Plains Exploration & Production 10-Q 2006 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, 2006

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.    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  x Accelerated filer  ¨ Non-accelerated filer  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes   ¨    No  x

76.7 million shares of Common Stock, $0.01 par value, issued and outstanding at July 31, 2006.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION

ITEM 1. Unaudited Condensed Consolidated Financial Statements:

Condensed Consolidated Balance Sheets June 30, 2006 and December 31, 2005	1
Condensed Consolidated Statements of Income For the three months and six months ended June 30, 2006 and 2005	2
Condensed Consolidated Statements of Cash Flows For the three months and six months ended June 30, 2006 and 2005	3
Condensed Consolidated Statements of Comprehensive Income For the three months and six months ended June 30, 2006 and 2005	4
Condensed Consolidated Statement of Changes in Stockholders’ Equity For the six months ended June 30, 2006	5
Notes to Condensed Consolidated Financial Statements	6
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk	36
ITEM 4. Controls and Procedures	38
PART II. OTHER INFORMATION	39

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	June 30, 2006			December 31, 2005
ASSETS
Current Assets
Cash and cash equivalents	$	1,403		$	1,552
Accounts receivable		131,642			148,691
Inventories		13,669			10,325
Deferred income taxes		162,277			128,816
Other current assets		10,315			3,948
		319,306			293,332
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		2,845,684			2,604,892
Not subject to amortization		187,681			112,204
Other property and equipment		18,676			16,282
		3,052,041			2,733,378
Less allowance for depreciation, depletion and amortization		(597,120	)		(498,075	)
		2,454,921			2,235,303
Goodwill		173,790			173,858
Other Assets		41,169			39,449
	$	2,989,186		$	2,741,942
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	135,503		$	122,996
Commodity derivative contracts		266,418			85,596
Royalties payable		47,201			43,279
Stock appreciation rights		57,279			55,170
Interest payable		13,029			13,000
Other current liabilities		35,216			43,957
		554,646			363,998
Long-Term Debt
Revolving credit facility		231,000			272,000
8.75% Senior Subordinated Notes		276,439			276,538
7.125% Senior Notes		248,888			248,837
		756,327			797,375
Other Long-Term Liabilities
Asset retirement obligation		165,882			155,865
Commodity derivative contracts		507,506			440,543
Other		5,687			7,014
		679,075			603,422
Deferred Income Taxes		271,410			258,810
Commitments and Contingencies (Note 4)
Stockholders’ Equity
Common stock		791			784
Additional paid-in capital		973,535			940,988
Retained earnings (deficit)		(192,443	)		(133,664	)
Accumulated other comprehensive income		(44,574	)		(89,566	)
Treasury stock, at cost		(9,581	)		(205	)
		727,728			718,337
	$	2,989,186		$	2,741,942

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,
	2006			2005			2006			2005
Revenues
Oil sales	$	286,617		$	206,490		$	538,084		$	386,648
Oil hedging		(36,548	)		(43,818	)		(73,087	)		(89,263	)
Gas sales
Sales related to buy/sell contracts		—			8,328			—			16,084
Other		27,601			46,377			63,155			92,274
Gas hedging		—			(807	)		—			19
Other operating revenues		716			738			1,853			1,621
		278,386			217,308			530,005			407,383
Costs and Expenses
Production costs
Lease operating expenses		44,738			36,877			86,903			69,205
Steam gas costs
Costs related to buy/sell contracts		484			8,716			1,036			16,837
Other		12,360			7,688			24,584			16,248
Electricity		9,954			8,186			18,786			14,761
Production and ad valorem taxes		7,036			5,967			12,804			13,303
Gathering and transportation expenses		2,072			2,404			3,656			5,949
General and administrative		38,065			18,342			61,037			55,870
Depreciation, depletion and amortization		50,917			45,745			100,684			89,338
Accretion		2,476			1,934			4,942			3,679
		168,102			135,859			314,432			285,190
Income from Operations		110,284			81,449			215,573			122,193
Other Income (Expense)
Interest expense		(19,210	)		(14,158	)		(35,004	)		(25,561	)
Loss on mark-to-market derivative contracts		(142,914	)		(113,871	)		(312,242	)		(487,923	)
Gain on termination of merger agreement		37,902			—			37,902			—
Interest and other income (expense)		1,296			(120	)		1,620			172
Income (Loss) Before Income Taxes and Cumulative Effect of Accounting Change		(12,642	)		(46,700	)		(92,151	)		(391,119	)
Income tax (expense) benefit
Current		(45	)		(1,330	)		(8,757	)		(1,330	)
Deferred		5,560			700			44,311			139,501
Income (Loss) Before Cumulative Effect of Accounting Change		(7,127	)		(47,330	)		(56,597	)		(252,948	)
Cumulative effect of accounting change, net of tax benefit		—			—			(2,182	)		—
Net Income (Loss)	$	(7,127	)	$	(47,330	)	$	(58,779	)	$	(252,948	)
Earnings (loss) per share, basic and diluted
Income (loss) before cumulative effect of accounting change	$	(0.09	)	$	(0.61	)	$	(0.72	)	$	(3.27	)
Cumulative effect of accounting change		—			—			(0.03	)		—
Net income (loss)	$	(0.09	)	$	(0.61	)	$	(0.75	)	$	(3.27	)
Weighted Average Shares Outstanding, basic and diluted		78,694			77,329			78,567			77,266

