			(10,257	)		—			(10,257	)
Noncash compensation
Stock appreciation rights		5,830			—			—			5,830
Other noncash compensation		2,069			—			—			2,069
Other noncash items		352			—			—			352
Change in assets and liabilities from operating activities		3,477			(8,032	)		—			(4,555	)

Net cash provided by operating activities		53,217			34,730			—			87,947

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(62,989	)		(32,035	)		—			(95,024	)
Acquisitions, net of cash acquired		—			(267,197	)		—			(267,197	)
Proceeds from property sales		—			8,517			—			8,517
Other		(1,633	)		(126	)		—			(1,759	)

Net cash used in investing activities		(64,622	)		(290,841	)		—			(355,463	)

CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facility		190,400			—			—			190,400
Proceeds from debt issuance		80,061			—			—			80,061
Debt issuance costs		(4,143	)		—			—			(4,143	)
Advances/investments with affiliates		(256,088	)		256,088			—			—
Other		174			—			—			174

Net cash provided by (used in) financing activities		10,404			256,088			—			266,492

Net increase (decrease) in cash and cash equivalents		(1,001	)		(23	)		—			(1,024	)
Cash and cash equivalents, beginning of period		1,004			24			—			1,028

Cash and cash equivalents, end of period	$	3		$	1		$	—		$	4

Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in connection with the information contained in the consolidated financial statements and notes thereto included elsewhere in this report.

Overview

Company Overview

Plains Exploration & Production Company (“Plains”, “PXP”, “us”, “our”, or “we”) is an independent oil and gas company primarily engaged in the activities of acquiring, exploiting, developing and producing oil and gas in the United States. We own oil and gas properties in six states with principal operations in:

•

the Los Angeles, San Joaquin, Santa Maria and Ventura Basins onshore and offshore California;

•

the Gulf Coast Basin onshore and offshore Louisiana;

•

the East Texas Basin in east Texas and north Louisiana; and

•

the Permian Basin in Texas.

Assets in our principal focus areas include mature properties with long-lived reserves and significant development and exploitation opportunities as well as newer properties with development, exploitation and exploration potential. We have historically hedged portions of our oil and gas production to manage our exposure to commodity price risk

Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At September 30, 2004 we had approximately $230 million of availability under our revolving credit facility. We expect to spend approximately $60 to $70 million for capital expenditures during the three months ending December 31, 2004 and our Board of Directors has approved a capital budget for 2005 of approximately $325 million. We believe that we have sufficient liquidity through our cash from operations and borrowing capacity under our revolving credit facility to meet our short-term and long-term normal recurring operating needs, debt service obligations, contingencies and anticipated capital expenditures.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We hedge to limit our commodity price exposure. The level of hedging activity depends on our view of market conditions, available hedge prices and our operating strategy. Under our hedging program, we have typically hedged up to 70%-75% of our production for the current year, up to 40%-50% of our production for the next year and up to 25%-40% of our production for the following year. Our hedging activities mitigate our exposure to price declines and allow us the flexibility to continue to execute our capital plan even if prices decline during the period our hedges are in place. In addition, the majority of our capital expenditures are discretionary and could be curtailed if our cash flows declined from expected levels.

Completion of our acquisition of Nuevo had a significant impact on our company. We now have a large proved reserve base that is over 70% proved developed, a significantly improved balance sheet and an attractive growth profile. The combined company is expected to generate significant cash flow that will be available for debt reduction and future growth opportunities.

Hedge Restructuring

In September 2004 we entered into new oil price collars for the period 2005 through 2008 and eliminated approximately 80% of our 2005 fixed price crude oil swaps. By converting fixed price swaps to collars we retained downside protection while potentially capturing significantly higher cash flow. In addition, we now have certainty of an attractive price range for a meaningful amount of our production for the next several years. Specifically, we exchanged existing 2005 oil price swaps with respect to 22,000 barrels of oil per day at an average price of $24.25 for new oil price collars relating to 22,000 barrels of oil per day during the period 2005 through 2008 that have a floor price of $25.00 and an average ceiling price of $34.76. The Company’s only remaining 2005 crude oil swaps involve 13,000 barrels of oil per day in the first quarter and 10,000 barrels of oil per day in the second quarter, at fixed prices averaging $25.82 and $25.80, respectively.

Accounting for the restructured hedge position will include the following elements:

•

The new collars do not qualify for hedge accounting because they incorporate a net liability position associated with the cancelled swaps. As a result, changes to the market value of the collars will be recorded quarterly on the income statement as derivative fair value gains or losses. For example, if the forward curve for oil prices is higher at the end of an accounting period than at the beginning of the period a derivative fair value loss will be recorded. Conversely, if the forward curve for oil prices declines during the accounting period a fair value gain will be recorded. As a consequence of this accounting treatment we expect that there may be significant volatilty in our reported earnings. As further discussed below we recognized a pre-tax derivative mark-to-market loss of $113.9 million in the third quarter of 2004.

•

Any cash flow impact associated with the new collars will be reported as a financing activity in the statement of cash flows rather than an operating cash flow because under accounting rules, the collars are deemed to contain a significant financing element.

•

Other Comprehensive Income (“OCI”) at September 30, 2004 includes $106.0 million of deferred losses representing the mark-to-market value of the cancelled 2005 swaps as of the date of the restructuring. These deferred losses will remain in OCI until the hedged production is delivered during 2005, at which time they will be recognized as a reduction to oil revenues.

