Plains Exploration & Production 10-Q 2005 Q2 Quarterly report

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 June 30, 2005

OR

¨ 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)

(713) 579-6000

(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.    Yesx    No¨

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

78.3 million shares of Common Stock, $0.01 par value, issued and outstanding at August 1, 2005.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION
ITEM 1. Unaudited Financial Statements:
Condensed Consolidated Balance Sheets June 30, 2005 and December 31, 2004	1
Condensed Consolidated Statements of Income For the three months and six months ended June 30, 2005 and 2004	2
Condensed Consolidated Statements of Cash Flows For the six months ended June 30, 2005 and 2004	3
Condensed Consolidated Statements of Comprehensive Income For the three months and six months ended June 30, 2005 and 2004	4
Condensed Consolidated Statement of Changes in Stockholders’ Equity For the six months ended June 30, 2005	5
Notes to Condensed Consolidated Financial Statements	6
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk	40
ITEM 4. Controls and Procedures	43
PART II. OTHER INFORMATION	44

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	June 30,         2005			December 31,           2004
ASSETS
Current Assets
Cash and cash equivalents	$	969		$	1,545
Accounts receivable - Plains All American Pipeline, L.P.		33,450			26,224
Other accounts receivable		94,832			96,064
Inventories		10,625			8,505
Deferred income taxes		122,033			76,823
Assets held for sale		-			44,222
Other current assets		6,912			4,784
		268,821			258,167
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		2,388,244			2,402,179
Not subject to amortization		90,565			79,405
Other property and equipment		15,142			12,546
		2,493,951			2,494,130
Less allowance for depreciation, depletion and amortization		(410,834	)		(323,041	)
		2,083,117			2,171,089
Goodwill		172,558			170,467
Other Assets		34,760			33,522
	$	2,559,256		$	2,633,245
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	99,152		$	90,469
Commodity derivative contracts		208,698			175,473
Royalties payable		38,958			39,174
Stock appreciation rights		54,681			34,589
Interest payable		13,328			13,070
Deposit on assets held for sale		-			40,711
Other current liabilities		31,260			32,909
		446,077			426,395
Long-Term Debt
8.75% Senior Subordinated Notes		276,634			276,727
7.125% Senior Notes		248,788			248,741
Revolving credit facility		226,500			110,000
		751,922			635,468
Other Long-Term Liabilities
Asset retirement obligation		141,622			126,850
Commodity derivative contracts		354,293			244,140
Other		7,257			10,534
		503,172			381,524
Deferred Income Taxes		223,962			319,483
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common stock		775			772
Additional paid-in capital		924,956			913,466
Retained earnings (deficit)		(172,600	)		80,406
Accumulated other comprehensive income		(119,008	)		(123,874	)
Treasury stock, at cost		-			(395	)
		634,123			870,375
	$	2,559,256		$	2,633,245

See notes to consolidated financial statements.

1

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	87,799		$	63,019		$	162,407		$	127,286
Other oil sales		118,691			59,145			224,241			63,182
Oil hedging		(43,818	)		(22,600	)		(89,263	)		(41,633	)
Gas sales
Sales related to buy/sell contracts (Note 1)		8,328			3,885			16,084			3,885
Other		46,377			50,952			92,274			93,338
Gas hedging		(807	)		(2,129	)		19			(1,061	)
Other operating revenues		738			498			1,621			734
		217,308			152,770			407,383			245,731
Costs and Expenses
Production costs
Lease operating expenses		36,877			28,604			69,205			47,565
Steam gas costs
Costs related to buy/sell contracts (Note 1)		8,716			3,909			16,837			3,909
Other		7,688			3,445			16,248			4,402
Electricity		8,186			6,751			14,761			12,513
Production and ad valorem taxes		5,967			4,580			13,303			8,553
Gathering and transportation expenses		2,404			1,790			5,949			2,986
General and administrative (Note 1)		18,342			13,222			55,870			33,314
Depreciation, depletion and amortization		45,745			29,991			89,338			45,831
Accretion		1,934			1,877			3,679			2,604
		135,859			94,169			285,190			161,677
Income from Operations		81,449			58,601			122,193			84,054
Other Income (Expense)
Interest expense		(14,158	)		(8,607	)		(25,561	)		(15,537	)
Gain (loss) on mark-to-market derivative contracts		(113,871	)		374			(487,923	)		(1,191	)
Debt extinguishment costs		-			(19,691	)		-			(19,691	)
Interest and other income (expense)		(120	)		43			172			305
Income (Loss) Before Income Taxes		(46,700	)		30,720			(391,119	)		47,940
Income taxes
Current		(1,330	)		44			(1,330	)		(144	)
Deferred		700			(11,871	)		139,501			(18,505	)
Net Income (Loss)	$	(47,330	)	$	18,893		$	(252,948	)	$	29,291
Earnings (Loss) Per Share
Basic	$	(0.61	)	$	0.32		$	(3.27	)	$	0.59
Diluted	$	(0.61	)	$	0.32		$	(3.27	)	$	0.58
Weighted Average Shares Outstanding
Basic		77,329			59,602			77,266			49,925
Diluted		77,329			59,925			77,266			50,207

See notes to consolidated financial statements.

2

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

	Six Months Ended June 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(252,948	)	$	29,291
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		93,017			48,435
Deferred income taxes		(139,501	)		18,505
Debt extinguishment costs		-			(4,453	)
Commodity derivative contracts
Loss (gain) on derivatives		291,914			(18,571	)
Reclassify financing derivative settlements		270,742			19,762
Noncash compensation
Stock appreciation rights		16,900			3,573
Other		7,014			14,300
Other noncash items		(46	)		(79	)
Change in assets and liabilities from operating activities, net of effect of acquisitions
Accounts receivable and other assets		(8,066	)		19,329
Accounts payable and other liabilities		(22,620	)		(22,359	)
Commodity derivative contracts		(142,938	)		11,140
Net cash provided by operating activities		113,468			118,873
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development costs		(180,764	)		(78,416	)
Acquisition of oil and gas properties		(118,375	)		-
Acquisition of Nuevo Energy Company, net of cash acquired		-			(13,744	)
Proceeds from sales of properties		340,969			27,844
Other property and equipment		(2,596	)		(5,202	)
Net cash provided by (used in) investing activities		39,234			(69,518	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		751,000			598,250
Repayments		(634,500	)		(456,250	)
Proceeds from issuance of 7.125% Senior Notes		-			248,695
Retirement of debt assumed in acquisition of
Nuevo Energy Company		-			(405,000	)
Costs incurred in connection with financing arrangements		(1,490	)		(7,799	)
Derivative settlements		(270,742	)		(19,762	)
Other		2,454			(183	)
Net cash used in financing activities		(153,278	)		(42,049	)
Net increase (decrease) in cash and cash equivalents		(576	)		7,306
Cash and cash equivalents, beginning of period		1,545			1,377
Cash and cash equivalents, end of period	$	969		$	8,683

See notes to consolidated financial statements.

3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(in thousands of dollars)

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Net Income (Loss)	$	(47,330	)	$	18,893		$	(252,948	)	$	29,291
Other Comprehensive Income (Loss)
Commodity hedging contracts
Change in fair value		2,332			(59,435	)		(83,314	)		(125,537	)
Reclassification adjustment for settled contracts		16,895			24,533			33,094			42,381
Reclassification adjustment for terminated contracts		27,252			-			56,338			-
Related income taxes		(21,477	)		13,825			(1,252	)		32,975
Other
Interest rate swap and minimum pension liability		-			62			-			103
Related income taxes		-			(26	)		-			(43	)
		25,002			(21,041	)		4,866			(50,121	)
Comprehensive Income (Loss)	$	(22,328	)	$	(2,148	)	$	(248,082	)	$	(20,830	)

See notes to consolidated financial statements.

4

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)

	Common Stock			Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income			Treasury Stock					Total
	Shares	Amount											Shares		Amount
Balance, December 31, 2004	77,179	$	772	$	913,466		$	80,406		$	(123,874	)	(32	)	$	(395	)	$	870,375
Net loss	-		-		-			(252,948	)		-		-			-			(252,948	)
Other comprehensive income	-		-		-			-			4,866		-			-			4,866
Restricted stock awards
Issuance of stock	136		1		-			-			-		-			-			1
Deferred compensation	-		-		9,334			-			-		-			-			9,334
Treasury stock transactions	-		-		(337	)		(58	)		-		32			395			-
Exercise of stock options and other	162		2		2,493			-			-		-			-			2,495
Balance, June 30, 2005	77,477	$	775	$	924,956		$	(172,600	)	$	(119,008	)	-		$	-		$	634,123

See notes to consolidated financial statements.

5

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1—Organization and Significant Accounting Policies

Organization

The consolidated financial statements of Plains Exploration & Production Company (“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 June 30, 2005 and December 31, 2004, the results of our operations and our comprehensive income for the three months and six months ended June 30, 2005 and 2004, our cash flows for the six months ended June 30, 2005 and 2004 and the changes in our stockholders’ equity for the six months ended June 30, 2005. 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 of our operations for the six months ended June 30, 2005 are not necessarily indicative of the results of our operations 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 for the year ended December 31, 2004.

Accounting Policies

Asset Retirement Obligations.    The following table illustrates the changes in our asset retirement obligation (ARO) during the six months ended June 30, 2005 (in thousands):

Asset retirement obligation - beginning of period	$	130,469
Settlements		(413	)
Property dispositions		(2,989	)
Accretion expense		3,679
Asset retirement additions		14,098
Asset retirement obligation - end of period	$	144,844	(1)

(1) $3.2 million included in current liabilities.

Earnings Per Share.    For the three months and six months ended June 30, 2005 and 2004 the weighted average shares outstanding for computing basic and diluted earnings per share were (in thousands):

	Three Months Ended June 30,		Six Months Ended June 30,
	2005	2004	2005	2004
Common shares outstanding - basic	77,329	59,602	77,266	49,925
Unvested restricted stock, restricted stock units and stock options	-	323	-	282
Common shares outstanding - diluted	77,329	59,925	77,266	50,207

6

Due to our net loss in 2005 our unvested restricted stock, restricted stock units and stock options (943,000 and 895,000 equivalent shares for the three months and six months ended June 30, 2005, respectively) 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):

	June 30, 2005		December 31, 2004
Oil	$	1,526	$	1,526
Materials and supplies		9,099		6,979
	$	10,625	$	8,505

General and Administrative Expense.    Our general and administrative (“G&A”) expense consists of (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
G&A excluding items below	$	11,511	$	8,467	$	23,238	$	15,510
Stock appreciation rights		2,905		2,865		25,877		13,426
Other stock-based compensation		3,926		1,890		6,755		4,378
	$	18,342	$	13,222	$	55,870	$	33,314

At June 30, 2005 we had outstanding approximately 1.3 million of restricted stock units with a provision for accelerated vesting if the closing price of our common stock was equal to or greater than $37.92 per share for any ten of twenty consecutive trading days. Such units vested on July 21, 2005 and as a result in the third quarter of 2005 we will recognize approximately $18.8 million of pre-tax non-cash stock-based compensation expense with respect to such units. After withholding the required amounts to pay federal withholding and related taxes, we issued approximately 0.8 million shares of common stock to the holders of the restricted stock units.

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.