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,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(58,779	)	$	(252,948	)
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		105,626			93,017
Deferred income taxes		(44,311	)		(139,501	)
Cumulative effect of adoption of accounting change		2,182			—
Commodity derivative contracts
Loss on derivatives		335,234			291,914
Reclassify derivative settlements		71,310			270,742
Noncash compensation		23,418			23,914
Other noncash items		(48	)		(46	)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		6,124			(8,066	)
Accounts payable and other liabilities		(13,778	)		(21,868	)
Commodity derivative contracts		(21,215	)		(143,690	)
Net cash provided by operating activities		405,763			113,468
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(289,425	)		(299,139	)
Proceeds from sales of oil and gas properties		—			340,969
Derivative settlements		(42,731	)		—
Other		(4,535	)		(2,596	)
Net cash provided by (used in) investing activities		(336,691	)		39,234
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		728,900			751,000
Repayments		(769,900	)		(634,500	)
Derivative settlements		(28,579	)		(270,742	)
Other		358			964
Net cash used in financing activities		(69,221	)		(153,278	)
Net decrease in cash and cash equivalents		(149	)		(576	)
Cash and cash equivalents, beginning of period		1,552			1,545
Cash and cash equivalents, end of period	$	1,403		$	969

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,
	2006			2005			2006			2005
Net Income (Loss)	$	(7,127	)	$	(47,330	)	$	(58,779	)	$	(252,948	)
Other Comprehensive Income (Loss)
Commodity hedging contracts
Change in fair value		—			2,332			—			(83,314	)
Reclassification adjustment for settled contracts		—			16,895			—			33,094
Reclassification adjustment for terminated contracts		36,548			27,252			73,087			56,338
Related income taxes		(14,267	)		(21,477	)		(28,095	)		(1,252	)
		22,281			25,002			44,992			4,866
Comprehensive Income (Loss)	$	15,154		$	(22,328	)	$	(13,787	)	$	(248,082	)

See notes to consolidated financial statements.

4

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)

				Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income
	Common Stock												Treasury Stock
	Shares	Amount											Shares		Amount			Total
Balance, December 31, 2005	78,416	$	784	$	940,988		$	(133,664	)	$	(89,566	)	(5	)	$	(205	)	$	718,337
Net loss	—		—		—			(58,779	)		—		—			—			(58,779	)
Other comprehensive income	—		—		—			—			44,992		—			—			44,992
Stock-based compensation awards
Issuance of stock	647		7		—			—			—		—			—			7
Deferred compensation	—		—		29,154			—			—		—			—			29,154
Treasury stock transactions	—				(205	)		—			—		(249	)		(9,376	)		(9,581	)
Exercise of stock options and other	24		—		3,598			—			—		—			—			3,598
Balance, June 30, 2006	79,087	$	791	$	973,535		$	(192,443	)	$	(44,574	)	(254	)	$	(9,581	)	$	727,728

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

The consolidated financial statements of Plains Exploration & Production Company (“PXP”, “us”, “our”, “we” or the “Company”) 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, 2006 and December 31, 2005, the results of our operations and our comprehensive income for the three months and six months ended June 30, 2006 and 2005 and our cash flows and the changes in our stockholders’ equity for the six months ended June 30, 2006. 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 financial statements to conform to the current year presentation. The results of our operations for the six months ended June 30, 2006 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, 2005.

Stone Energy Corporation. On April 24, 2006 we announced that we had entered into a definitive agreement to acquire Stone Energy Corporation (“Stone”) in a stock-for-stock transaction. On June 22, 2006 the agreement was terminated by Stone in order for Stone to enter into a merger agreement with another company. In connection with the termination of the merger agreement we received a termination fee of $43.5 million. Earnings for the three months and six months ended June 30, 2006 include a gain on the termination of the merger agreement of $37.9 million representing the termination fee net of certain merger related costs incurred by the Company.

Asset Retirement Obligations. The following table reflects the changes in our asset retirement obligation during the six months ended June 30, 2006 (in thousands):

Asset retirement obligation - beginning of period	$	160,955
Settlements		(584	)
Accretion expense		4,942
Asset retirement additions		5,377
Asset retirement obligation - end of period	$	170,690	(1)

(1) $4.8 million included in current liabilities.

Earnings Per Share. For the three months and six months ended June 30, 2006 and 2005 the weighted average shares outstanding for computing basic and diluted earnings per share (“EPS”) (in thousands):

	Three Months Ended June 30,		Six Months Ended June 30,
	2006	2005	2006	2005
Common shares outstanding - basic and diluted	78,694	77,329	78,567	77,266
Unvested restricted stock, restricted stock units and stock options not included in computing
EPS due to antidilutive effect	730	943	812	895

In computing earnings per share, no adjustments were made to reported net income.