The restructured collars discussed above as well as certain other commodity derivative contracts to which we are a party, do not qualify for hedge accounting. Consequently, these contracts are marked-to-market each quarter with changes in fair value recognized currently as a derivative gain or loss on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

Price Differentials

Our realized wellhead oil and gas prices are lower than the NYMEX index level as a result of area and quality differentials. We have locked in an average fixed price differential to NYMEX of approximately $4.50 per barrel on approximately 16,000-17,000 barrels per day of production for the remainder of 2004 and approximately $5.00 per barrel on approximately 20,000 barrels per day of production for 2005 under the terms of our crude oil sales contracts. In addition, substantially all of the crude oil production from the California properties acquired from Nuevo is sold under a contract that

provides for pricing based on a fixed percentage of the NYMEX crude oil price for each type of crude oil produced in California. Consequently, the actual price received for production from the properties acquired from Nuevo will vary with the production mix. The average differential for the remainder of 2004 and for 2005 results in a net realized price of 82% of NYMEX for approximately 31,000-32,000 barrels per day of Nuevo production (79% of NYMEX for approximately 24,000-25,000 barrels per day when excluding planned property sales). Because a portion of our differentials are based on a percentage of NYMEX, lower or higher crude oil prices will result in a lower or higher differential.

Approximately 75% of our gas production is sold monthly off of industry recognized, published index pricing. The remaining 25% is priced daily on the spot market. Fluctuations between the two pricing mechanisms can significantly impact the overall differential to the Henry Hub.

Sale of Oil and Gas Properties

Additionally, we are in the process of divesting essentially all our assets in South Texas and New Mexico. These properties had proven reserves of 5.6 million equivalent barrels as of December 31, 2003. The Company anticipates receiving cash proceeds of approximately $40 million from these sales, which will be conducted in a combination of negotiated and auction transactions.

2004 Results Overview

Primarily as a result of the derivative mark-to-market loss, we reported a net loss of $18.7 million, or $0.32 per diluted share for the first nine months of 2004 compared to net income of $47.4 million, or $1.51 per diluted share for the first nine months of 2003. Net income includes the effect of the properties in our acquisition of Nuevo Energy Company, or Nuevo, which are included in our results effective May 14, 2004 and the effect of the properties in our acquisition of 3TEC Energy Corporation, or 3TEC, which are included in our results effective June 1, 2003. Net income for the first nine months of 2003 includes a non-cash, after-tax $12.3 million credit related to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”.

Income from operations increased to $141.9 million in the first nine months of 2004 from $76.0 million in the first nine months of 2003. The improvement is primarily attributable to higher oil and gas sales as a result of increased sales volumes due to the Nuevo and 3TEC properties and increased oil and gas prices. The increase in income from operations was offset by the derivative mark-to-market loss, debt extinguishment costs, expenses related to stock appreciation rights and higher interest costs related to the Nuevo and 3TEC acquisitions.

Acquisition of Nuevo

On May 14, 2004 we acquired Nuevo in a stock-for-stock transaction. In the acquisition, each outstanding share of Nuevo common stock was converted into 1.765 shares of PXP common stock and Nuevo became our wholly owned subsidiary. The transaction required the issuance of 36.5 million additional PXP common shares (bringing the total outstanding PXP common shares to approximately 77.0 million), plus the assumption of $254 million in net debt and $115 million of $2.875 Term Convertible Securities, Series A, or TECONS. The transaction is expected to qualify as a tax free reorganization under Section 368(a) and to be tax free to our stockholders and to be tax free for the stock portion of the consideration received by Nuevo stockholders. We have accounted for the transaction as a purchase of Nuevo under purchase accounting rules and we continue to use the full cost method of accounting for our oil and gas properties.

In connection with our acquisition of Nuevo we have completed a series of transactions to refinance a portion of our and all of Nuevo’s outstanding debt (the “Recapitalization Transactions”). The Recapitalization Transactions include amendments to our credit facility and the indenture with respect to our 8.75% senior subordinated notes, our issuance of $250 million of 7.125% senior notes due 2014, a cash tender offer for Nuevo’s outstanding $150 million of 9.375% senior subordinated notes, the redemption of the TECONS and the termination of Nuevo’s credit facility. All of these transactions were successfully completed on or before June 30, 2004. See—Financing Activities.

Under Section 43 of the Internal Revenue Code of 1986 (as amended) and similar California tax rules, taxpayers may claim enhanced oil recovery (“EOR”) tax credits based on capital spending and lease operating expense of qualified projects. We are evaluating certain projects that were operated by Nuevo to determine if they qualify for such credits. Based on our evaluation, we may amend certain federal and state income tax returns previously filed by Nuevo to claim EOR tax credits not previously claimed by Nuevo. Any such credits claimed will be reflected as an adjustment to our purchase price allocation with respect to the acquisition of Nuevo. Post merger qualifying costs incurred on EOR projects will result in credits that will result in a reduction in our effective tax rate in future periods. The credits are subject to various risks, including possible future legislative changes, possible phase out of the credit as a result of high crude oil prices, and audit positions that may be taken by taxing authorities. At this time we are unable to estimate the amount of EOR credits, if any, that may be claimed.