Buy/Sell Contracts.    Steam generators utilized in our thermal recovery operations in California are fueled by natural gas. In certain instances we have entered into buy/sell contracts that allow us to exchange gas we produce elsewhere for gas delivered to our thermal recovery operations. The buy/sell transactions result in us making or receiving physical delivery of the gas and involve the attendant risks and rewards of ownership, including title transfer. We did not enter into buy/sell contracts in periods prior to our acquisition of Nuevo Energy Company in May 2004.

We account for buy/sell contracts in the same manner as any other monetary transaction for which title passes and the risk and reward of ownership are assumed by the counterparties. The SEC has

7

questioned whether the industry’s accounting for buy/sell contracts should instead be shown net on the income statement and accounted for under the provisions of Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions” (APB 29). The topic is under deliberation by the Emerging Issues Task Force (EITF) of the FASB as Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The EITF first discussed this issue in November 2004 and again in March 2005. Additional research is being performed by the FASB staff, and the topic will be discussed again at a future EITF meeting. While this issue is under deliberation, the SEC staff directed companies in a February 2005 letter to disclose on the face of the income statement, if material, the amounts associated with buy/sell contracts and to discuss in a footnote to the financial statements the basis for the underlying accounting.

We believe our buy/sell contracts are monetary transactions that are outside the scope of APB 29. We also believe our accounting is supported by the indicators of gross reporting of purchases and sales in paragraph 3 of EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.”

Stock Based Compensation.    We account for stock based compensation using the intrinsic value method. No adjustments to our net income or earnings per share would be required under SFAS No. 123, “Accounting for Stock-Based Compensation”.

Federal and State Income Taxes.    During interim periods income tax expense is generally based on the estimated effective income tax rate that is expected for the entire year. In the second quarter, the Company revised its estimated 2005 annual effective tax rate to a 35.3% benefit from the 40.3% benefit that was utilized in the first quarter. As a result, the Company’s tax rate for the second quarter was 1% to reflect the change to the annual effective rate. The change in the estimated annual tax rate is primarily due to (1) a cumulative charge to income tax expense to reflect an increase in the estimated California apportionment factor as a result of the sale of the Company’s properties in East Texas and Oklahoma and the purchase of California properties, both in the second quarter of 2005, and (2) the effect of a permanent difference primarily resulting from the vesting in July 2005 of performance based restricted stock units that are not deductible because of IRS limitations on deductions for executive compensation. Our estimated effective tax rate was approximately 39% in 2004.

Variances in our reported tax rate from the 35% federal statutory rate are caused by state income taxes, EOR credits and various other items. EOR credits are a credit against federal and state income taxes for certain costs related to extracting high-cost oil, utilizing certain prescribed “enhanced” (tertiary) recovery methods. During periods when PXP reports net income, the benefit from the EOR credits should generally reduce our effective tax rate below the statutory rates. During periods when we report a net loss, the benefit from the EOR credits will generally increase our effective tax rate above the statutory rates. In 2005 we reported a net loss due to the mark-to-market derivative losses, and the EOR credits had the effect of increasing our tax benefit rate. The increase in the tax benefit rate attributable to the EOR credits was offset by the items discussed above, resulting in the estimated annual benefit rate of 35.3% for 2005.

Recent Accounting Pronouncements.    In December 2004 the FASB issued SFAS No.123R (revised 2004), “Share-Based Payment” (“SFAS 123R”). SFAS 123R requires that the compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. SFAS 123R covers a wide range of share-based compensation arrangements including stock options, restricted stock plans, performance-based awards, stock appreciation rights, and employee stock purchase plans. SFAS 123R replaces FASB Statement No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” Public entities (other

8

than those filing as small business issuers) were originally required to apply SFAS 123R as of the first interim or annual reporting period that begins after June 15, 2005. On April 14, 2005 the SEC announced the adoption of a new rule that amends the compliance dates for SFAS 123R. The Commission’s new rule allows registrants to implement SFAS 123R at the beginning of their next fiscal year, instead of the next reporting period, that begins after June 15, 2005. Accordingly, we will adopt SFAS 123R effective January 1, 2006. We are in the process of determining how the new method of valuing stock-based compensation as prescribed in SFAS 123R will be applied to valuing stock-based awards and the impact the recognition of compensation expense related to such awards will have on our financial statements.

In February 2005, the SEC issued guidance concerning the specific circumstance of a property disposition by a company that follows the full cost accounting method that resulted in a less than 25% alteration of the proved oil and gas reserve quantities within a full cost center. In connection with that disposition, the SEC considered if goodwill should be allocated to the property disposed, and, if so, whether that allocated goodwill should remain as a component of the capitalized full cost center or be reflected in the statement of operations.

The SEC concluded that only the fair value allocated to the oil and gas properties in a business acquisition should be included in the costs accounted for under Rule 4-10(c) of Regulation S-X. Goodwill associated with acquisitions of oil and gas properties that constitute a business is recognized in accordance with FASB Statement No. 141, “Business Combinations” but accounted for outside of the full cost rules. Therefore, when dispositions of these properties occur, the goodwill previously recognized does not affect the associated adjustments contemplated under Rule 4-10(c)(6)(i). Rather, the accounting for the goodwill and any potential impairment should follow the provisions of FASB Statement No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). Companies are required to consider whether a property disposition that results in a less than 25% alteration of the proved oil and gas reserve quantities within a given cost center is a trigger that requires goodwill be evaluated for impairment under SFAS 142. We determined that an evaluation of goodwill for impairment under FAS 142 was not required as a result of the property dispositions in the second quarter of 2005. The SEC has not yet addressed whether any portion of goodwill should be allocated to a disposition of greater than 25%, but less than 100%, of the oil and gas reserves in a given cost center.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. We do not believe that our financial position, results of operations or cash flows will be impacted by this Interpretation.

In June 2005 the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (SFAS 154), which changes the requirements for the accounting for and reporting of a change in accounting principle by requiring voluntary changes in accounting principles to be reported using retrospective application, unless impracticable to do so. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Application is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Early adoption is permitted. We do not believe that our financial position, results of operations or cash flows will be impacted by SFAS 154.

9

Note 2—Derivative Instruments and Hedging Activities

General

We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. 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, both realized and unrealized, are recognized currently in our income statement as gain (loss) on mark-to-market derivative contracts. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty. If a derivative is designated as a cash flow hedge and qualifies for hedge accounting, any unrealized gain or loss is deferred in accumulated Other Comprehensive Income (OCI), a component of Stockholders’ Equity, until the hedged oil and gas production is sold. 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. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain in OCI until the related product has been delivered.

Elimination of 2006 Swap & Collar Positions

In March 2005 we executed a series of contracts that eliminated all of our 2006 oil price swaps and collars at a pre-tax cost of $292.7 million. Approximately $145.4 million of this amount is attributable to 2006 collars for 22,000 barrels of oil per day with a floor price of $25.00 and an average ceiling price of $34.76. The collars were not accounted for as hedges, therefore, the $145.4 million loss in the fair value of these instruments was currently recognized in our income statement and there will be no income statement effect subsequent to March 31, 2005. Approximately $147.3 million of the cost is attributable to 2006 swaps for 15,000 barrels of oil per day at an average price of $25.28. We used hedge accounting for the swaps through March 2005 and as a result the $145.8 million loss in fair value attributable to the swaps has been deferred in OCI and will be recognized as a noncash reduction to oil revenues in 2006 when the hedged production is sold.

In May 2005 we completed the transactions to eliminate all of our 2006 oil price swaps and collars and paid the $292.7 million due under the contracts with proceeds received from the property sale discussed in Note 5. Under SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”, the collars were deemed to contain a significant financing element because they included off-market terms. Accordingly, the $145.4 million cash payment for the collars is reflected as a financing cash outflow in our statement of cash flows. The $147.3 million cash payment for the swaps is reflected as an operating cash outflow in our statement of cash flows. These payments reduced derivative liabilities on our balance sheet.

Acquisition of Floors for 2006 and 2007 Oil Production

In the first half of 2005 we acquired $45.00 NYMEX put options on 50,000 barrels of oil per day in 2006 and 20,000 barrels of oil per day in 2007. These put options cost an average of $2.95 per barrel for 2006 and $4.43 per barrel for 2007, which will be paid when the options are settled. We have elected not to use hedge accounting for the puts, consequently, the puts are marked-to-market with fair value gains and losses recognized as a gain or loss on mark-to-market derivative contracts on the income statement.

10

Derivative Instruments Designated as Cash Flow Hedges

At June 30, 2005 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
2005
July - December	Natural gas	Swap	5,000 /MMBtu	$	4.40	Waha
Purchases of Natural Gas
2005
July - 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.

Derivative Instruments Not Designated as Hedging Instruments

At June 30, 2005 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
2005
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
July - December	Crude oil	Collar	22,000 /Barrels	$25.00 Floor-$34.76 Ceiling	WTI
2006
January - December	Crude oil	Put options	50,000 /Barrels	$45.00	WTI
2007
January - December	Crude oil	Collar	22,000 /Barrels	$25.00 Floor-$34.76 Ceiling	WTI
January - December	Crude oil	Put options	20,000 /Barrels	$45.00	WTI
2008
January - December	Crude oil	Collar	22,000 /Barrels	$25.00 Floor-$34.76 Ceiling	WTI

The average price for the put options does not reflect the cost to purchase such options.

During the three and six months ended June 30, 2005 we recognized pre-tax losses of $113.9 million and $487.9 million, respectively, from derivatives that do not qualify for hedge accounting. During the three and six months ended June 30, 2005 we made cash payments of $50.9 million and $87.8 million on derivatives that do not qualify for hedge accounting that settled during the period. In addition, in the second quarter we made a $145.4 million cash payment to eliminate our 2006 oil price collars.

11

Physical Purchase Contracts

Although not a derivative, at June 30, 2005 we also had 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
2005
July - December	Natural gas	Physical purchase	10,000 /MMBtu	$4.19	Socal

Other Comprehensive Income

During the three months and six months ended June 30, 2005, net deferred losses of $44.1 million and $89.3 million, respectively, were reclassified from OCI and charged to oil and gas revenues and steam gas costs and in the six months ended June 30, 2005 we recognized $0.1 million for ineffectiveness of derivatives that qualify for hedge accounting. During the three months and six months ended June 30, 2004, net deferred losses of $24.5 million and $42.4 million, respectively, were reclassified from OCI and charged to oil and gas revenues and steam gas costs and in the three months and six months ended June 30, 2004 we recognized $0.1 million and $0.2 million, respectively, for ineffectiveness of derivatives that qualify for hedge accounting.

At June 30, 2005 OCI consisted of $194.7 million ($119.0 million after tax) of deferred losses on our hedging instruments, including $49.8 million ($30.4 million, net of tax) of deferred losses attributable to the cancelled 2005 swaps and $145.8 million ($89.1 million, net of tax) of deferred losses attributable to the cancelled 2006 swaps. At December 31, 2004, OCI consisted of $200.9 million ($123.9 million after tax) of unrealized losses on our open hedging instruments, including $106.2 million ($65.5 million, net of tax) of deferred losses attributable to the cancelled 2005 swaps.

During the twelve months ended June 30, 2006, based on quoted market prices for future delivery as of June 30, 2005, we expect to reclassify $0.8 million of net deferred gains associated with open derivative contracts and $122.9 million of net deferred losses on terminated derivative contracts from OCI to oil and gas revenue. Also during such period, we expect to reclassify approximately $47.5 million of deferred income tax benefits from OCI to income tax expense. The amounts ultimately reclassified to earnings will vary due the actual realized value upon settlement.