6

Inventories. Oil inventories are carried at the lower of the cost to produce or market value and materials and supplies inventories are stated at the lower of cost or market with cost determined on an average cost method. Our inventories consist of (in thousands):

	June 30,		December 31,
	2006		2005
Oil	$	2,983	$	2,099
Materials and supplies		10,686		8,226
	$	13,669	$	10,325

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,
	2006		2005		2006		2005
G&A excluding stock-based compensation	$	16,812	$	11,511	$	32,038	$	23,238
Stock-based compensation		21,253		6,831		28,999		32,632
	$	38,065	$	18,342	$	61,037	$	55,870

Stockholders’ Equity. Our Board of Directors has authorized the repurchase of up to $500 million of our common stock. The shares will be repurchased from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. As of June 30, 2006, no purchases had been made under this program. In July 2006 we repurchased 2,461,900 common shares at a cost of $100.8 million.

The 254,000 shares of treasury stock at June 30, 2006 represent shares issued to a rabbi trust for the benefit of certain of the Company’s officers that retired or resigned in the first six months of 2006.

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; (6) stock-based compensation and (7) valuation of derivative instruments. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Stock Based Compensation. Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No.123R “Share-Based Payment” (“SFAS 123R”) that requires that the compensation cost relating to share-based payment transactions be recognized in financial statements. We used the “modified prospective approach” as allowed under SFAS 123R. See Note 3.

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 and used in thermal recovery operations. Effective January 1, 2006 we adopted Emerging Issues Task Force Issue No. 04-13 (“EITF 04-13”), “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF 04-13 requires that two or more inventory transactions with the same counterparty be viewed as a single nonmonetary transaction if the transactions were entered into in contemplation of one another (as determined in accordance with EITF 04-13). We have determined that transactions under certain of our buy/sell contracts should be presented net in accordance EITF 04-13. Accordingly, certain costs previously recorded gross in revenues and operating costs in prior periods will be recorded net in 2006 and subsequent periods.

7

Recent Accounting Pronouncements. In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments” (“SFAS 155”), which eliminates the exemption from applying SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. SFAS 155 also allows the election of fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement event. Adoption is effective for all financial instruments acquired or issued after the beginning of the first fiscal year that begins after September 15, 2006. Early adoption is permitted. The adoption of SFAS 155 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.

In March 2006, the FASB issued SFAS No. 156 – “Accounting for Servicing of Financial Assets” (“SFAS 156”), which requires all separately recognized servicing assets and servicing liabilities be initially measured at fair value. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities at fair value. Adoption is required as of the beginning of the first fiscal year that begins after September 15, 2006. Early adoption is permitted. The adoption of SFAS 156 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.

In June 2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement No. 109)” which is effective for fiscal years beginning after December 15, 2006 with earlier adoption encouraged. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We are currently evaluating the potential impact of this interpretation

Note 2—Derivative Instruments and Hedging Activities

We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production and the purchase of natural gas used in our thermal recovery operations. 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 a gain or (loss) on mark-to-market derivative contracts. Cash flows are only impacted to the extent the actual settlements under the contracts result in making a payment to 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.

At December 31, 2005 we had collars on 22,000 barrels of oil per day for all of 2007 and 2008 with a floor price of $25.00 and an average ceiling price of $34.76. In April 2006, we executed a series of offsetting contracts to eliminate all of these crude oil price collars at a pre-tax cost of approximately $593 million. This amount represents the fair value of the collars on the date we entered into the offsetting positions. Since the collars were not designated as a hedge such amount has been recognized in our income statement as a loss on mark-to-market derivative contracts ($170 million in 2006 and $423 million in prior periods).

We may settle these contracts as they mature (i.e., on a monthly basis throughout 2007 and 2008) or, at our option, we may pay the amounts due at an earlier date. If the contracts are settled as they mature, our total cost would be approximately $644 million and the $51 million in excess of the fair value on the date we entered into the offsetting positions would be recognized in our income statement as interest expense.

8

At June 30, 2006 we also had the following open commodity derivative positions, none of which were designated as hedging instruments:

Period	Instrument Type	Daily Volumes	Average Price	Index
Sales of Crude Oil Production
2006
Jul - Dec	Put options	50,000 Bbls	$55.00 Strike price	WTI
2007
Jan - Dec	Put options	50,000 Bbls	$55.00 Strike price	WTI
2008
Jan - Dec	Put options	42,000 Bbls	$55.00 Strike price	WTI
Purchases of Natural Gas
2006
Jul - Dec	Call options	30,000 MMBtu	$12.00 Strike price	Socal

The average strike prices for the put options and call options do not reflect the cost to purchase such options. The crude oil put options cost an average of $4.91 per barrel for 2006, $5.57 per barrel for 2007 and $3.35 per barrel for 2008. The natural gas call options cost an average of $1.04 per MMBtu. The premiums for the put and call options will be paid when the options are settled.

During the three months ended June 30, 2006 and 2005 we recognized pre-tax losses of $142.9 million and $113.9 million, respectively, from derivatives that do not qualify or were not designated for hedge accounting. During such periods we made cash payments of $25.2 million and $196.2 million, respectively, on derivatives that do not qualify for hedge accounting that settled during the periods.

During the six months ended June 30, 2006 and 2005 we recognized pre-tax losses of $312.2 million and $487.9 million, respectively, from derivatives that do not qualify or were not designated for hedge accounting. During such periods we made cash payments of $50.1 million and $233.2 million, respectively, on derivatives that do not qualify for hedge accounting that settled during the periods.