General

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Our revenues are derived from the sale of oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SEC’s full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter to determine a ceiling value of our properties. The rules require a write-down if our capitalized costs exceed the allowed “ceiling.” We have had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will fluctuate in the near term. If oil and gas prices decline significantly in the future, write-downs of our oil and gas properties

could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities. Decreases in oil and gas prices have had, and will likely have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow.

To manage our exposure to commodity price risk, we use various derivative instruments to hedge our exposure to oil and gas sales price fluctuations. Our hedging arrangements provide us protection on the hedged volumes if these prices decline below the prices at which these hedges are set. However, if prices increase, ceiling prices in our hedges may cause us to receive less revenues on the hedged volumes than we would receive in the absence of hedges. Gains and losses from hedging transactions are recognized as revenues when the associated production is sold. Changes in the fair value and settlement gains and losses of derivative instruments that do not qualify for hedge accounting are recognized in other income (expense).

Our oil and gas production expenses include salaries and benefits of personnel involved in production activities, steam gas costs, electric costs, maintenance costs, production, ad valorem and severance taxes, and other costs necessary to operate our producing properties. Depletion of capitalized costs of producing oil and gas properties is provided using the units of production method based upon proved reserves. For the purposes of computing depletion, proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary.

General and administrative expenses (“G&A”) consist primarily of salaries and related benefits of administrative personnel, office rent, systems costs and other administrative costs.

Results of Operations

The following table reflects the components of our oil and gas production and sales prices and sets forth our operating revenues and costs and expenses on a barrel of oil equivalent (“BOE”) basis:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Sales Volumes
Oil and liquids (MBbls)		5,232			2,437			11,174			6,905
Gas (MMcf)		10,863			7,354			27,731			10,828
MBOE		7,043			3,663			15,796			8,710
Daily Average Sales Volumes
Oil and liquids (Bbls)		56,870			26,489			40,781			25,293
Gas (Mcf)		118,076			79,935			101,208			39,663
BOE		76,549			39,812			57,650			31,904
Unit Economics (in dollars)
Average Oil & Liquids Sales Price ($/Bbl)
Net realized price before hedging	$	36.64		$	26.37		$	34.20		$	26.87
Hedging revenue (expense)⁽¹⁾		(8.23	)		(4.76	)		(7.58	)		(5.49	)

Net realized price	$	28.41		$	21.61		$	26.62		$	21.38

Average Gas Sales Price ($/Mcf)
Net realized price before hedging	$	5.71		$	5.03		$	5.74		$	5.29
Hedging revenue (expense)⁽²⁾		(0.11	)		0.74			(0.08	)		0.50

Net realized price	$	5.60		$	5.77		$	5.66		$	5.79

Average Realized Price per BOE	$	29.74		$	25.97		$	28.77		$	24.15

Costs and Expenses per BOE
Production costs
Lease operating expenses	$	6.32		$	5.08		$	5.83		$	5.64
Steam gas costs		2.03			0.19			1.43			0.25
Electricity		1.31			1.45			1.38			1.80
Production and ad valorem taxes		0.93			1.06			0.96			0.77
Gathering and transportation		0.37			0.26			0.35			0.15
G&A
G&A excluding items below		1.71			1.51			1.96			1.64
Stock appreciation rights		2.13			1.27			1.80			0.84
Merger related costs		0.35			0.55			0.22			0.36
DD&A per BOE (oil and gas properties)		5.93			4.04			5.45			3.66

(1)

Does not include $4.58 per barrel and $3.41 per barrel of cash settlement payments for the three and nine months ended September 30, 2004, respectively, for hedges assumed in connection with the Nuevo and 3TEC mergers. Realized gains and losses on derivative instruments that are designated as a hedge and qualify for hedge accounting are generally included in oil and gas revenues in the period the hedged volumes are sold. However, in the case of the derivatives acquired in connection with our acquisitions of Nuevo and 3TEC, only cash settlements for changes in fair value subsequent to the acquisition date will be reflected in our oil and gas revenues. Cash settlements for the liability existing at the merger date are reflected as the payment of a liability.

(2)

Does not include $0.25 per Mcf and $0.79 per Mcf of cash settlement payments for the three months ended September 30, 2004 and 2003, respectively or $0.28 per Mcf and $0.67 per Mcf of cash settlement payments for the nine months ended September 30, 2004 and 2003, respectively, for hedges assumed in connection with the Nuevo and 3TEC mergers for the reasons discussed in Note 1.

Comparison of Three Months Ended September 30, 2004 to Three Months Ended September 30, 2003

Oil and gas revenues. Oil and gas revenues increased 120%, or $114.4 million, to $209.5 million for 2004 from $95.1 million for 2003. The increase is due to increased production volumes attributable to the properties acquired from Nuevo and higher realized prices. Our average realized price per BOE increased 15% to $29.74 and our production increased 92% to 7.0 MMBOE. Production attributable to the properties acquired from Nuevo was 3.8 MMBOE in the third quarter of 2004.

Oil revenues increased 182%, or $96.0 million, to $148.7 million for 2004 from $52.7 million for 2003, reflecting higher realized prices ($16.6 million) and higher production ($79.4 million). Our average realized price for oil increased 31%, or $6.80, to $28.41 per Bbl for 2004 from $21.61 per Bbl for 2003. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $43.85 per Bbl in 2004 versus $30.21 per Bbl in 2003. Hedging had the effect of decreasing our average price per Bbl by $8.23 in 2004 compared to $4.76 per Bbl in 2003. Oil production increased 115% to 5.2 MMBbls in the third quarter of 2004 from 2.4 MMBbls in the third quarter of 2003. Production attributable to the properties acquired from Nuevo was 3.3 MMBbls in the third quarter of 2004.