Net pre-tax deferred losses associated with terminated or de-designated derivative contracts that have been or will be reclassified from OCI and recognized as a non-cash reduction in our 2005 and 2006 oil revenues are as follows (in millions):

	2005		2006
1st Quarter	$	29.1	$	36.5
2nd Quarter		27.3		36.6
3rd Quarter		25.7		36.6
4th Quarter		24.1		36.1

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Note 3—Long-Term Debt

At June 30, 2005 and December 31, 2004 debt, all of which is classified as long-term, consisted of (in millions):

	June 30, 2005		December 31, 2004
Senior revolving credit facility	$	226.5	$	110.0
8.75% senior subordinated notes, including unamortized premium of $1.6 million in 2005 and $1.7 million in 2004		276.6		276.7
7.125% senior notes, including unamortized discount of $1.2 million in 2005 and $1.3 million in 2004		248.8		248.7
	$	751.9	$	635.4

Senior Revolving Credit Facility.    On May 16, 2005 we entered into an Amended and Restated Credit Agreement (the “Amended Credit Agreement”) which amended and restated our $500 million senior revolving credit facility. The Amended Credit Agreement increased the facility size to $750 million and established an initial borrowing base of $750 million. The borrowing base will be redetermined on a semi-annual basis, with PXP and the lenders each having the right to one annual interim unscheduled redetermination, and may be adjusted based on PXP’s oil and gas properties, reserves, other indebtedness and other relevant factors. Additionally, the Amended Credit Agreement contains a $75 million sub-limit for letters of credit. The Amended Credit Agreement matures on May 16, 2010. Collateral consists of 100% of the shares of stock of our domestic subsidiaries and mortgages covering at least 80% of the total present value of our domestic oil and gas properties.

The Amended Credit Agreement also modifies certain covenants to provide additional flexibility regarding the issuance of debt, the disposition of non oil and gas properties and mergers of subsidiaries. The Amended Credit Agreement also resets as of June 30, 2005 the financial covenant test with respect to tangible net worth. The effective interest rate on our borrowings under the Amended Credit Agreement was 4.2% at June 30, 2005. At that date we were in compliance with the covenants contained in the Amended Credit Agreement and could have borrowed the full amount available under the Amended Credit Agreement.

Short-term Credit Facility.    In May 2005 we amended our uncommitted short-term credit facility to extend its term and increase the facility size. We may make borrowings from time to time until May 27, 2006, not to exceed at any time the maximum principal amount of $25.0 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 May 27, 2006. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and the Company. No amounts were outstanding under the short-term credit facility at June 30, 2005.

Note 4—Related Party Transactions

Our Chief Executive Officer is a director of Vulcan Energy Corporation (“Vulcan Energy” formerly known as Plains Resources). In connection with the reorganization and our 2002 spin-off from Plains Resources we entered into certain agreements with Plains Resources, including a master separation agreement; the Plains Exploration & Production transition services agreement that expired June 16, 2004; the Plains Resources transition services agreement that expired June 8, 2004; and a technical services agreement that expired June 30, 2004. For the three months and six months ended June 30, 2004 we billed Plains Resources $0.1 million and $0.4 million, respectively, for services provided by us under these agreements. In addition, for the six months ended June 30, 2004 we billed Plains Resources $0.2 million for administrative costs associated with certain special projects performed on their behalf.

13

Our Chief Executive Officer is a member of Cypress Aviation LLC (“Cypress”). In June 2004, based on third party valuations we acquired two aircraft from Cypress for $4.5 million. Prior to the acquisition 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 three months and six months ended June 30, 2004, we paid Gulf Coast $0.2 million and $0.4 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 Energy. 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 six months ended June 30, 2005 and 2004, the following amounts were recorded with respect to such transactions (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
Sales of oil to PAA
PXP’s share	$	87,799	$	63,019	$	162,407	$	127,286
Royalty owners’ share		12,727		12,490		29,716		25,476
	$	100,526	$	75,509	$	192,123	$	152,762
Charges for PAA marketing fees	$	310	$	354	$	619	$	750

Note 5—Acquisitions and Dispositions

Nuevo Energy Company

On May 14, 2004 we acquired Nuevo Energy Company (“Nuevo”) in a stock-for-stock transaction (the “Nuevo acquisition”). In the Nuevo 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 Nuevo acquisition required the issuance of 36.5 million additional PXP common shares, plus the assumption of $254 million in net debt and $115 million of $2.875 Term Convertible Securities, Series A, or TECONS. We accounted for the Nuevo acquisition as a purchase effective May 14, 2004. We have completed our evaluation of the assets acquired and liabilities assumed at the time of the acquisition and during the first half of 2005 goodwill related to the acquisition was increased by $2.1 million.

The following unaudited pro forma information shows the pro forma effect of the Nuevo acquisition, the issuance by PXP on June 30, 2004 of $250 million of 7.125% Senior Notes due 2014, the retirement of Nuevo’s 9 ³/8% Senior Subordinated Notes and TECONS on June 30, 2004 and the sale of Nuevo’s Congo operations. This unaudited pro forma information assumes such transactions occurred on January 1, 2004.

14

This unaudited pro forma information has been prepared based on our historical consolidated statements of income and the historical consolidated statement of income of Nuevo. 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 January 1, 2004.

(in thousands, except per share data)	Three Months Ended June 30, 2004		Six Months Ended June 30, 2004
Revenues	$	195,658	$	380,662
Income from operations		67,157		103,607
Net income		17,436		27,717
Basic and diluted earnings per share	$	0.23	$	0.36
Weighted average shares outstanding
Basic		76,851		76,792
Diluted		77,255		77,155

Pro forma net income has been reduced by debt extinguishment costs of $19.7 million ($12.1 million after tax) and $22.7 million ($14.0 million after tax), respectively, in the three months and six months ended June 30, 2004.

Other

On April 1, 2005 we acquired certain California producing oil and gas properties from a private company for $118 million. The properties are primarily located in the Los Angeles Basin of onshore California with some smaller properties located in adjacent Ventura County.

On May 31, 2005 we closed the sale to XTO Energy, Inc. of interests in producing properties located in East Texas and Oklahoma for net proceeds of approximately $335 million. The proceeds were primarily used to fund the transactions to eliminate all of our 2006 oil price swaps and collars as discussed in Note 2. As of December 31, 2004, our independent reserve engineers estimated that these producing properties had proven reserves of approximately 27 million equivalent barrels of which 81% was proved developed. The properties produced approximately 5,800 net equivalent barrels per day at March 31, 2005.

Prior to our acquisition of Nuevo, Nuevo sold its Tonner Hills real estate property and received $40.7 million of the purchase price with the remainder due upon completion of certain habitat restoration activities. We completed the required restoration and in the second quarter of 2005 we received the $6.5 million due under the terms of the agreement. The fair value of our investment in the property at December 31, 2004 is reflected on the balance sheet in current assets under the caption assets held for sale and the $40.7 million that had been received as of that date is reflected on the balance sheet in current liabilities, as such amounts were accounted for as deposits until the completion of the habitat restoration activities.

Note 6—Commitments and Contingencies

Environmental matters.    As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. Often these regulations are more burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have operated for over 90 years. We have established policies for continuing compliance with environmental laws and regulations. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations.

15

In January 2005 we discovered and self-reported a violation related to flared gas emissions in excess of permitted levels on properties acquired in the Nuevo acquisition. Estimated excess emissions from the San Joaquin Valley casing vent recovery system located on the Gamble Lease are approximately 881 tons over a 745 day period. We brought the facility into compliance within 10 days of discovering the violation. In July 2005 we reached an agreement to settle this matter for $750,000.

Plugging, Abandonment and Remediation Obligations.    Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically, when producing oil and gas assets are purchased the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we receive an indemnity with respect to those costs. There can be no assurance that we will be able to collect on these indemnities.

In connection with the sale of certain properties offshore California in December 2004 we retained the responsibility for certain abandonment costs, including removing, dismantling and disposing of the existing offshore platforms. Such abandonment costs are included in our asset retirement obligation as reflected on our consolidated balance sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $44 million). The fair value of our obligation, $0.4 million, is included in Other Long-Term Liabilities in the Consolidated balance Sheet.

Operating risks and insurance coverage.    Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including well blowouts, cratering, explosions, oil spills, gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property, or injury to persons. Our operations in California, including transportation of oil by pipelines within the city and county of Los Angeles, are especially susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. Although we maintain insurance coverage considered to be customary in the industry for a company our size, we are not fully insured against all risks, either because insurance is not available or because of high premium costs. We maintain coverage for earthquake damages in California but this coverage may not provide for the full effect of damages that could occur and we may be subject to additional liabilities. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences.

Sale of Nuevo’s Congo operations.    Upon our acquisition of Nuevo, we became a party to an existing agreement between Nuevo, CMS NOMECO Oil & Gas Co. (CMS) and a third party. Under the agreement, Nuevo and CMS may be liable to the third party for the recapture of dual consolidated losses (DCLs) in connection with each company’s 1995 acquisition of Congolese properties. Nuevo and CMS agreed to indemnify each other for any act that would cause the third party to experience a liability from the recapture of DCLs as a result of a triggering event.

CMS sold its interest in the Congolese properties to a subsidiary of Perenco, S.A. (Perenco) in 2002. Both CMS and Perenco, have received from the Internal Revenue Service (IRS), in accordance with the U.S. consolidated return regulations, a closing agreement confirming that the transaction will not trigger recapture. We and Perenco have finalized a closing agreement with the IRS confirming that neither our merger with Nuevo, nor the sale of our interest in the Congolese properties to Perenco will

16

trigger recapture. The estimated remaining contingent liabilities are $19.2 million relative to Nuevo’s former interest, and $23.5 million relative to CMS’ former interest, for which we would be jointly liable. We believe the occurrence of a triggering event in the future is remote and we do not believe the agreements will have a material adverse affect upon us.

Other commitments and contingencies.    As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil and gas properties and the marketing, transportation and storage of oil. It is management’s belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

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—Consolidating Financial Statements

We are the issuer of $275 million of 8.75% Notes due 2012 and $250 million of 7.125% Notes due 2014. 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

• PXP on a consolidated basis.