Cash payments made during the three months and six months ended June 30, 2005 include the $145.4 million we paid to eliminate our 2006 oil price collars.

Under SFAS No. 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 in the Statement of Cash Flows. Cash settlements with respect to derivatives that are qualified for hedge accounting and do not have a significant financing element are reflected as operating activities in the Statement of Cash Flows. Cash settlements with respect to derivatives that are not qualified for hedge accounting and do not have a significant financing element are reflected as investing activities in the Statement of Cash Flows.

Other Comprehensive Income

During the three months and six months ended June 30, 2006 net deferred losses of $36.5 million and $73.1 million, respectively, attributable to cancelled 2006 swaps were reclassified from OCI and charged to oil and gas revenues. 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 during the six months ended June 30, 2005 we recognized $0.1 million for ineffectiveness of derivatives that qualify for hedge accounting.

At June 30, 2006 and December 31, 2005 OCI consisted of $72.7 million ($44.6 million, net of tax) and $145.8 million ($89.6 million, net of tax), respectively, of deferred losses attributable to cancelled 2006 swaps that are being reclassified to oil revenues in 2006.

9

Note 3—Stock Based Compensation

Prior to January 1, 2006, we accounted for stock based compensation using the intrinsic value method pursuant to Accounting Principles Bulletin No. 25 “Accounting for Stock Issued to Employees” (“APB 25”). No adjustments to our net income or earnings per share would have been required under SFAS No. 123 “Accounting for Stock Based Compensation” (“SFAS 123”). Effective January 1, 2006, we adopted the provisions of SFAS 123R. Under the provisions of SFAS 123R, stock-based compensation is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite employee service period (generally the vesting period of the grant). We adopted SFAS 123R using the modified prospective application method, under which compensation cost is recognized in the financial statements beginning with the adoption date for all share-based payments granted after that date, and for all unvested awards granted prior to the adoption of SFAS 123R. The cumulative adjustment at January 1, 2006 associated with the adoption of SFAS 123R resulted in a $2.2 million charge to earnings (net of a $1.4 million tax benefit). Our paid-in capital was increased by $3.6 million and our deferred tax liability was decreased by $1.4 million.

We have two stock incentive plans, the 2002 Stock Incentive Plan (the “2002 Plan”), which provides for a maximum of 1.5 million shares available for awards, and the 2004 Stock Incentive Plan (the “2004 Plan”), which provides for a maximum of 5.0 million shares available for awards. The 2002 Plan and the 2004 Plan provide for the grant of stock options, and other awards (including performance units, performance shares, share awards, restricted stock, restricted stock units, and stock appreciation rights, or SARs) to our directors, officers, employees, consultants and advisors. Our compensation committee may grant options and SARs on such terms, including vesting and payment forms, as it deems appropriate in its discretion, however, no option or SARs may be exercised more than 10 years after its grant, and the purchase price for incentive stock options and non-qualified stock options may not be less than 100% of the fair market value of our common stock on the date of grant. The compensation committee may grant restricted stock awards, restricted stock units, share awards, performance units and performance shares on such terms and conditions as it may in its discretion decide.

For the six months ended June 30, 2006 $29.0 million of stock-based compensation expense was charged to earnings ($17.5 million after a tax benefit of $11.5 million). In addition, during such period $2.7 million of stock-based compensation expense was capitalized. Additionally, there was $148.5 million of total unrecognized compensation cost related to unvested share-based compensation arrangements that is expected to be recognized over a weighted-average period of approximately six years. The tax benefit realized as a result of the vesting of restricted stock and restricted stock unit awards during the six months ended June 30, 2006 was $3.2 million. Stock based compensation expense for the six months ended June 30, 2006 includes $9.4 million resulting from the accelerated vesting of 0.4 million restricted stock units held by certain former officers that resigned their positions during the period.

Estimates of fair value are not intended to predict actual future events of the value ultimately realized by employees who receive share-based awards, and subsequent events are not indicative of the reasonableness of original estimates of fair value made by the Company under SFAS 123R.

Stock Appreciation Rights

SARs grants generally vest ratably over three years and expire within five years after the date of grant. These awards are similar to stock options, but are settled in cash rather than in shares of common stock and are classified as liability awards. Under the provisions of SFAS 123R, compensation cost for these awards is determined using a fair-value method and remeasured at each reporting date until the date of settlement. Stock-based compensation expense recognized in the six months ended June 30, 2006 is based on SARs ultimately expected to vest and has been reduced for estimated forfeitures.

10

The following table summarizes the status of our SARs at June 30, 2006 and the changes during the six months then ended:

	Outstanding (thousands)		Weighted Average Exercise Price		Aggregate Intrinsic Value ($ thousands)		Weighted Average Remaining Contractural Life (Years)
Outstanding at January 1, 2006	2,615		$	16.82
Granted	296			40.61
Exercised	(197	)		10.68
Cancelled	(39	)		31.11
Outstanding at June 30, 2006	2,675			19.70	$	55,740	3.7
Exercisable at June 30, 2006	1,710			11.07	$	50,375	3.6

The total intrinsic value of SARs exercised in the six months ended June 30, 2006 was $5.6 million and the fair value as of June 30, 2006 for SARs granted in the six months then ended was $10.40 per share.