Gas revenues increased $18.4 million, to $60.8 million for 2004 from $42.4 million for 2003. A 3.5 Bcf increase in production volumes to 10.9 Bcf accounted for the increased gas revenues. The properties acquired from Nuevo accounted for 3.0 Bcf of the increase in 2004 production. Our average realized price for gas decreased 3%, or $0.17, to $5.60 per Mcf for 2004 from $5.77 per Mcf for 2003. In 2004 hedging revenues decreased our average price by $0.11 per Mcf while in 2003 hedging revenues increased our average price by $0.74 per Mcf.

Lease operating expenses. Lease operating expenses (including steam gas costs and electricity) increased 176%, or $43.4 million, to $68.0 million for 2004 from $24.6 million for 2003, due to the properties acquired from Nuevo. The properties acquired from Nuevo accounted for $43.6 million of the 2004 operating expenses. On a per unit basis, lease operating expenses increased to $9.66 per BOE in 2004 versus $6.72 per BOE in 2003. A large component of the per unit increase is attributable to the steam gas costs attributable to the properties acquired from Nuevo. Steam gas costs averaged $2.03 per BOE in the third quarter of 2004 versus $0.19 per BOE in the third quarter of 2003.

Production and ad valorem taxes. Production and ad valorem taxes increased $2.7 million, to $6.6 million for 2004 from $3.9 million for 2003 primarily due to the properties acquired from Nuevo. The properties acquired from Nuevo accounted for $2.6 million of such costs in 2004.

Gathering and transportation expenses. Gathering and transportation expenses increased $1.6 million, to $2.6 million for 2004 from $1.0 million for 2003 primarily due to the properties acquired from Nuevo. The properties acquired from Nuevo accounted for $1.3 million of such costs in 2004.

General and administrative expense. G&A expense, excluding amounts attributable to stock appreciation rights, or SARs, and merger related costs, increased 119%, or $6.6 million, to $12.1 million for 2004 from $5.5 million for 2003. The increase is primarily a result of increased costs resulting from the Nuevo acquisition.

G&A expense related to outstanding stock appreciation rights or SARs was $15.0 million and $4.7 million for the three months ended September 30, 2004 and 2003, respectively. Accounting for SARs requires that we record an expense or credit for vested or deemed vested SARs depending on whether, during the period, our stock price either rose or fell, respectively. Our stock price at September 30, 2004 was $23.86 versus $18.35 on June 30, 2004. In the third quarter of 2004 and 2003 we made cash payments of $0.7 million and $0.6 million, respectively, for SARs that were exercised during the period.

G&A expense for 2004 and 2003 includes $2.4 million and $2.0 million, respectively, of merger related expenses consisting primarily of severance and other compensation costs and accounting system integration and conversion expenses.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $4.0 million and $2.8 million of G&A expense in the third quarter of 2004 and 2003, respectively.

Depreciation, depletion, amortization and accretion, or DD&A. DD&A expense increased 183%, or $29.6 million, to $45.8 million for 2004 from $16.2 million for 2003. Approximately $27.2 million of the increase was attributable to our oil and gas DD&A due to a higher per unit rate and higher production. Our oil and gas unit of production rate increased to $5.93 per BOE in 2004 compared to $4.04 per BOE in 2003. The increase primarily reflects the effect of the Nuevo acquisition. The remaining increase is primarily attributable to accretion expense.

Interest expense. Interest expense increased 58%, or $4.1 million, to $11.0 million for 2004 from $6.9 million for 2003 primarily due to higher outstanding debt as a result of the Nuevo acquisition. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization. We capitalized $2.1 million and $1.2 million of interest in 2004 and 2003, respectively.

Gain (loss) on mark-to-market derivative contracts. The restructured collars discussed above as well as certain other commodity derivative contracts to which we are a party, do not qualify for hedge accounting. Consequently, these contracts are marked-to-market each quarter with changes in fair value recognized currently as a derivative gain or loss on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

During the three months ended September 30, 2004 we recognized a pre-tax loss of $124.7 million from derivatives that do not qualify for hedge accounting consisting of a mark-to-market loss of $113.9 million and cash settlements of $10.8 million. We recognized a mark-to-market gain of $1.7 million in the third quarter of 2003.

Income tax expense. Income tax expense (benefit) was $(29.4) million in the third quarter of 2004 compared to $14.8 million in the third quarter of 2003. Our overall effective tax rate decreased to 37% in 2004 from 41% in 2003. The decrease in the effective rate in 2004 primarily reflects the tax loss on the sale of our Illinois properties and the effect of the Nuevo acquisition. Current tax expense for the third quarter of 2004 consists of $3.4 million of 2004 state and federal income tax expense and a $2.9 million benefit related to a provision-to-return adjustment (which is offset by a $2.9 million deferred tax expense) related to our recently filed 2003 income tax returns.

Comparison of Nine Months Ended September 30, 2004 to Nine Months Ended September 30, 2003

Oil and gas revenues. Oil and gas revenues increased 116%, or $244.2 million, to $454.5 million for 2004 from $210.3 million for 2003. The increase is due to increased production volumes attributable to the properties acquired from Nuevo and 3TEC and higher realized prices. Our average realized price per BOE increased 19% to $28.77 and our production increased 81% to 15.8 MMBOE. Production attributable to the properties acquired from Nuevo and 3TEC was 9.7 MMBOE in the first nine months of 2004 compared to 1.7 MMBOE in the first nine months of 2003.