17

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

JUNE 30, 2005

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	960		$	9		$	-		$	969
Accounts receivable and other current assets		260,991			6,861			-			267,852
		261,951			6,870			-			268,821
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		1,979,374			408,870			-			2,388,244
Not subject to amortization		40,287			50,278			-			90,565
Other property and equipment		14,456			686			-			15,142
		2,034,117			459,834			-			2,493,951
Less allowance for depreciation, depletion and amortization		(261,656	)		(149,178	)		-			(410,834	)
		1,772,461			310,656			-			2,083,117
Investment in and Advances to Subsidiaries		385,339			-			(385,339	)		-
Goodwill		27,512			145,046			-			172,558
Other Assets		24,126			10,634			-			34,760
	$	2,471,389		$	473,206		$	(385,339	)	$	2,559,256
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	176,761		$	60,618		$	-		$	237,379
Commodity derivative contracts		206,618			2,080			-			208,698
		383,379			62,698			-			446,077
Long-Term Debt		751,922			-			-			751,922
Other Long-Term Liabilities		476,809			26,363			-			503,172
Payable to Parent		-			60,972			(60,972	)		-
Deferred Income Taxes		225,156			(1,194	)		-			223,962
Stockholders’ Equity
Stockholders’ equity		753,131			370,881			(370,881	)		753,131
Accumulated other comprehensive income		(119,008	)		(46,514	)		46,514			(119,008	)
		634,123			324,367			(324,367	)		634,123
	$	2,471,389		$	473,206		$	(385,339	)	$	2,559,256

18

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

DECEMBER 31, 2004

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	876		$	669		$	-		$	1,545
Accounts receivable and other current assets		215,668			40,954			-			256,622
		216,544			41,623			-			258,167
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		1,817,709			584,470			-			2,402,179
Not subject to amortization		39,707			39,698			-			79,405
Other property and equipment		11,963			583			-			12,546
		1,869,379			624,751			-			2,494,130
Less allowance for depreciation, depletion and amortization		(209,224	)		(113,817	)		-			(323,041	)
		1,660,155			510,934			-			2,171,089
Investment in and Advances to Subsidiaries		612,538			-			(612,538	)		-
Goodwill		25,421			145,046			-			170,467
Other Assets		28,806			4,716			-			33,522
	$	2,543,464		$	702,319		$	(612,538	)	$	2,633,245
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	210,366		$	40,556		$	-		$	250,922
Commodity derivative contracts		172,800			2,673			-			175,473
		383,166			43,229			-			426,395
Long-Term Debt		635,468			-			-			635,468
Other Long-Term Liabilities		340,271			41,253			-			381,524
Payable to Parent		-			307,820			(307,820	)		-
Deferred Income Taxes		314,184			5,299			-			319,483
Stockholders’ Equity
Stockholders’ equity		994,249			353,629			(353,629	)		994,249
Accumulated other comprehensive income		(123,874	)		(48,911	)		48,911			(123,874	)
		870,375			304,718			(304,718	)		870,375
	$	2,543,464		$	702,319		$	(612,538	)	$	2,633,245

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2005

(in thousands)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	142,885		$	19,787		$	-		$	162,672
Gas sales		12,283			41,615			-			53,898
Other operating revenues		610			128			-			738
		155,778			61,530			-			217,308
Costs and Expenses
Production costs		55,521			14,317			-			69,838
General and administrative		14,329			4,013			-			18,342
Depreciation, depletion, amortization and accretion		28,638			19,041			-			47,679
		98,488			37,371			-			135,859
Income from Operations		57,290			24,159			-			81,449
Other Income (Expense)
Equity in earnings of subsidiaries		11,490			-			(11,490	)		-
Interest expense		(11,230	)		(2,928	)		-			(14,158	)
Gain (loss) on mark-to-market derivative contracts		(113,871	)		-			-			(113,871	)
Interest and other income (expense)		(120	)		-			-			(120	)
Income (Loss) Before Income Taxes		(56,441	)		21,231			(11,490	)		(46,700	)
Income taxes
Current		17,415			(18,745	)		-			(1,330	)
Deferred		(8,304	)		9,004			-			700
Net Income (Loss)	$	(47,330	)	$	11,490		$	(11,490	)	$	(47,330	)

20

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2004

(in thousands)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	30,242		$	69,322		$	-		$	99,564
Gas sales		4,636			48,072			-			52,708
Other operating revenues		-			498			-			498
		34,878			117,892			-			152,770
Costs and Expenses
Production costs		14,012			35,067			-			49,079
General and administrative		10,215			3,007			-			13,222
Depreciation, depletion, amortization and accretion		1,891			29,977			-			31,868
		26,118			68,051			-			94,169
Income from Operations		8,760			49,841			-			58,601
Other Income (Expense)
Equity in earnings of subsidiaries		18,636			-			(18,636	)		-
Debt extinguishment costs		-			(19,691	)		-			(19,691	)
Gain (loss) on mark-to-market derivative contracts		-			374			-			374
Interest expense		(6,885	)		(1,722	)		-			(8,607	)
Interest and other income (expense)		51			(8	)		-			43
Income Before Income Taxes		20,562			28,794			(18,636	)		30,720
Income taxes
Current		-			44			-			44
Deferred		(1,669	)		(10,202	)		-			(11,871	)
Net Income	$	18,893		$	18,636		$	(18,636	)	$	18,893

21

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2005

(in thousands)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	265,019		$	32,366		$	-		$	297,385
Gas sales		24,429			83,948			-			108,377
Other operating revenues		1,249			372			-			1,621
		290,697			116,686			-			407,383
Costs and Expenses
Production costs		99,079			37,224			-			136,303
General and administrative		51,738			4,132			-			55,870
Depreciation, depletion, amortization and accretion		55,813			37,204			-			93,017
		206,630			78,560			-			285,190
Income from Operations		84,067			38,126			-			122,193
Other Income (Expense)
Equity in earnings of subsidiaries		17,252			-			(17,252	)		-
Interest expense		(18,872	)		(6,689	)		-			(25,561	)
Gain (loss) on mark-to-market derivative contracts		(487,923	)		-			-			(487,923	)
Interest and other income (expense)		172			-			-			172
Income (Loss) Before Income Taxes		(405,304	)		31,437			(17,252	)		(391,119	)
Income taxes
Current		19,963			(21,293	)		-			(1,330	)
Deferred		132,393			7,108			-			139,501
Net Income (Loss)	$	(252,948	)	$	17,252		$	(17,252	)	$	(252,948	)

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2004

(in thousands)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	61,656		$	87,179		$	-		$	148,835
Gas sales		8,851			87,311			-			96,162
Other operating revenues		-			734			-			734
		70,507			175,224			-			245,731
Costs and Expenses
Production costs		28,416			51,512			-			79,928
General and administrative		29,203			4,111			-			33,314
Depreciation, depletion, amortization and accretion		4,570			43,865			-			48,435
		62,189			99,488			-			161,677
Income from Operations		8,318			75,736			-			84,054
Other Income (Expense)
Equity in earnings of subsidiaries		29,563			-			(29,563	)		-
Debt extinguishment costs		-			(19,691	)					(19,691	)
Gain (loss) on mark-to-market derivative contracts		-			(1,191	)		-			(1,191	)
Interest expense		(7,373	)		(8,164	)		-			(15,537	)
Interest and other income (expense)		313			(8	)		-			305
Income Before Income Taxes		30,821			46,682			(29,563	)		47,940
Income taxes
Current		-			(144	)		-			(144	)
Deferred		(1,530	)		(16,975	)		-			(18,505	)
Net Income	$	29,291		$	29,563		$	(29,563	)	$	29,291

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2005

(in thousands of dollars)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(252,948	)	$	17,252		$	(17,252	)	$	(252,948	)
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		55,813			37,204			-			93,017
Equity in earnings of subsidiaries		(17,252	)		-			17,252			-
Deferred income taxes		(132,393	)		(7,108	)		-			(139,501	)
Commodity derivative contracts
Loss (gain) on derivatives		265,215			26,699			-			291,914
Reclassify financing derivative settlements		268,634			2,108			-			270,742
Noncash compensation
Stock appreciation rights		16,900			-			-			16,900
Other		7,014			-			-			7,014
Other noncash items		(46	)		-			-			(46	)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(36,081	)		28,015			-			(8,066	)
Accounts payable and other liabilities		(21,074	)		(1,546	)		-			(22,620	)
Commodity derivative contracts		(142,938	)		-			-			(142,938	)
Net cash provided by operating activities		10,844			102,624			-			113,468
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development costs		(119,860	)		(60,904	)		-			(180,764	)
Acquisition of oil and gas properties		(1,629	)		(116,746	)		-			(118,375	)
Proceeds from sales of properties		6,500			334,469			-			340,969
Other property and equipment		(2,493	)		(103	)		-			(2,596	)
Net cash provided by (used in) investing activities		(117,482	)		156,716			-			39,234
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		751,000			-			-			751,000
Repayments		(634,500	)	��	-			-			(634,500	)
Costs incurred in connection with financing arrangements		(1,490	)		-						(1,490	)
Derivative settlements		(268,634	)		(2,108	)		-			(270,742	)
Investment in and advances to affiliates		257,892			(257,892	)					-
Other		2,454			-			-			2,454
Net cash provided by (used in) financing activities		106,722			(260,000	)		-			(153,278	)
Net increase (decrease) in cash and cash equivalents		84			(660	)		-			(576	)
Cash and cash equivalents, beginning of period		876			669			-			1,545
Cash and cash equivalents, end of period	$	960		$	9		$	-		$	969

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2004

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	29,291		$	29,563		$	(29,563	)	$	29,291
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		4,570			43,865			-			48,435
Equity in earnings of subsidiaries		(29,563	)		-			29,563			-
Deferred income taxes		1,530			16,975			-			18,505
Debt extinguishment costs		-			(4,453	)		-			(4,453	)
Commodity derivative contracts
Loss (gain) on derivatives		-			(18,571	)		-			(18,571	)
Reclassify financing derivative settlements		-			19,762			-			19,762
Noncash compensation
Stock appreciation rights		3,573			-			-			3,573
Other		14,300			-			-			14,300
Other noncash items		(79	)		-			-			(79	)
Change in assets and liabilities from operating activities
net of effect of acquisition
Accounts receivable and other assets		(14,281	)		33,610			-			19,329
Accounts payable and other liabilities		17,337			(39,696	)		-			(22,359	)
Commodity derivative contracts		-			11,140			-			11,140
Net cash provided by operating activities		26,678			92,195			-			118,873
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development costs		(24,710	)		(53,706	)		-			(78,416	)
Acquisition of Nuevo Energy Company, net of cash acquired		-			(13,744	)		-			(13,744	)
Proceeds from sales of properties		-			27,844			-			27,844
Other property and equipment		(5,202	)		-			-			(5,202	)
Net cash used in investing activities		(29,912	)		(39,606	)		-			(69,518	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		598,250			-			-			598,250
Repayments		(456,250	)		-			-			(456,250	)
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		(6,724	)		(1,075	)		-			(7,799	)
Derivative settlements		-			(19,762	)		-			(19,762	)
Investment in and advances to affiliates		(378,957	)		378,957			-			-
Other		(183	)		-			-			(183	)
Net cash provided by (used in) financing activities		4,831			(46,880	)		-			(42,049	)
Net increase in cash and cash equivalents		1,597			5,709			-			7,306
Cash and cash equivalents, beginning of period		403			974			-			1,377
Cash and cash equivalents, end of period	$	2,000		$	6,683		$	-		$	8,683

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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 and our report on Form 10-K for the year ended December 31, 2004.

Company Overview

We are an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploiting, exploring and producing oil and gas properties in the United States. We own oil and gas properties in five states with principal operations in:

• the Los Angeles and San Joaquin Basins onshore California;

• the Santa Maria Basin offshore California;

• the Gulf Coast Basin onshore and offshore Louisiana, including the Gulf of Mexico; and

• the Val Verde portion of the greater 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.

Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At June 30, 2005 we had approximately $517 million of availability under our revolving credit facility. We have a capital budget for 2005, excluding acquisitions, of approximately $425 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, derivative obligations, debt service obligations, contingencies and anticipated capital expenditures. In addition, the majority of our capital expenditures are discretionary and could be curtailed if our cash flows declined from expected levels.