We estimate the fair value of SARs granted using the Black-Scholes valuation model and the fair value of the SARs are remeasured at the end of the period. The following assumptions are as of June 30, 2006:

Expected life (in years)	1 - 4
Volatility	27.9% - 39.5%
Risk-free interest rate	5.1% - 5.2%
Dividend yield	0%

Expected volatility is based on the historical volatility of our common stock and other factors. We use historical experience with exercise and post-vesting exercise behavior to determine the SARs expected life. The expected life represents the period of time that SARs granted are expected to be outstanding. The risk-free rate is based on the U.S. Treasury rate with a maturity date corresponding to the SARs’ expected life.

Service Based Restricted Stock and Restricted Stock Units

Our stock compensation plans allow grants of restricted stock and restricted stock units. Restricted stock is issued on the grant date but is restricted as to transferability. Restricted stock unit awards represent the right to receive common stock when vesting occurs.

Restricted stock and restricted stock unit grants generally vest ratably over three years of service. Compensation cost for these awards is based on the closing market price of our common stock on the date preceding the date of grant. Stock-based compensation expense is based on the awards ultimately expected to vest, and has been reduced for estimated forfeitures.

The following table summarizes the status of our restricted stock and restricted stock units at June 30, 2006 and the changes during the six months then ended:

	Outstanding (thousands)		Weighted Average Fair Value		Aggregate Intrinsic Value ($ thousands)		Weighted Average Remaining Contractural Life (Years)
Outstanding at January 1, 2006	1,100		$	25.87
Granted	1,286			40.46
Vested	(723	)		27.35
Cancelled	(90	)		38.49
Outstanding at June 30, 2006	1,573			36.45	$	63,758	2.5

11

Executives’ Long-Term Retention and Deferred Compensation Plan

Under the terms of this plan certain executives have been granted the right to receive annual restricted stock grants beginning in 2005. Under the provisions of SFAS 123R all such future grants are deemed granted for the purpose of determining stock-based compensation expense. At January 1, 2006 these restricted stock units were classified as equity instruments (as defined in SFAS 123R) and the valuation under SFAS 123R was unchanged from the intrinsic valuation under APB 25.

The following table summarizes the status of these restricted stock units at June 30, 2006 and the changes during the six months then ended:

	Equity Instruments (thousands)		Weighted Average Fair Value		Aggregate Intrinsic Value ($ thousands)		Weighted Average Remaining Contractural Life (Years)
Outstanding at January 1, 2006	2,990		$	40.40
Reclassified to liability instruments	(111	)		40.40
Vested	(99	)		40.40
Cancelled	(561	)		40.40
Reclassified from liability instruments	111			40.54
Outstanding at June 30, 2006	2,330			40.40	$	94,458	7.76

In addition, the annual grants may be increased if certain common stock price based performance targets are achieved. We have used a Monte-Carlo simulation model to estimate the number of restricted stock units expected to be granted in the future. This model involves forecasting potential future stock price paths based on the expected return on the common stock and its volatility, then calculating the number of restricted stock units to be granted based on the results of the simulations.

The following assumptions were used at June 30, 2006 with respect to the Monte Carlo simulation model:

Expected annual return	10.90	%
Expected daily return	0.04	%
Daily standard deviation	2.19	%

During 2006 certain of these restricted stock units were reclassified as liability instruments (as defined in SFAS 123R) and revalued under the fair value approach in accordance with the provisions of SFAS 123R instead of the previously applied intrinsic valuation method prescribed by APB 25.

12

The following tables summarize the status of these restricted stock units at June 30, 2006 and the changes during the six months then ended:

	Equity Instruments (thousands)		Weighted Average Fair Value		Aggregate Intrinsic Value ($ thousands)		Weighted Average Remaining Contractual Life (Years)
Outstanding at January 1, 2006	496		$	38.52
Cancelled	(56	)		38.52
Change in Estimate	(28	)		38.52
Reclassified to liability instruments	(412	)		38.52
Reclassified from liability instruments	95			39.53
Outstanding at June 30, 2006	95			39.53	$	3,853	5.06
	Liability Instruments (thousands)		Weighted Average Fair Value		Aggregate Intrinsic Value ($ thousands)		Weighted Average Remaining Contractual Life (Years)
Outstanding at January 1, 2006	—		$	—
Reclassified from equity instruments	412			37.64
Cancelled	(52	)		37.64
Change in Estimate	18			39.53
Reclassified to equity instruments	(95	)		39.53
Outstanding at June 30, 2006	283			39.53	$	11,468	8.66

Stock Options

As a result of the acquisition of Nuevo Energy Company (“Nuevo”) in 2004, we converted certain of Nuevo’s outstanding stock options to options on our common stock. At June 30, 2006 there were 133,153 options outstanding with an average exercise price of $15.51 per share and an average remaining life of 2.9 years.

Note 4—Commitments and Contingencies

Operating leases. In March 2006 we entered into an operating lease with respect to an aircraft under the terms of which we will be required to make lease payments as follows: 2006—$2.3 million, 2007 through 2010—$6.1 million, and thereafter—$16.0 million.

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. We also maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not fully insured against all environmental risks. 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.