Oil revenues increased 102%, or $149.9 million, to $297.5 million for 2004 from $147.7 million for 2003, reflecting higher realized prices ($36.2 million) and higher production ($113.7 million). Our average realized price for oil increased 25%, or $5.24, to $26.62 per Bbl for 2004 from $21.38 per Bbl

for 2003. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $39.13 per Bbl in 2004 versus $30.94 per Bbl in 2003. Hedging had the effect of decreasing our average price per Bbl by $7.58 in 2004 compared to $5.49 per Bbl in 2003. Oil production increased 62% to 11.2 MMBbls in 2004 from 6.9 MMBbls in 2003. Production attributable to the properties acquired from Nuevo was 5.0 MMBbls in 2004.

Gas revenues increased $94.3 million, to $157.0 million in 2004 from $62.7 million in 2003. A 16.9 Bcf increase in production volumes, primarily from the properties acquired from Nuevo and 3TEC, accounted for the increased gas revenues. Our average realized price for gas decreased 2%, or $0.13, to $5.66 per Mcf for 2004 from $5.79 per Mcf for 2003. In 2004 hedging revenues decreased our average price by $0.08 per Mcf while in 2003 hedging revenues increased our average price by $0.50 per Mcf.

Lease operating expenses. Lease operating expenses (including steam gas costs and electricity) increased 104%, or $69.4 million, to $136.4 million for 2004 from $67.0 million for 2003, primarily due to the properties acquired from Nuevo. The properties acquired from Nuevo accounted for $63.6 million of the 2004 operating expenses. On a per unit basis, lease operating expenses increased to $8.64 per BOE in 2004 versus $7.69 per BOE in 2003. The per unit increase is primarily attributable to the steam gas costs attributable to the properties acquired from Nuevo. Steam gas costs averaged $1.43 per BOE in 2004 versus $0.25 per BOE in 2003.

Production and ad valorem taxes. Production and ad valorem taxes increased $8.4 million, to $15.1 million for 2004 from $6.7 million for 2003 primarily due to the properties acquired from Nuevo and 3TEC.

Gathering and transportation expenses. Gathering and transportation expenses increased $4.3 million, to $5.6 million for 2004 from $1.3 million for 2003 primarily due to the properties acquired from Nuevo and 3TEC.

General and administrative expense. G&A expense, excluding amounts attributable to stock appreciation rights, or SARs, and merger related costs, increased 117%, or $16.6 million, to $30.9 million for 2004 from $14.3 million for 2003. The increase is primarily a result of increased costs resulting from the Nuevo and 3TEC acquisitions.

G&A expense related to outstanding stock appreciation rights or SARs was $28.4 million and $7.3 million in 2004 and 2003, respectively. Accounting for SARs requires that we record an expense or credit for vested or deemed vested SARs depending on whether, during the period, our stock price either rose or fell, respectively. The $28.4 million of expense in 2004 reflects additional vesting of outstanding SARs as well as an increase in our stock price. Our stock price at September 30, 2004 was $23.86 versus $15.39 on December 31, 2003. The $7.3 million of SARs expense in 2003 primarily reflects an increase in our stock price. In the first nine months of 2004 and 2003 we made cash payments of $10.6 million and $1.5 million, respectively, for SARs that were exercised during the period.

G&A expense for 2004 and 2003 includes $3.5 million and $3.1 million, respectively, of merger related expenses consisting primarily of severance and other compensation costs and accounting system integration and conversion expenses.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $10.8 million and $7.4 million of G&A expense in 2004 and 2003, respectively.

Depreciation, depletion, amortization and accretion, or DD&A. DD&A expense increased 167%, or $58.9 million, to $94.2 million in 2004 from $35.3 million in 2003. Approximately $54.5 million of the increase was attributable to our oil and gas DD&A due to a higher per unit rate and higher production. Our oil and gas unit of production rate increased to $5.45 per BOE in 2004 compared to $3.66 per BOE in 2003. The increase primarily reflects the effect of the Nuevo acquisition. The remaining increase is primarily attributable to accretion expense.

Interest expense. Interest expense increased 55%, or $9.4 million, to $26.5 million for 2004 from $17.1 million for 2003 primarily due to higher outstanding debt as a result of the Nuevo and 3TEC acquisitions. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization. We capitalized $4.9 million and $2.0 million of interest in 2004 and 2003, respectively.

Debt extinguishment costs. In connection with the retirement of the debt assumed in the acquisition of Nuevo we recorded $19.7 million of debt extinguishment consisting primarily of a $6.6 million loss on the repurchase of all $150 million of Nuevo’s outstanding 9³/8% Senior Subordinated Notes and a $13.1 million loss on redemption of all outstanding $118 million aggregate principal amount of Nuevo’s 5.75% Convertible Subordinated Debentures due December 15, 2026.