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 manage our commodity price risk. Hedging may prevent us from receiving the full advantage of increases in oil or gas prices above the maximum fixed amount specified in the hedge agreement. The level of hedging activity depends on our view of market conditions, available hedge prices and our operating strategy (see “– Derivative Instruments and Hedging”).

Acquisitions and Dispositions

On April 1, 2005 we acquired certain California producing oil and gas properties from a private company for $118 million. The properties are primarily located in the Los Angeles Basin of onshore California with some smaller properties located in adjacent Ventura County. The transaction was financed under our credit facility.

We periodically evaluate and from time to time have elected to sell certain of our mature producing properties that we consider to be nonstrategic. Such sales enable us to focus on our core properties, maintain financial flexibility and redeploy the proceeds therefrom to activities that we believe potentially have a higher financial return. On May 31, 2005 we closed the sale to XTO Energy, Inc. of interests in producing properties located in East Texas and Oklahoma for net proceeds of approximately $335 million. The proceeds were primarily used to fund the transactions to eliminate all of our 2006 oil

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price swaps and collars as discussed in “– Derivative Instruments and Hedging”. As of December 31, 2004, our independent reserve engineers estimated that these producing properties had proven reserves of approximately 27 million equivalent barrels of which 81% were proved developed. The properties produced approximately 5,800 net equivalent barrels per day at March 31, 2005.

After taking into account the acquisition of the California oil and gas properties and the sale to XTO Energy as though such events occurred before year-end, we estimate our December 31, 2004 reserves would have been approximately 410 MMBOE, of which approximately 68% were proved developed.

Derivative Instruments and Hedging

For the remainder of 2005 we have in place crude oil price collars on approximately 36,000 barrels per day (approximately 14,000 barrels per day with a floor of $26.00 and an average ceiling of $29.68 and 22,000 barrels per day with a floor of $25.00 and an average ceiling of $34.76) and swaps on 5,000 MMbtu per day of natural gas sales at an average price of $4.40 per MMBtu. In addition, for 2007 and 2008 we have crude oil price collars on 22,000 barrels per day with a floor of $25.00 and an average ceiling of $34.76. For 2006 and 2007 we have $45.00 crude oil put options on 50,000 barrels per day and 20,000 barrels per day, respectively. The oil collars and puts are subject to mark-to-market accounting, consequently, as in the past, we expect that there will continue to be significant volatility in our reported earnings due to gains and losses as changes occur in the NYMEX price index.

In May 2005 we completed a series of transactions that eliminated our 2006 collars on 22,000 barrels of oil per day with a floor price of $25.00 and an average ceiling price of $34.76 and our 2006 swaps on 15,000 barrels of oil per day at an average price of $25.28 at a pre-tax cost of approximately $292.7 million (approximately $145.4 million attributable to the collars and $147.3 million attributable to the swaps).

The collars were not accounted for as hedges, therefore, the $145.4 million loss in the fair value of these instruments was currently recognized in our income statement and there will be no income statement effect subsequent to March 31, 2005. We used hedge accounting for the swaps through March 2005 and as a result the $145.8 million loss in fair value attributable to the swaps has been deferred in OCI and will be recognized as a noncash reduction to oil revenues in 2006 when the hedged production is sold. The $145.4 million cash payment for the collars is reflected as a financing cash outflow in our statement of cash flows and the $147.3 million cash payment for the swaps is reflected as an operating cash outflow in our statement of cash flows. These payments reduced derivative liabilities on our balance sheet.

The cost of eliminating the 2006 swaps and collars is a deductible expense for tax purposes. As a result of the tax deduction, as well as our existing net operating loss (“NOL”) and enhanced oil recovery (“EOR”) credit carryforwards, we do not expect to pay any significant federal or state income taxes in 2005.

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,

27

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 estimated proved reserves and our revenues, profitability and cash flow.

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 estimated proved reserves. For the purposes of computing depletion, estimated 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 Overview

In the second quarter of 2005 we reported a net loss of $47.3 million, or $0.61 per share, compared to a net income of $18.9 million, or $0.32 per share, in the second quarter of 2004. The loss in 2005 primarily reflects a $113.9 million derivative mark-to-market loss. Cash payments related to these derivative contracts that settled in the second quarter totaled $50.9 million. Our results for 2005 include the effect of the properties acquired in our 2004 acquisition of Nuevo, which are included in our 2004 results with effect from May 14, 2004.

Income from operations increased to $81.4 million in the second quarter of 2005 from $58.6 million in the second quarter of 2004. The improvement is primarily attributable to higher oil and gas sales as a result of increased sales volumes due to the Nuevo properties and increased oil and gas prices. The increase in income from operations was offset by the derivative mark-to-market loss and higher interest costs primarily related to the Nuevo acquisition.

Primarily as a result of a $487.9 million derivative mark-to-market loss, we reported a net loss of $252.9 million, or $3.27 per share for the first six months of 2005 compared to net income of $29.3 million, or $0.58 per diluted share for the first six months of 2004. Cash payments related to these derivative contracts totaled $233.3 million for the first six months of 2005, including the $145.4 million cash payment to eliminate our 2006 collars.

Income from operations increased to $122.2 million in the first half of 2005 from $84.1 million in the first half of 2004. The improvement is primarily attributable to higher oil and gas sales as a result of increased sales volumes due to the Nuevo properties and increased oil and gas prices. The increase in income from operations was offset by the derivative mark-to-market loss and higher interest costs primarily related to the Nuevo acquisition.

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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 BOE basis:

	Three Months Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
Sales Volumes
Oil and liquids (MBbls)		4,740		3,746		9,157		5,942
Gas (MMcf)		8,501		9,464		17,778		16,868
MBOE		6,157		5,323		12,120		8,753
Daily Average Sales Volumes
Oil and liquids (Bbls)		52,088		41,165		50,593		32,648
Gas (Mcf)		93,417		104,000		98,219		92,681
BOE		67,658		58,498		66,963		48,093
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	53.13	$	38.34	$	51.53	$	36.75
Henry Hub gas		6.73		6.01		6.50		5.84
Average Realized Sales Price Before Hedging
Oil (per Bbl)	$	43.56	$	32.61	$	42.22	$	32.06
Gas (per Mcf)		6.43		5.79		6.10		5.76
Per BOE		42.42		33.25		40.84		32.87
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	5.99	$	5.37	$	5.71	$	5.43
Steam gas costs		2.66		1.38		2.73		0.95
Electricity		1.33		1.27		1.22		1.43
Production and ad valorem taxes		0.97		0.86		1.10		0.98
Gathering and transportation		0.39		0.34		0.49		0.34
DD&A per BOE (oil and gas properties)		7.18		5.49		7.14		5.06

The following table reflects cash payments made with respect to derivative contracts that settled during the periods presented (in millions of dollars):

	Three Months Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
Contracts accounted for using hedge accounting
Oil	$	24.9	$	36.8	$	53.0	$	55.8
Gas		1.3		3.8		2.4		6.3
Mark-to-market contracts		50.9		4.6		87.9		5.6

Comparison of Three Months Ended June 30, 2005 to Three Months Ended June 30, 2004

Oil and gas revenues.    Oil and gas revenues increased $64.3 million, to $216.6 million for 2005 from $152.3 million for 2004. The increase is primarily due to increased production volumes attributable to the properties acquired in the Nuevo acquisition in May 2004 and higher realized prices.

Oil revenues, excluding the effects of hedging, increased $84.3 million to $206.5 million for 2005 from $122.2 million for 2004 reflecting higher realized prices ($41.0 million) and higher production ($43.3 million). Our average realized price for oil increased $10.95 to $43.56 per Bbl for 2005 from $32.61 per Bbl for 2004. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $51.53 per Bbl in 2005 versus $38.34 per Bbl in 2004. Oil production increased to 4.7 MMBbls in 2005 from 3.7 MMBbls in 2004. Production attributable to the properties acquired from Nuevo increased by 1.0 MMBbls as the properties were included in our results for the full quarter in 2005.

29

Hedging had the effect of decreasing our oil revenues by $43.8 million, or $9.24 per Bbl in 2005 compared to $22.6 million or $6.03 per Bbl in 2004. The 2005 amount includes $27.3 million of deferred losses related to 2005 swaps that were terminated in 2004. These losses were deferred in OCI until the production that was originally hedged was produced and delivered during the second quarter of 2005.

Gas revenues, excluding the effects of hedging, decreased $0.1 million to $54.7 million in 2005 from $54.8 million in 2004 reflecting higher realized prices ($6.1 million) offset by lower production ($6.2 million). Our average realized price for gas of $6.43 per Mcf for 2005 compared to $5.79 per Mcf for 2004. Gas production decreased from 9.5 Bcf in 2004 to 8.5 Bcf in 2005 primarily due to the sale of our properties in East Texas and Oklahoma.

Hedging had the effect of decreasing our gas revenues by $0.8 million, or $0.09 per Mcf in 2005 compared to $2.1 million or $0.22 per Mcf in 2004.

Lease operating expenses.    Lease operating expenses (including steam gas costs and electricity) increased $18.8 million, to $61.5 million for 2005 from $42.7 million for 2004, primarily due to the properties acquired from Nuevo which accounted for $33.7 million of our operating expenses in 2005 compared to $20.0 million in 2004. On a per unit basis, lease operating expenses increased to $9.98 per BOE in 2005 versus $8.02 per BOE in 2004. The per unit increase is primarily attributable to the steam gas costs attributable to the properties acquired from Nuevo. Steam gas costs averaged $2.66 per BOE in 2005 versus $1.38 per BOE in 2004.

Production and ad valorem taxes.    Production and ad valorem taxes increased $1.4 million, to $6.0 million for 2005 from $4.6 million for 2004 primarily due to the properties acquired from Nuevo ($2.3 million in 2005 versus $1.1 million in 2004) and increased oil and gas prices.

Gathering and transportation expenses.    Gathering and transportation expenses increased $0.6 million, to $2.4 million for 2005 from $1.8 million for 2004 primarily due to the properties acquired from Nuevo ($1.5 million in 2005 versus $0.8 million in 2004).

General and administrative expense.    Our G&A expense consists of (in thousands of dollars):

	Three Months Ended June 30,
	2005		2004
G&A excluding items below	$	11,511	$	8,467
Stock appreciation rights		2,905		2,865
Other stock-based compensation		3,926		1,890
	$	18,342	$	13,222

G&A expense, excluding amounts attributable to stock appreciation rights (“SARs”) and other stock based compensation, increased $3.0 million, to $11.5 million for 2005 from $8.5 million for 2004, primarily reflecting increased costs resulting from the Nuevo acquisition and to a lesser extent Sarbanes-Oxley compliance costs.

G&A expense related to SARs was $2.9 million in 2005 and 2004. 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. Such expense in 2005 and 2004 reflects additional vesting of outstanding SARs as well as an increase in our stock price in 2005 and a decrease in 2004. Our stock price was $35.53 per share on June 30, 2005 versus $34.90 per share on March 31, 2005 and $18.35 per share on June 30, 2004 versus $18.64 per share on March 31, 2004. In 2005 and 2004 we made cash payments of $5.9 million and $5.6 million, respectively, for SARs that were exercised during the period.

30

G&A expense for 2005 and 2004 includes other stock based compensation costs of $3.9 million and $1.9 million, respectively, related to restricted stock and restricted stock unit grants.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $4.6 million and $3.3 million of G&A expense in 2005 and 2004, respectively.