13

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. We cannot assure you 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. The present value of such abandonment costs, $39 million ($79 million undiscounted), 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, $0.5 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, releases of 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, 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 Energy Company’s Congo operations. Upon our acquisition of Nuevo Energy Company (“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, 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 closing agreements with the IRS confirming that neither our merger with Nuevo, nor the sale of our interest in the Congolese properties to Perenco will trigger recapture. At December 31, 2005 the estimated remaining contingent liabilities were $15.2 million relative to Nuevo’s former interest, and $21.4 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.

On November 15, 2005, the United States Court of Federal Claims issued a ruling granting the plaintiffs’ motion for summary judgment as to liability and partial summary judgment as to damages in the breach of contract lawsuitAmber Resources Company et al. v. United States, Case No. 02-30c. The Court’s ruling also denied the United States’ motion to dismiss and motion for summary judgment. The United States Court of Federal Claims ruled that the federal government’s imposition of new and onerous requirements that stood as a significant obstacle to oil and gas development breached agreements that it made when it sold 36 federal leases offshore California. The Court further ruled that the Government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. The final ruling in the case will not be made until the Court addresses the plaintiffs’

14

additional claims regarding the hundreds of millions of dollars that have been spent in the successful efforts to find oil and gas in the disputed lease area, and other matters. The final ruling, including the rulings made on November 15, 2005 will be subject to appeal, and no payments will be made until all appeals have either been waived or exhausted. We are among the current lessees of the 36 leases. Our share of the $1.1 billion award is in excess of $80 million.

We are a defendant in various other 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 5—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 domestic wholly owned unrestricted subsidiaries (referred to as “Guarantor Subsidiaries”).

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

• PXP (the “Issuer” or “Parent”);

• the Guarantor Subsidiaries on a combined basis;

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

• PXP on a consolidated basis.

15

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

JUNE 30, 2006

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1,401		$	2		$	—		$	1,403
Accounts receivable and other current assets		288,312			29,591			—			317,903
		289,713			29,593			—			319,306
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		2,318,367			527,317			—			2,845,684
Not subject to amortization		128,155			59,526			—			187,681
Other property and equipment		17,314			1,362			—			18,676
		2,463,836			588,205			—			3,052,041
Less allowance for depreciation, depletion and amortization		(336,128	)		(260,992	)		—			(597,120	)
		2,127,708			327,213			—			2,454,921
Investment in and Advances to Subsidiaries		476,736			—			(476,736	)		—
Other Assets		47,692			167,267			—			214,959
	$	2,941,849		$	524,073		$	(476,736	)	$	2,989,186
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	240,739		$	47,489		$	—		$	288,228
Commodity derivative contracts		266,418			—			—			266,418
		507,157			47,489			—			554,646
Long-Term Debt		756,327			—			—			756,327
Other Long-Term Liabilities		646,917			32,158			—			679,075
Payable to Parent		—			106,182			(106,182	)		—
Deferred Income Taxes		303,720			(32,310	)		—			271,410
Stockholders’ Equity
Stockholders’ equity		772,302			385,868			(385,868	)		772,302
Accumulated other comprehensive income		(44,574	)		(15,314	)		15,314			(44,574	)
		727,728			370,554			(370,554	)		727,728
	$	2,941,849		$	524,073		$	(476,736	)	$	2,989,186

16

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

DECEMBER 31, 2005

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1,548		$	4		$	—		$	1,552
Accounts receivable and other current assets		247,721			44,059			—			291,780
		249,269			44,063			—			293,332
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		2,126,960			477,932			—			2,604,892
Not subject to amortization		73,987			38,217			—			112,204
Other property and equipment		15,375			907			—			16,282
		2,216,322			517,056			—			2,733,378
Less allowance for depreciation, depletion and amortization		(305,510	)		(192,565	)		—			(498,075	)
		1,910,812			324,491			—			2,235,303
Investment in and Advances to Subsidiaries		458,984			—			(458,984	)		—
Other Assets		50,412			162,895			—			213,307
	$	2,669,477		$	531,449		$	(458,984	)	$	2,741,942
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	199,508		$	78,894		$	—		$	278,402
Commodity derivative contracts		85,596			—			—			85,596
		285,104			78,894			—			363,998
Long-Term Debt		797,375			—			—			797,375
Other Long-Term Liabilities		573,848			29,574			—			603,422
Payable to Parent		—			103,526			(103,526	)		—
Deferred Income Taxes		294,813			(36,003	)		—			258,810
Stockholders’ Equity
Stockholders’ equity		807,903			386,229			(386,229	)		807,903
Accumulated other comprehensive income		(89,566	)		(30,771	)		30,771			(89,566	)
		718,337			355,458			(355,458	)		718,337
	$	2,669,477		$	531,449		$	(458,984	)	$	2,741,942