During the nine months ended September 30, 2004 we recognized a pre-tax loss of $125.8 million from derivatives that do not qualify for hedge accounting consisting of a mark-to-market loss of $109.5 million and cash settlements of $16.3 million. We recognized a mark-to-market gain of $3.2 million in the nine months ended September 30, 2003

Income tax expense. Income tax expense (benefit) was $(10.8) million in 2004 compared to $26.8 million in 2003. Our overall effective tax rate decreased to 37% in 2004 from 43% in 2003. The decrease in the effective rate in 2004 primarily reflects the tax loss on the sale of our Illinois properties and the effect of the Nuevo acquisition. Current tax expense for 2004 consists of $3.5 million of 2004 state and federal income tax expense and a $2.9 million benefit related to a provision-to-return adjustment (which is offset by a $2.9 million deferred tax expense) related to our recently filed 2003 income tax returns.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At September 30, 2004 we had approximately $230 million of availability under our revolving credit facility. We believe that we have sufficient liquidity through our cash from operations and borrowing capacity under our revolving credit facility to meet our short-term and long-term normal recurring operating needs, debt service obligations, contingencies and anticipated capital expenditures.

Our cash flows depend on many factors, including the price of oil and gas and the success of our acquisition and drilling activities. We actively manage our exposure to commodity price fluctuations by hedging portions of our production and thereby mitigate our exposure to price declines. This allows us the flexibility to continue to execute our capital plan even if prices decline during the period our hedges are in place. In addition, the majority of our capital expenditures are discretionary and could be curtailed if our cash flows declined from expected levels.

At September 30, 2004 we had a working capital deficit of approximately $249.2 million. Approximately $184.0 million of the working capital deficit is attributable to the fair value of our commodity derivative instruments (net of related deferred income taxes). In accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, the fair value of all derivative instruments is recorded on the balance sheet. Our hedge agreements provide for monthly settlement based on the differential between the agreement price and actual NYMEX oil price. Cash received for the sale of physical production will be based on actual market prices and will generally offset any gains or losses realized on the derivative instruments. Substantially all of our derivative contracts do not have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date. In addition, $32.7 million of the working capital deficit is attributable to the in-the-money value of stock appreciation rights that were deemed vested at September 30, 2004.

As discussed in “Overview—Sale of Oil and Gas Properties” we expect to sell certain oil and gas properties for cash proceeds of approximately $152 million.

Financing Activities

In connection with our acquisition of Nuevo, we completed the Recapitalization Transactions described below to refinance a portion of our and all of Nuevo’s outstanding debt. In connection with the Recapitalization Transactions we recognized a $19.7 million pre-tax loss on early extinguishment of debt in the second quarter of 2004.

Senior Revolving Credit Facility. On May 14, 2004 and on May 28, 2004 we amended our three-year, $500 million senior revolving credit facility with a group of lenders and with JPMorgan Chase Bank serving as administrative agent. This credit facility provides for a current borrowing base of $650 million that will be redetermined on a semi-annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on the Company’s oil and gas properties, reserves, other indebtedness and other relevant factors. The credit facility has commitments for up to $500 million in borrowings. Additionally, the credit facility contains a $50.0 million sub-limit on letters of credit. This amended credit facility matures on April 4, 2007. To secure borrowings, we pledged 100% of the shares of stock of our domestic subsidiaries and gave mortgages covering at least 80% of the total present value of our domestic oil and gas properties.

subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, the credit facility requires us to maintain a current ratio, which includes availability under the credit facility, of at least 1.0 to 1.0 and a minimum tangible net worth requirement.

The 7.125% Notes and subsidiary guarantees are senior obligations of ours and our subsidiary guarantors. Accordingly, they rank:

•

pari passu in right of payment to our and our subsidiary guarantors’ existing and future senior unsecured indebtedness;

•

senior in right of payment to our and our subsidiary guarantors’ existing and future subordinated indebtedness;

•

effectively junior in right of payment to our and our subsidiary guarantors’ senior secured indebtedness to the extent of the value of the collateral securing that indebtedness; and

•

Nuevo had an interest rate swap with a notional amount of $100.0 million to hedge a portion of the fair value of the 9³/8 Notes which was cancelled for total consideration of $1.7 million.

Redemption of TECONS. On June 30, 2004, Nuevo completed the redemption of all outstanding $118 million aggregate principal amount of its 5.75% Convertible Subordinated Debentures due December 15, 2026 (the “TECON Debentures”), the proceeds of which were used by Nuevo’s wholly-controlled financing trust to redeem all of the trust’s outstanding $115.0 million of TECONS for total consideration of $117.0 million, which were publicly held, and all outstanding $3.0 million of $2.875 term convertible securities held by Nuevo.

Cash Flows


	Nine Months Ended September 30,
	2004			2003
	(in millions)
Cash provided by (used in):
Operating activities	$	250.1		$	87.9
Investing activities		(76.1	)		(355.4	)
Financing activities		(173.6	)		266.5

Net cash provided by operating activities was $250.1 million and $87.9 million for the first nine months of 2004 and 2003, respectively. The increase primarily reflects the effect of the properties acquired in the Nuevo and 3TEC acquisition and increased commodity prices.

Net cash used in investing activities was $76.1 million in the first nine months of 2004 and $355.4 million in the first nine months of 2003. Costs incurred in connection with our oil and gas acquisition, development and exploration activities totaled $142.1 million in 2004 compared to $95.0 million in 2003. Investing activities in 2004 include $14.2 million paid, net of cash acquired, in connection with the Nuevo acquisition. Investing activities in 2003 include $267.2 million paid, net of cash acquired, in connection with the 3TEC acquisition. Investing activities for 2004 also includes $85.9 million in proceeds from the sale of properties.