Depreciation, depletion and amortization, or DD&A.    DD&A expense increased $15.7 million, to $45.7 million in 2005 from $30.0 million in 2004. Approximately $15.0 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 $7.18 per BOE in 2005 compared to $5.49 per BOE in 2004. The increase primarily reflects the effect of the Nuevo acquisition.

Accretion expense.    Accretion expense was $1.9 million in 2005 and 2004. The increase attributable to asset retirement obligations related to acquisitions was offset by the impact of various property sales.

Interest expense.    Interest expense increased $5.6 million, to $14.2 million for 2005 from $8.6 million for 2004 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 $0.7 million and $1.9 million of interest in 2005 and 2004, respectively.

Gain (loss) on mark-to-market derivative contracts.    We do not use hedge accounting for certain of our derivative instruments, because the derivatives do not qualify or we have elected not to use hedge accounting. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts 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.

As a result of the increase in oil prices, we recognized a $113.9 million loss related to mark-to-market derivative contracts in the second quarter of 2005. Cash payments related to these contracts that settled in the second quarter of 2005 totaled $50.9 million. In the second quarter of 2004 we recognized a gain on mark-to-market derivative contracts of $0.4 million. Cash payments related to these contracts that settled in the second quarter of 2004 totaled $4.6 million.

Debt extinguishment costs.    In connection with the retirement of the debt assumed in the acquisition of Nuevo, in 2004 we recorded $19.7 million of debt extinguishment costs.

Income tax expense.    During interim periods income tax expense is generally based on the estimated effective income tax rate that is expected for the entire year. In the second quarter, the Company revised its estimated 2005 annual effective tax rate to a 35.3% benefit from the 40.3% benefit that was utilized in the first quarter. As a result, the Company’s tax rate for the second quarter was 1% to reflect the change to the annual effective rate. The change in the estimated annual tax rate is primarily due to (1) a cumulative charge of $5.7 million to income tax expense to reflect an increase in the estimated California apportionment factor as a result of the sale of the Company’s properties in East Texas and Oklahoma and the purchase of California properties, both in the second quarter of 2005, and (2) the $9.5 million effect of a permanent difference primarily resulting from the vesting in July 2005 of performance based restricted stock units that are not deductible because of IRS limitations on deductions for executive compensation. Our estimated effective tax rate was approximately 39% in 2004.

Variances in our reported tax rate from the 35% federal statutory rate are caused by state income taxes, EOR credits and various other items. EOR credits are a credit against federal and state income

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taxes for certain costs related to extracting high-cost oil, utilizing certain prescribed “enhanced” (tertiary) recovery methods. During periods when PXP reports net income, the benefit from the EOR credits should generally reduce our effective tax rate below the statutory rates. During periods when PXP reports a net loss, the benefit from the EOR credits will generally increase our effective tax rate above the statutory rates. In the current period, PXP reported a net loss due to the mark-to-market derivative losses, and the EOR credits had the effect of increasing our tax benefit rate. The increase in the tax benefit rate attributable to the EOR credits was offset by the items discussed above, resulting in the estimated annual benefit rate of 35.3% for 2005.

The payment to eliminate our 2006 oil price swaps and collars is tax deductible. As a result of this tax deduction, as well as our existing NOL and EOR credit carryforwards we do not expect to pay any significant federal or state income taxes in 2005.

Comparison of Six Months Ended June 30, 2005 to Six Months Ended June 30, 2004

Oil and gas revenues.    Oil and gas revenues increased $160.8 million, to $405.8 million for 2005 from $245.0 million for 2004. The increase is primarily due to increased production volumes attributable to the properties acquired in the Nuevo acquisition and higher realized prices.

Oil revenues, excluding the effects of hedging, increased $196.2 million, to $386.7 million for 2005 from $190.5 million for 2004, reflecting higher realized prices ($60.4 million) and higher production ($135.8 million). Our average realized price for oil increased $10.16 to $42.22 per Bbl for 2005 from $32.06 per Bbl for 2004. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $51.53 per Bbl in 2005 versus $36.75 per Bbl in 2004. Oil production increased to 9.2 MMBbls in 2005 from 5.9 MMBbls in 2004. Production attributable to the properties acquired from Nuevo was 5.3 MMBbls in 2005 compared to 1.7 MMBbls in 2004.

Hedging had the effect of decreasing our oil revenues by $89.3 million, or $9.75 per Bbl in 2005 compared to $41.6 million or $7.01 per Bbl in 2004. The 2005 amount includes $56.3 million of deferred losses related to 2005 swaps that were terminated in 2004. These losses were deferred in OCI until the production that was originally hedged was produced and delivered during the first half of 2005.

Gas revenues, excluding the effects of hedging, increased $11.1 million, to $108.3 million in 2005 from $97.2 million in 2004 due to increased production volumes ($5.5 million) and higher realized prices ($5.6 million). Our average realized price for gas was $6.10 per Mcf for 2005 compared to $5.76 per Mcf for 2004.

Hedging had no impact on our 2005 gas revenues and average price and decreased our 2004 gas revenues by $1.1 million and average price by $0.06 per Mcf.

Lease operating expenses.    Lease operating expenses (including steam gas costs and electricity) increased $48.7 million, to $117.1 million for 2005 from $68.4 million for 2004, primarily due to the properties acquired from Nuevo which accounted for $63.0 million of our operating expenses in 2005 compared to $20.0 million in 2004. On a per unit basis, lease operating expenses increased to $9.66 per BOE in 2005 versus $7.81 per BOE in 2004. The per unit increase is primarily attributable to the steam gas costs attributable to the properties acquired from Nuevo. Steam gas costs averaged $2.73 per BOE in 2005 versus $0.95 per BOE in 2004.

Production and ad valorem taxes.    Production and ad valorem taxes increased $4.7 million, to $13.3 million for 2005 from $8.6 million for 2004 primarily due to the properties acquired from Nuevo ($4.5 million in 2005 versus $1.1 million in 2004) and increased oil and gas prices.

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Gathering and transportation expenses.    Gathering and transportation expenses increased $2.9 million, to $5.9 million for 2005 from $3.0 million for 2004 primarily due to the properties acquired from Nuevo ($3.2 million in 2005 versus $0.8 million in 2004).

General and administrative expense.    Our G&A expense consists of (in thousands of dollars):

	Six Months Ended June 30,
	2005		2004
G&A excluding items below	$	23,238	$	15,510
Stock appreciation rights		25,877		13,426
Other stock-based compensation		6,755		4,378
	$	55,870	$	33,314

G&A expense, excluding amounts attributable to SARs and other stock based compensation, increased $7.7 million, to $23.2 million for 2005 from $15.5 million for 2004, primarily reflecting increased costs resulting from the Nuevo acquisition and to a lesser extent Sarbanes-Oxley compliance costs.

G&A expense related to SARs was $25.9 million in 2005 compared to $13.4 million in 2004. 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. Such expense in 2005 and 2004 reflects additional vesting of outstanding SARs as well as an increase in our stock price. Our stock price was $35.53 per share on June 30, 2005 versus $26.00 per share on December 31, 2004 and $18.35 per share on June 30, 2004 versus $15.39 per share on December 31, 2003. In 2005 and 2004 we made cash payments of $9.0 million and $9.9 million, respectively, for SARs that were exercised during the period.

G&A expense for 2005 and 2004 includes other stock based compensation costs of $6.8 million and $4.4 million, respectively, related to restricted stock and restricted stock unit grants.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $9.8 million and $6.8 million of G&A expense in 2005 and 2004, respectively.

Depreciation, depletion and amortization, or DD&A.    DD&A expense increased $43.5 million, to $89.3 million in 2005 from $45.8 million in 2004. Approximately $42.3 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 $7.14 per BOE in 2005 compared to $5.07 per BOE in 2004. The increase primarily reflects the effect of the Nuevo acquisition.

Accretion expense.    Accretion expense increased $1.1 million to $3.7 million in 2005 from $2.6 million in 2004. The increase is primarily attributable to the increase in asset retirement obligations related to the Nuevo acquisition.

Interest expense.    Interest expense increased $10.1 million, to $25.6 million for 2005 from $15.5 million for 2004 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 $1.4 million and $2.8 million of interest in 2005 and 2004, respectively.

Gain (loss) on mark-to-market derivative contracts.    We do not use hedge accounting for certain of our derivative instruments, because the derivatives do not qualify or we have elected not to use hedge

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accounting. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts 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.

As a result of the increase in oil prices, we recognized a $487.9 million loss related to mark-to-market derivative contracts in the first half of 2005. Cash payments related to these contracts that settled in the second quarter of 2005 totaled $87.8 million. In addition, we paid $145.4 million in connection with the elimination of our 2006 oil collars during this period. In the first half of 2004 we recognized a loss on mark-to-market derivative contracts of $1.2 million. Cash payments related to these contracts that settled in the first half of 2004 totaled $5.6 million.

Debt extinguishment costs.    In connection with the retirement of the debt assumed in the acquisition of Nuevo, in 2004 we recorded $19.7 million of debt extinguishment costs.

Income tax expense.    During interim periods income tax expense is generally based on the estimated effective income tax rate that is expected for the entire year. We currently estimate our 2005 annual effective tax rate to be a 35.3% benefit. Included in this benefit is (1) a cumulative charge of $5.7 million to income tax expense to reflect an increase in the estimated California apportionment factor as a result of the sale of the Company’s properties in East Texas and Oklahoma and the purchase of California properties, both in the second quarter of 2005, and (2) the $9.5 million effect of a permanent difference primarily resulting from the vesting in July 2005 of performance based restricted stock units that are not deductible because of IRS limitations on deductions for executive compensation.

Variances in our reported tax rate from the 35% federal statutory rate are caused by state income taxes, EOR credits and various other items. EOR credits are a credit against federal and state income taxes for certain costs related to extracting high-cost oil, utilizing certain prescribed “enhanced” (tertiary) recovery methods. During periods when PXP reports net income, the benefit from the EOR credits should generally reduce our effective tax rate below the statutory rates. During periods when PXP reports a net loss, the benefit from the EOR credits will generally increase our effective tax rate above the statutory rates. In the current period, PXP reported a net loss due to the mark-to-market derivative losses, and the EOR credits had the effect of increasing our tax benefit rate. The increase in the tax benefit rate attributable to the EOR credits was offset by the items discussed above, resulting in the estimated annual benefit rate of 35.3% for 2005. Our estimated effective tax rate was approximately 39% in 2004.

The payment to eliminate our 2006 oil price swaps and collars is tax deductible. As a result of this tax deduction, as well as our existing NOL and EOR credit carryforwards we do not expect to pay any significant federal or state income taxes in 2005.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At June 30, 2005 we had approximately $517 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, derivative obligations, 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. Hedging also prevents us from receiving the full advantage of increases in oil or gas prices above the maximum fixed amount specified in the hedge

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agreement. The level of hedging activity depends on our view of market conditions, available hedge prices and our operating strategy. In addition, the majority of our capital expenditures are discretionary and could be curtailed if our cash flows declined from expected levels.

As discussed in “Company Overview – Hedge Restructuring”, we eliminated all of our 2006 oil price swaps and collars at a cost of approximately $292.7 million which we paid with the proceeds from the property sale discussed in “– Acquisitions and Dispositions”. The payment to eliminate our 2006 oil price swaps and collars is tax deductible. As a result of this tax deduction, as well as our existing net operating loss (NOL) and enhanced oil recovery credit (EOR) carryforwards we do not expect to pay any significant federal or state income taxes in 2005.