17

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2006

(in thousands)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	215,827		$	34,242		$	—	$	250,069
Gas sales		5,968			21,633			—		27,601
Other operating revenues		557			159			—		716
		222,352			56,034			—		278,386
Costs and Expenses
Production costs		53,811			22,833			—		76,644
General and administrative		36,571			1,494			—		38,065
Depreciation, depletion and amortization and accretion		20,212			33,181			—		53,393
		110,594			57,508			—		168,102
Income from Operations		111,758			(1,474	)		—		110,284
Other Income (Expense)
Equity in earnings of subsidiaries		(1,769	)		—			1,769		—
Interest expense		(16,538	)		(2,672	)		—		(19,210	)
Loss on mark-to-market derivative contracts		(142,914	)		—			—		(142,914	)
Interest and other income		39,198			—			—		39,198
Income (Loss) Before Income Taxes and Cumulative Effect of Accounting Change		(10,265	)		(4,146	)		1,769		(12,642	)
Income tax benefit (expense)
Current		(13,462	)		13,417			—		(45	)
Deferred		16,600			(11,040	)		—		5,560
Net Income (Loss) Before Cumulative Effect of Accounting Change		(7,127	)		(1,769	)		1,769		(7,127	)
Cumulative effect of accounting change, net of tax benefit		—			—			—		—
Net Income (Loss)	$	(7,127	)	$	(1,769	)	$	1,769	$	(7,127	)

18

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	)
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	)

19

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2006

(in thousands)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	399,982		$	65,015		$	—	$	464,997
Gas sales		11,309			51,846			—		63,155
Other operating revenues		1,138			715			—		1,853
		412,429			117,576			—		530,005
Costs and Expenses
Production costs		105,711			42,058			—		147,769
General and administrative		59,174			1,863			—		61,037
Depreciation, depletion and amortization and accretion		36,278			69,348			—		105,626
		201,163			113,269			—		314,432
Income from Operations		211,266			4,307			—		215,573
Other Income (Expense)
Equity in earnings of subsidiaries		(361	)		—			361		—
Interest expense		(29,528	)		(5,476	)		—		(35,004	)
Loss on mark-to-market derivative contracts		(312,242	)		—			—		(312,242	)
Interest and other income		39,522			—			—		39,522
Income (Loss) Before Income Taxes and Cumulative Effect of Accounting Change		(91,343	)		(1,169	)		361		(92,151	)
Income tax benefit (expense)
Current		(3,607	)		(5,150	)		—		(8,757	)
Deferred		38,353			5,958			—		44,311
Net Income (Loss) Before Cumulative Effect of Accounting Change		(56,597	)		(361	)		361		(56,597	)
Cumulative effect of accounting change, net of tax benefit		(2,182	)		—			—		(2,182	)
Net Income (Loss)	$	(58,779	)	$	(361	)	$	361	$	(58,779	)

20

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	)
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	)

21

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2006

(in thousands of dollars)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(58,779	)	$	(361	)	$	361		$	(58,779	)
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		36,278			69,348			—			105,626
Equity in earnings of subsidiaries		361			—			(361	)		—
Deferred income taxes		(38,353	)		(5,958	)		—			(44,311	)
Cumulative effect of adpotion of accounting change		2,182			—			—			2,182
Commodity derivative contracts
Loss on derivatives		310,125			25,109			—			335,234
Reclassify derivative settlements		71,310			—			—			71,310
Noncash compensation		23,418			—			—			23,418
Other noncash items		(48	)		—			—			(48	)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(4,061	)		10,185			—			6,124
Accounts payable and other liabilities		(17,109	)		3,331			—			(13,778	)
Commodity derivative contracts		(21,215	)		—			—			(21,215	)
Net cash provided by operating activities		304,109			101,654			—			405,763
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(185,569	)		(103,856	)		—			(289,425	)
Derivative settlements		(42,731	)		—			—			(42,731	)
Other		(4,080	)		(455	)		—			(4,535	)
Net cash used in investing activities		(232,380	)		(104,311	)		—			(336,691	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		728,900			—			—			728,900
Repayments		(769,900	)		—			—			(769,900	)
Derivative settlements		(28,579	)		—			—			(28,579	)
Investment in and advances to affiliates		(2,655	)		2,655			—			—
Other		358			—			—			358
Net cash provided by (used in) financing activities		(71,876	)		2,655			—			(69,221	)
Net decrease in cash and cash equivalents		(147	)		(2	)		—			(149	)
Cash and cash equivalents, beginning of period		1,548			4			—			1,552
Cash and cash equivalents, end of period	$	1,401		$	2		$	—		$	1,403

22

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 on derivatives		265,215			26,699			—			291,914
Reclassify derivative settlements		268,634			2,108			—			270,742
Noncash compensation		23,914			—			—			23,914
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		(20,322	)		(1,546	)		—			(21,868	)
Commodity derivative contracts		(143,690	)		—			—			(143,690	)
Net cash provided by operating activities		10,844			102,624			—			113,468
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(121,489	)		(177,650	)		—			(299,139	)
Proceeds from sales of oil and gas properties		6,500			334,469			—			340,969
Other		(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	)
Derivative settlements		(268,634	)		(2,108	)		—			(270,742	)
Investment in and advances to affiliates		257,892			(257,892	)		—			—
Other		964			—			—			964
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

23

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 Form 10-K for the year ended December 31, 2005.

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 six 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 senior revolving credit facility. At June 30, 2006 we had approximately $500 million of availability under our revolving credit facility. We have a capital budget for 2006, excluding acquisitions, of $496 million. We believe that we have sufficient liquidity through our cash from operations and borrowing capacity under our senior revolving credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies, anticipated capital expenditures and expenditures under our stock repurchase program. In addition, the majority of our capital expenditures and expenditures under our stock repurchase program 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 use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil or gas prices above the maximum fixed amount specified in the derivative agreement. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy (see “– Derivative Instruments and Hedging”).