Net cash used in financing activities in the first nine months of 2004 was $173.6 million. During the period borrowings under our credit facility increased $52.0 million and we received $248.7 million in proceeds from the issuance of our 7.125% Senior Notes. These proceeds and funds generated by our operations we used to retire $405.0 million in debt assumed in the Nuevo acquisition and to pay $9.0 million in debt financing costs and $61.3 million in financing derivative settlements. Net cash provided by financing activities in the first nine months of 2003 was $266.5 million, primarily reflecting amounts borrowed to finance the 3TEC acquisition.

Capital Requirements

We have made and will continue to make substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and gas. We expect to spend approximately $60 to $70 million for capital expenditures during the three months ending December 31, 2004 and our Board of directors has approved a $325 million capital budget for 2005. We expect that these capital expenditures will be funded with cash flow from our operations and our revolving credit facility.

We will incur cash expenditures upon the exercise of SARs, but our common shares outstanding will not increase. At September 30, 2004 we had approximately 3.0 million SARs outstanding of which 2.0 million were vested. If all of the vested SARs were exercised, based on $23.86, the price of our common stock as of September 30, 2004, we would pay $30.6 million to holders of the SARs. In the first nine months of 2004 we made cash payments of $10.6 million for SARs that were exercised during that period.

Critical Accounting Policies and Factors that May Affect Future Results

Based on the accounting policies that we have in place, certain factors may impact our future financial results. Significant accounting policies related to commodity pricing and risk management activities, write-downs under full cost ceiling test rules, oil and gas reserves, stock appreciation rights and goodwill are discussed in our Annual Report on Form 10-K/A for the year ended December 31, 2003.

Recent Accounting Pronouncements

In September 2004 the SEC published Staff Accounting Bulletin No. 106 (SAB 106), which is effective January 1, 2005. SAB 106 relates to the Staff’s views regarding the application of SFAS 143 by oil and gas producing companies following the full cost accounting method. SAB 106 requires that the future outflows associated with settling AROs that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling test calculation. SAB 106 also requires that to the extent that estimated dismantlement and abandonment costs, net of estimated salvage values, have not been included as capitalized costs in the base for computing depletion, depreciation and amortization (DD&A) because they have not yet been capitalized as asset retirement costs under SFAS 143, such costs that will be incurred as a result of future development activities on proved reserves should be estimated and included in the costs to be amortized. We are currently evaluating the guidelines with respect to our full cost ceiling test calculation and the computation of our DD&A rates. We do not believe any required changes in our calculations would have resulted in a ceiling test writedown at September 30, 2004 or a significant change in our DD&A expense.

Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements based on our current expectations and projections about future events. Statements that are predictive in nature, that depend upon or refer to future events or conditions, or that include words such as “will”, “would”, “should”, “plans”, “likely”, “expects”, “anticipates”, “intends”, “believes”, “estimates”, “thinks”, “may”, and similar expressions, are forward-looking statements. These statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. These factors include, among other things:

•

uncertainties inherent in the development and production of oil and gas and in estimating reserves;

•

unexpected difficulties in integrating our operations as a result of any significant acquisitions, including the recent acquisition of Nuevo;

•

unexpected future capital expenditures (including the amount and nature thereof);

•

impact of oil and gas price fluctuations;

•

the effects of our indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt, and could have other adverse consequences;

•

the effects of competition;

•

the success of our risk management activities;

•

the availability (or lack thereof) of acquisition or combination opportunities;

•

the impact of current and future laws and governmental regulations;

•

environmental liabilities that are not covered by an effective indemnity or insurance, and

•

general economic, market, industry or business conditions.

All forward-looking statements in this report are made as of the date hereof, and you should not place undue certainty on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report. Moreover,

although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. See Items 1 & 2.— “Business and Properties—Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2003 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Factors That May Affect Future Results” in this report for additional discussions of risks and uncertainties.

Item 3—Qualitative and Quantitative Disclosures About Market Risks

Commodity derivatives. We actively manage our exposure to commodity price fluctuations by hedging portions of our oil and gas production through the use of derivative instruments. The derivative instruments currently consist of oil and gas swaps, collars and option contracts entered into with financial institutions. We do not enter into derivative instruments for speculative trading purposes. Derivative instruments utilized to manage commodity price risk are accounted for in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, as amended. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value are recognized currently in our earnings as other income (expense). If a derivative is designated as a cash flow hedge and qualifies for hedge accounting, the unrealized gain or loss on the derivative is deferred in accumulated Other Comprehensive Income (“OCI”), a component of Stockholders’ Equity until the sale of the hedged oil and gas production. Realized gains and losses on derivative instruments that are designated as a hedge and qualify for hedge accounting are generally included in oil and gas revenues in the period the hedged volumes are sold. However, in the case of the derivatives acquired in connection with our acquisitions of Nuevo and 3TEC, only changes in fair value subsequent to the acquisition date will be reflected in our oil and gas revenues.

As discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Hedge Restructuring”, in September 2004 we entered into new oil price collars for the period 2005—2008 and eliminated approximately 80% of our 2005 fixed price crude oil swaps. By converting fixed price swaps to collars we retained downside protection while potentially capturing significantly higher cash flow. In addition, we now have certainty of an attractive price range for a meaningful amount of our production for the next several years. The restructured collars as well as certain other commodity derivative contracts to which we are a party, do not qualify for hedge accounting. Consequently, these contracts are marked-to-market each quarter with changes in fair value recognized currently as a derivative gain or loss on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

See Note 3 to the Consolidated Financial Statements—“Derivative Instruments and Hedging Activities” for a complete discussion of our hedging activities and a listing of our derivative instruments at September 30, 2004.

The fair value of outstanding crude oil and natural gas commodity derivative instruments and the change in fair value that would be expected from a 10% price decrease are shown in the table below (in millions):


	September 30,
	2004					2003
	Fair Value			Effect of 10% Price Decrease		Fair Value			Effect of 10% Price Decrease
Swaps and options contracts	$	(481.8	)	$	157.9	$	(35.4	)	$	38.2

The fair value of the swaps and option contracts are estimated based on quoted prices from independent reporting services compared to the contract price of the agreement, and approximate the gain or loss that would have been realized if the contracts had been closed out at period end. All hedge positions offset physical positions exposed to the cash market. None of these offsetting physical positions are included in the above table. Price risk sensitivities were calculated by assuming an across-the-board 10% decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in prompt month prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.

The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better. Four of the financial institutions are participating lenders in our revolving credit facility, with one counterparty holding contracts that represent approximately 31% of the fair value of all open positions as of September 30, 2004.

Our management intends to continue to maintain hedging arrangements for a portion of our production. These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set, but ceiling prices in our hedges may cause us to receive less revenues on the hedged volumes than we would receive in the absence of hedges.

Price differentials. Our realized wellhead oil and gas prices are lower than the NYMEX index level as a result of area and quality differentials. We have locked in an average fixed price differential to NYMEX of approximately $4.50 per barrel on approximately 16,000-17,000 barrels per day of production for the remainder of 2004 and approximately $5.00 per barrel on approximately 20,000 barrels per day of production for 2005 under the terms of our crude oil sales contracts. In addition, substantially all of the crude oil production from the California properties acquired from Nuevo is sold under a contract that provides for pricing based on a fixed percentage of the NYMEX crude oil price for each type of crude oil produced in California. Consequently, the actual price received for production from the properties acquired from Nuevo will vary with the production mix. The average differential for the remainder of 2004 and for 2005 results in a net realized price of 82% of NYMEX for approximately 31,000-32,000 barrels per day of Nuevo production (79% of NYMEX for approximately 24,000-25,000 barrels per day when excluding planned property sales). Because a portion of our differentials are based on a percentage of NYMEX, lower or higher crude oil prices will result in a lower or higher differential.

Interest rate risk. Our credit facility is sensitive to market fluctuations in interest rates. We use interest rate swaps to hedge underlying debt obligations. These instruments hedge specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment

to interest expense over the life of the instruments. We entered into an interest rate swap for an aggregate notional principal amount of $7.5 million that fixed the interest rate on that amount of borrowing under our credit facility at 3.9% plus the LIBOR margin set forth in our credit facility. The swap expired in October 2004.

Item 4—Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-14(c) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures as of September 30, 2004 are effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

We have recently added an Assistant Controller—Internal Control and Compliance to oversee our compliance with Sarbanes-Oxley Section 404 and coordinate our internal audit function. During our fiscal quarter ended September 30, 2004, there was no significant change in our internal control over financial reporting, other than the addition of our Assistant Controller—Internal Control and Compliance, that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1—Legal Proceedings

Item 2—Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

Issuer Purchases of Equity Securities

Period

Total

Number of

Shares

Purchased

Average

Price

Paid per

Share

Total

Number of

Shares

Purchased

As Part of

Publicly

Announced

Plans or

Programs

Maximum

Number (or

Approximate

Dollar Value)

of Shares

that May Yet

Purchased

Under the

Plans or

Programs

July 1 to September 30, 2004 (1)

4,000

20.48

—

(1)

These shares were repurchased from the holders of restricted stock at the time the restrictions lapsed in accordance with the Company’s 2002 Stock Incentive Plan, as amended, in order to pay the withholding taxes of the holder.

Item 6—Exhibits and Reports on Form 8-K

(a)

Exhibits



10.1	*	Fourth Amendment to Credit Agreement dated April 4, 2003, dated effective as of September 30 2004, among, Plains Exploration & Production Company, each of the subsidiary guarantor parties thereto, each of the lenders that is a signatory thereto, and J.P. Morgan Chase Bank as administrative agent.

10.2	*	First Amendment to Crude Oil Marketing Agreement dated July 15, 2004, dated as of October 19, 2004, among Plains Exploration & Production Company, Arguello, Inc., PXP Gulf Coast Inc., (“Sellers”) and Plains Marketing, L.P. (“Buyer”).

31.1	*	Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	*	Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	*	Chief Executive Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	*	Chief Financial Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Filed herewith

(b) Reports on Form 8-K


Date		Item(s)
July 1, 2004		5, 7
July 8, 2004		5, 7
July 18, 2004		7
September 7, 2004		7.01, 9.01
September 15, 2004		8.01, 9.01
September 22, 2004		8.01, 9.01
September 30, 2004		1.01, 9.01

Items 3, 4 & 5 are not applicable and have been omitted.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	PLAINS EXPLORATION & PRODUCTION COMPANY.

Date: November 5, 2004	By:	/s/ STEPHEN A. THORINGTON
		Stephen A. Thorington
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)