At June 30, 2005 we had a working capital deficit of approximately $177 million. Approximately $139 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 difference between the fixed price in the contract and the actual NYMEX oil price. Cash received for the sale of physical production will be based on actual market prices and, if necessary, will be available to meet derivative settlement obligations. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date. The contract counterparties for our derivative commodity contracts are all major financial institutions. All seven of the financial institutions are participating lenders in our credit facility, with three such counterparties holding contracts that represent approximately 68% of the fair value of all of our open positions at June 30, 2005. In addition, approximately $33 million (net of related deferred income taxes) of the working capital deficit is attributable to the in-the-money value of stock appreciation rights that were deemed vested at June 30, 2005.

Financing Activities

Senior Revolving Credit Facility.    On May 16, 2005, we entered into an Amended and Restated Credit Agreement (the “Amended Credit Agreement”) which amended and restated our $500 million senior revolving credit facility. The Amended Credit Agreement increased the facility size to $750 million and established an initial borrowing base of $750 million. The borrowing base will be redetermined on a semi-annual basis, with PXP and the lenders each having the right to one annual interim unscheduled redetermination, and may be adjusted based on PXP’s oil and gas properties, reserves, other indebtedness and other relevant factors. Additionally, the Amended Credit Agreement contains a $75 million sub-limit for letters of credit. The Amended Credit Agreement matures on May 16, 2010. Collateral consists of 100% of the shares of stock of our domestic subsidiaries and mortgages covering at least 80% of the total present value of our domestic oil and gas properties.

The Amended Credit Agreement also modifies certain covenants to provide additional flexibility regarding the issuance of debt, the disposition of non oil and gas properties and mergers of subsidiaries. The Amended Credit Agreement also resets as of June 30, 2005 the financial covenant test with respect to tangible net worth. The effective interest rate on our borrowings under the Amended Credit Agreement was 4.2% at June 30, 2005. At that date we were in compliance with the covenants contained in the Amended Credit Agreement and could have borrowed the full amount available under the Amended Credit Agreement.

7.125% Senior Notes.    On June 30, 2005 we had $250.0 million principal amount of ten year senior unsecured notes (the “7.125% Notes”) outstanding. The 7.125% Notes were issued at 99.478% and

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bear interest at 7.125% with a yield to maturity of 7.2%. During the period from June 15, 2009 to June 14, 2012, we may redeem all or part of the 7.125% Notes at our option, at rates varying from 103.563% to 101.188% of the principal amount and at 100% of the principal amount thereafter. 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. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 7.125% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.

8.75% Senior Subordinated Notes.    At June 30, 2005, we had $275.0 million principal amount of 8.75% Senior Subordinated Notes due 2012 (the “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. During the period from July 1, 2007 to June 30, 2010 they are redeemable, at our option, at rates varying from 104.375% to 101.458% of the principal amount and at 100% of the principal amount thereafter. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 8.75% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.

Short-term Credit Facility.    In May 2005 we amended our uncommitted short-term credit facility to extend its term and increase the facility size. We may make borrowings from time to time until May 27, 2006, not to exceed at any time the maximum principal amount of $25.0 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 May 27, 2006. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and the Company. No amounts were outstanding under the short-term credit facility at June 30, 2005.

Shelf Registration.    We have filed with the Securities and Exchange Commission a universal shelf registration statement, which became effective May 2, 2005, that allows us to issue up to $500 million of debt and/or equity securities. The prices and terms of the debt and/or equity securities will be determined at the time of the sale.

Cash Flows

Net cash provided by operating activities was $113.5 million in 2005 compared to $118.9 million in 2004. The decrease from 2004 to 2005 primarily reflects the effect of the $147.3 million payment to eliminate all of our 2006 oil price swaps as discussed in “Company Overview – Hedge Restructuring”, partially offset by increased sales volumes as a result of the Nuevo acquisition and increased oil prices. Under SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, certain of our derivatives are deemed to contain a significant financing element and cash settlements with respect to such derivatives are required to be reflected as financing activities. Accordingly, in the first half of 2005 derivative cash settlements totaling $270.7 million, including the $145.4 million payment to eliminate all of our 2006 oil price collars, have been reclassified to financing activities.

Net cash provided by investing activities was $39.2 million in 2005 compared to net cash used in investing activities of $69.5 million in 2004. Sales proceeds of $341.0 million in 2005 were partially offset by outflows which included costs incurred in connection with our oil and gas acquisition, development and exploration activities of $180.8 million and costs associated with property acquisitions of $118.4 million. The 2004 outflows include costs incurred in connection with our oil and gas acquisition, development and exploration activities of $78.4 million and costs associated with the Nuevo acquisition of $13.7 million, reduced by property sales proceeds of $27.8 million.

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Net cash used in financing activities in 2005 was $153.3 million, primarily reflecting $116.5 million in net borrowings under our credit facility and the payment of $270.7 million in financing derivative settlements. Net cash used in financing activities in 2004 was $42.1 million. During the period borrowings under our credit facility increased $142.0 million and we received $248.6 million in proceeds from the issuance of our 7.125% Senior Notes. These proceeds and funds generated by our operations were used to retire $405.0 million in debt assumed in the Nuevo acquisition and to pay $7.8 million in debt financing costs and $19.8 million in derivative settlements.

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 have a capital budget for 2005, excluding acquisitions, of approximately $425 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, derivative obligations, debt service obligations, contingencies and anticipated capital expenditures. In addition, the majority of our capital expenditures are discretionary and could be curtailed if our cash flows declined from expected levels.

Stock Appreciation Rights and Restricted Stock Units

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 was $35.53 per share on June 30, 2005 versus $26.00 per share on December 31, 2004 and we recognized $25.9 million of expense in the first half of 2005. We incur cash expenditures upon the exercise of SARs, but our common shares outstanding do not increase. At June 30, 2005 we had approximately 2.7 million SARs outstanding of which 1.8 million were vested. If all of the vested SARs were exercised, based on $35.53, the price of our common stock as of June 30, 2005, we would pay $45.8 million to holders of the SARs. In the first half of 2005 we made cash payments of $9.0 million for SARs that were exercised during that period.

Our stock compensation plans also allow grants of restricted stock and restricted stock units. Restricted stock is issued on the grant date but restricted as to transferability. Restricted stock unit awards represent the right to receive common stock when vesting occurs. Compensation expense with respect to grants of restricted stock and restricted stock units is recognized as it vests for accounting purposes. We recognized $6.8 million of expense in the first half of 2005. At June 30, 2005 we had outstanding approximately 1.3 million restricted stock units with a provision for accelerated vesting if the closing price of our common stock was equal to or greater than $37.92 per share for any ten of twenty consecutive trading days. Such units vested on July 21, 2005 and as a result in the third quarter of 2005 we will recognize approximately $18.8 million of pre-tax non-cash stock-based compensation expense with respect to such units. After withholding the required amounts to pay federal withholding and related taxes, we issued approximately 0.8 million shares of common stock to the holders of the restricted stock units.

Industry Concentration

Financial instruments which potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments related to our hedging activities. During the first half of 2005 and 2004 sales to Plains All American Pipeline, L.P. accounted for approximately 40% and 52%, respectively, of our total revenues and during the first half of 2005 sales to ConocoPhillips accounted for approximately 44% of our total revenues. During such periods no other purchaser accounted for more than 10% of our total revenues. The loss of any single significant customer or contract could have a material adverse short-term effect, however, we do not believe that the loss of any single significant customer or contract would materially affect our business

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in the long-term. We believe such purchasers could be replaced by other purchasers under contracts with similar terms and conditions. However, their role as the purchaser of a significant portion of our oil production does have the potential to impact our overall exposure to credit risk, either positively or negatively, in that they may be affected by changes in economic, industry or other conditions.

The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better. All seven of the financial institutions are participating lenders in our credit facility, with three such counterparties holding contracts that represent approximately 68% of the fair value of all of our open positions at June 30, 2005.

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. Critical 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 for the year ended December 31, 2004.

Recent Accounting Pronouncements

In December 2004 the FASB issued SFAS No.123R (revised 2004), “Share-Based Payment” (“SFAS 123R”). that requires that the compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. SFAS 123R covers a wide range of share-based compensation arrangements including stock options, restricted stock plans, performance-based awards, stock appreciation rights, and employee stock purchase plans. SFAS 123R replaces FASB Statement No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” Public entities (other than those filing as small business issuers) were originally required to apply SFAS 123R as of the first interim or annual reporting period that begins after June 15, 2005. On April 14, 2005 the SEC announced the adoption of a new rule that amends the compliance dates for SFAS 123R. The Commission’s new rule allows registrants to implement SFAS 123R at the beginning of their next fiscal year, instead of the next reporting period, that begins after June 15, 2005. Accordingly, we will adopt SFAS 123R effective January 1, 2006. We are in the process of determining how the new method of valuing stock-based compensation as prescribed in SFAS 123R will be applied to valuing stock-based awards and the impact the recognition of compensation expense related to such awards will have on our financial statements.

In February 2005, the SEC issued guidance concerning the specific circumstance of a property disposition by a company that follows the full cost accounting method that resulted in a less than 25% alteration of the proved oil and gas reserve quantities within a full cost center. In connection with that disposition, the SEC considered if goodwill should be allocated to the property disposed, and, if so, whether that allocated goodwill should remain as a component of the capitalized full cost center or be reflected in the statement of operations.

The SEC concluded that only the fair value allocated to the oil and gas properties in a business acquisition should be included in the costs accounted for under Rule 4-10(c) of Regulation S-X. Goodwill associated with acquisitions of oil and gas properties that constitute a business is recognized in accordance with FASB Statement No. 141, “Business Combinations” but accounted for outside of the full cost rules. Therefore, when dispositions of these properties occur, the goodwill previously recognized does not affect the associated adjustments contemplated under Rule 4-10(c)(6)(i). Rather, the accounting for the goodwill and any potential impairment should follow the provisions of FASB Statement No. 142, Goodwill and Other Intangible Assets (SFAS 142). Companies are required to consider whether a property disposition that results in a less than 25% alteration of the proved oil and

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gas reserve quantities within a given cost center is a trigger that requires goodwill be evaluated for impairment under SFAS 142. We determined that an evaluation of goodwill for impairment under FAS 142 was not required as a result of the property dispositions in the second quarter of 2005. The SEC has not yet addressed whether any portion of goodwill should be allocated to a disposition of greater than 25%, but less than 100%, of the oil and gas reserves in a given cost center.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. We do not believe that our financial position, results of operations or cash flows will be impacted by this Interpretation.

In June 2005 the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (SFAS 154), which changes the requirements for the accounting for and reporting of a change in accounting principle by requiring voluntary changes in accounting principles to be reported using retrospective application, unless impracticable to do so. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Application is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Early adoption is permitted. We do not believe that our financial position, results of operations or cash flows will be impacted by SFAS 154.

Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking information regarding PXP that is intended to be covered by the safe harbor “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995. 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. Although we believe that our expectations are based on reasonable assumptions, there are risks, uncertainties and other factors that could cause actual results to be materially different from those in the 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;

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

• impact of oil and gas price fluctuations, including the impact on our earnings as a result of our derivative positions;

• 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;

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• 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 reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report and our other filings with the SEC. 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 for any obligation to disclose material information under the Federal 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, 2004 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 – Quantitative and Qualitative Disclosures About Market Risks

General

We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. 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, both realized and unrealized, are recognized currently in our income statement as gain (loss) on mark-to-market derivative contracts. If a derivative is designated as a cash flow hedge and qualifies for hedge accounting, any unrealized gain or loss is deferred in accumulated Other Comprehensive Income (“OCI”), a component of Stockholders’ Equity, until the hedged oil and gas production is sold. 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. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain in OCI until the related product has been delivered.

The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better. All seven of the financial institutions are participating lenders in our revolving credit facility, with three counterparties holding contracts that represent approximately 68% of the fair value of all open positions as of June 30, 2005.

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.

Elimination of 2006 Swap & Collar Positions

In March 2005 we executed a series of contracts that eliminated all of our 2006 oil price swaps and collars at a pre-tax cost of approximately $292.7 million. Approximately $145.4 million of this amount is

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attributable to 2006 collars for 22,000 barrels of oil per day with a floor price of $25.00 and an average ceiling price of $34.76. The collars were not accounted for as hedges, therefore, the $145.4 million loss in the fair value of these instruments was currently recognized in our income statement and there will be no income statement effect subsequent to March 31, 2005. Approximately $147.3 million of the cost is attributable to 2006 swaps for 15,000 barrels of oil per day at an average price of $25.28. We used hedge accounting for the swaps through March 2005 and as a result the $145.8 million loss in fair value attributable to the swaps has been deferred in OCI and will be recognized as a noncash reduction to oil revenues in 2006 when the hedged production is sold.

In May 2005 we completed the transactions to eliminate all of our 2006 oil price swaps and collars and paid the $292.7 million due under the contracts with proceeds received from the property sale discussed under “Acquisitions and Dispositions”. Under SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”, the collars were deemed to contain a significant financing element because they included off-market terms. Accordingly, the $145.4 million cash payment for the collars is reflected as a financing cash outflow in our statement of cash flows. The $147.3 million cash payment for the swaps is reflected as an operating cash outflow in our statement of cash flows. These payments reduced derivative liabilities on our balance sheet.

Acquisition of Floors for 2006 and 2007 Oil Production

In the first half of 2005 we acquired $45.00 NYMEX put options on 50,000 barrels of oil per day in 2006 and 20,000 barrels of oil per day in 2007. These put options cost an average of $2.95 per barrel for 2006 and $4.43 per barrel for 2007, which will be paid when the options are settled. We have elected not to use hedge accounting for the puts, consequently, the puts are marked-to-market with fair value gains and losses recognized as a gain or loss on mark-to-market derivative contracts on the income statement.

Derivative Instruments Designated as Cash Flow Hedges.

At June 30, 2005, 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
2005
July - December	Natural gas	Swap	5,000 /MMBtu	$4.40	Waha
Purchases of Natural Gas
2005
July - 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.

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Derivative Instruments Not Designated as Hedging Instruments.

At June 30, 2005, 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
2005
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
July - December	Crude oil	Collar	22,000 /Barrels	$25.00 Floor-$34.76 Ceiling	WTI
2006
January - December	Crude oil	Put options	50,000 /Barrels	$45.00	WTI
2007
January - December	Crude oil	Collar	22,000 /Barrels	$25.00 Floor-$34.76 Ceiling	WTI
January - December	Crude oil	Put options	20,000 /Barrels	$45.00	WTI
2008
January - December	Crude oil	Collar	22,000 /Barrels	$25.00 Floor-$34.76 Ceiling	WTI

The average price for the put options does not reflect the cost to purchase such options.

During the three and six months ended June 30, 2005 we recognized pre-tax losses of $113.9 million and $487.9 million, respectively, from derivatives that do not qualify for hedge accounting that settled during the period. During the three and six months ended June 30, 2005 we made cash payments of $50.9 million and $87.8 million on derivatives that do not qualify for hedge accounting that settled during the period. In addition, in the second quarter we made a $145.4 million payment to eliminate our 2006 oil price collars.

Physical Purchase Contracts.

Although not a derivative, at June 30, 2005 we also had 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
2005
July - December	Natural gas	Physical purchase	10,000 /MMBtu	$	4.19	Socal

Changes in Fair Value

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 increase are shown in the table below (in millions):

	June 30, 2005
	Fair Value			Effect of 10% Price Increase
Derivatives designated as cash flow hedges	$	2.8		$	0.4
Derivatives not designated as hedging instruments		(456.1	)		(136.0	)

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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% increase 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.

ITEM 4 – Controls and Procedures

Disclosure 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 Rules 13a-15(e) and 15d-15(e) to the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer believe that the disclosure controls and procedures as of June 30, 2005 were effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosure.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, our internal control over financial reporting can provide only reasonable assurance with respect to our financial reporting and financial statement preparation.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2005 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 4 – Submission of Matters to a Vote of Security Holders

The following items were presented for approval to stockholders of record on March 21, 2005 at the Company’s 2005 annual meeting of stockholders, held on May 5, 2005 in Houston, Texas:

		For	Against	Abstained or Withheld
(i)	Election of Directors
	James C. Flores	69,045,892	-	1,577,956
	Isaac Arnold, Jr.	69,938,201	-	685,647
	Alan R. Buckwalter, III	69,939,219	-	684,629
	Jerry L. Dees	69,138,517	-	1,485,331
	Tom H. Delimitros	69,137,464	-	1,486,384
	Robert L. Gerry III	69,922,380	-	701,468
	John H. Lollar	68,810,316	-	1,813,532
(ii)	Ratification of PricewaterhouseCoopers LLP, independent certified public accountants, as auditors of the Company’s financial statements for the fiscal year ended December 31, 2005	69,311,813	1,282,607	29,428

Of the 77,368,217 shares of common stock issued and outstanding on March 21, 2005, 70,623,848 were present, either in person or by proxy.

ITEM 5 – Other Information.

(a) Form 8-K, Item 1.01 Entry into a Material Definitive Agreement

Adoption of Long-Term Retention and Deferred Compensation Arrangement

The Compensation Committee of the Board of Directors of Plains Exploration & Production Company (the “Company”), with input from an independent compensation consulting firm, has approved a long-term retention and deferred compensation arrangement effective August 3, 2005. The plan provides for the deferral of awards of equity compensation received by Company executives for service to the Company and in lieu thereof, an equivalent number of restricted stock units will be credited to an account for the executive. The restricted stock units will vest in accordance with the terms of the equity compensation award, but payment upon vesting will be deferred until the earlier of (i) ten years from the date the deferral election is made, (ii) six months after the date of termination of employment with the Company following a termination without cause or for good reason (as defined in the executives’ employment agreements), (iii) death or disability, or (iv) the occurrence of an unforeseeable emergency (as defined in the Internal Revenue Code). Voluntary additional deferrals may also provide for payment on a date or dates chosen by the executive officer (subject to the provisions of 409A of the Code). Initially, each of the executive officers will be credited restricted stock units as described below.

Pursuant to the terms of this plan and the Company’s 2004 Stock Incentive Plan, the Company’s Chief Executive Officer, James C. Flores, will be credited 200,000 restricted stock units annually for ten years, with the first 200,000 units credited as of September 30, 2005. Each annual credit of restricted stock units is subject to continued service by Mr. Flores. The first five annual credits will each vest in full in five years from the date of such annual credit, and the sixth, seventh, eighth, ninth and tenth annual credits will each vest in full on September 30, 2015. Vesting of such restricted stock units may occur earlier in the event of a change in control (as defined in the 2004 Stock Incentive Plan) or

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termination of Mr. Flores without cause (as defined in his employment agreement). Payment upon vesting of the restricted stock units will be deferred until September 30, 2015 or as described above pursuant to the terms of the plan. The number of restricted stock units to be credited to Mr. Flores’ account annually will increase to 300,000 effective upon the date that the Company’s common stock closes at or above $75.84 per share on any ten out of twenty consecutive trading days.

In addition, pursuant to the terms of this plan and the Company’s 2004 Stock Incentive Plan, each of the Company’s Executive Vice Presidents, Stephen A. Thorington, Thomas M. Gladney and John F. Wombwell, will be credited 33,000 restricted stock units annually for three years, with the first 33,000 units credited as of August 3, 2005. Each annual credit of restricted stock units is subject to continued service by such executive. Each annual credit will vest in full in five years from the date of such annual credit. The number of restricted stock units to be credited to each executive’s account annually will increase to 50,000 effective upon the date that the Company’s common stock closes at or above $75.84 per share on any ten out of twenty consecutive trading days. If the executive is still employed by the Company one year following the third annual credit date, an additional credit of 33,000 restricted stock units (or 50,000 if stock price has reached $75.84 per share as described above) will be made in each of the following three years; if the executive is still employed with the Company one year following the sixth annual credit date, an additional credit of 33,000 restricted stock units (or 50,000 if stock price has reached $75.84 per share as described above) will be made in each of the following three years; and if the executive is still employed with the Company one year following the ninth annual credit date, an additional credit of 33,000 restricted stock units (or 50,000 if stock price has reached $75.84 per share as described above) will be made in the following year. The restricted stock units credited to the executive’s account on each of the fourth, fifth and sixth annual credit dates will vest in full in five years from the date of such annual credit. The seventh, eighth, ninth and tenth annual credits of restricted stock units will each vest in full on September 30, 2015. Payment upon vesting of the restricted stock units will be deferred until September 30, 2015 or as described above pursuant to the terms of the plan. Vesting of all credited restricted stock units and any annual credits not yet made, as well as payment with respect to such restricted stock units, may occur earlier in the event of termination of employment following a change of control (as defined in the 2004 Stock Incentive Plan) and Mr. Flores is not Chief Executive Officer of the Company and the executive does not report directly to Mr. Flores. Vesting of credited restricted stock units may also be accelerated upon termination without cause (as defined in the executive’s employment agreement).

The Long-Term Retention and Deferred Compensation arrangement, and the Long-Term Retention and Deferral Agreements entered into thereunder, are included with this report as Exhibits and are incorporated herein by reference in their entirety.

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ITEM 6 – Exhibits

4.1	*	Fourth Supplemental Indenture to Amended and Restated Indenture dated as of June 18, 2004, dated as of June 30, 2005, among Plains Exploration & Production Company, the Subsidiary Guarantor Parties thereto and J.P. Morgan Chase Bank, as Trustee
4.2	*	Second Supplemental Indenture to Indenture dated as of June 30, 2004, dated as of June 30, 2005, among Plains Exploration & Production Company, the Subsidiary Guarantor Parties thereto, and Wells Fargo Bank, N.A., as Trustee
10.1	*	Amended and Restated Credit Agreement dated as of May 16, 2005, among Plains Exploration & Production Company, as borrower, each of the lenders that is a signatory thereto, and J.P. Morgan Chase Bank as administrative agent.
10.2	*	Long-Term Retention and Deferred Compensation.
10.3	*	Long-Term Retention and Deferral Agreement for James C. Flores.
10.4	*	Long-Term Retention and Deferral Agreement for Executive Vice Presidents.
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

Items 1, 2 & 3 are not applicable and have been omitted.

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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: August 8, 2005	By:	/s/ Stephen A. Thorington
		Stephen A. Thorington
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

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