Stone Energy Corporation

On April 24, 2006 we announced that we had entered into a definitive agreement to acquire Stone Energy Corporation (“Stone”) in a stock-for-stock transaction. On June 22, 2006 the agreement was terminated by Stone in order for Stone to enter into a merger agreement with another company. In connection with the termination of the merger agreement we received a termination fee of $43.5 million. Earnings for the three months and six months ended June 30, 2006 include a gain on the termination of the merger agreement of $37.9 million representing the termination fee net of certain merger related costs incurred by the Company.

Property Divestitures

On June 28, 2006 we announced our intention to divest certain non-strategic oil and gas properties located primarily in California and Texas. High commodity prices and an active asset market prompted us to initiate the divestiture plan. We believe the current environment provides a unique opportunity to capture asset value currently unrecognized by the equity markets. We intend to use the sales proceeds to ensure financial flexibility by reducing debt and to deliver near-term value to shareholders by repurchasing shares of our common stock.

The properties included in the divestiture plan currently produce approximately 8,000 barrels of oil equivalent per day. Certain properties to be offered include Buena Vista and Mt. Poso Fields in the San Joaquin Valley, Sansinena Field in the Los Angeles Basin and Pakenham Field in West Texas. The sales will be conducted in a combination of negotiated and auction transactions and are expected to close during the fourth quarter of 2006.

24

Derivative Instruments and Hedging

For 2006, our crude oil derivative position consists exclusively of purchased put option contracts with a strike price of $55.00 on 50,000 barrels per day. The only cash settlements we are required to make on these contracts are option premiums, which are expected to total approximately $7.5 million per month. In return, to the extent the daily average NYMEX price for West Texas Intermediate crude oil is less than $55.00, we will receive the difference between $55.00 and the daily average NYMEX price for West Texas Intermediate crude oil.

In addition to our 2006 crude oil put options, we also have purchased put option contracts with a strike price of $55.00 on 50,000 barrels per day in 2007 and 42,000 barrels per day in 2008. We also have 2006 call options on 30,000 MMBtu per day of natural gas.

At December 31, 2005 we had collars on 22,000 barrels of oil per day for all of 2007 and 2008 with a floor price of $25.00 and an average ceiling price of $34.76. In April 2006, we executed a series of offsetting contracts to eliminate all of these crude oil price collars at a pre-tax cost of approximately $593 million. This amount represents the fair value of the collars on the date we entered into the offsetting positions. Since the collars were not designated as a hedge, such amount has been recognized in our income statement as a loss on mark-to-market derivative contracts ($170 million in 2006 and $423 million in prior periods).

We may settle these contracts as they mature (i.e., on a monthly basis throughout 2007 and 2008) or, at our option, we may pay the amounts due at an earlier date. If the contracts are settled as they mature, our total cost would be approximately $644 million and the $51 million in excess of the fair value on the date we entered into the offsetting positions would be recognized in our income statement as interest expense.

Since our remaining derivative position consists entirely of crude oil put options and natural gas call options, we expect a decrease in the volatility in derivative gains or losses on our income statement in subsequent periods.

See Item 3. Quantitative and Qualitative Disclosures About Market Risks for a discussion of our current derivative positions.

General

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Our revenues are derived from the sale of oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SEC’s full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter to determine a ceiling value of our properties. The rules require a write-down if our capitalized costs exceed the allowed “ceiling.” We have had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will fluctuate in the near term. If oil and gas prices decline significantly in the future, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities. Decreases in oil and gas prices have had, and will likely have in the future, an adverse effect on the carrying value of our estimated proved reserves, our reserve volumes 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.

25

Results Overview

In the first half of 2006, primarily as a result of a $312.2 million derivative mark-to-market loss, we reported a net loss of $58.8 million, or $0.75 per share. Cash payments related to mark-to-market derivative contracts totaled $50.1 million in the first half of 2006. Our net loss in 2006 includes a non-cash, after-tax expense related to the adoption of SFAS 123R of $2.2 million, or $0.03 per share.

Our earnings are subject to volatility due to: (i) gains and losses on derivative contracts subject to mark-to-market accounting as changes occur in the NYMEX price indexes; (ii) SARs, which are subject to variable accounting based on changes in fair value; and (iii) beginning in 2006 as a result of the adoption of SFAS 123R certain of our restricted stock units became subject to variable accounting based on changes in fair value. The fair value of SARs and restricted stock units is related to the market price of our common stock and will fluctuate with movements in our stock price.

In the first half of 2005, 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. Cash payments related to mark-to-market derivative contracts totaled $233.2 million in the first half of 2005.

26

Results of Operations

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Daily Average Volumes
Oil and liquids sales (Bbls)		52,990		52,088		52,699		50,593
Gas (Mcf)
Production		64,384		93,417		64,553		98,219
Used in steam operations		12,390		14,911		13,721		15,147
Sales (1)		51,994		78,506		50,832		83,072
BOE
Production		63,721		67,658		63,457		66,963
Sales (1)		61,656		65,172		61,171		64,437
Unit Economics (in dollars) (2)
Average NYMEX Prices
Oil	$	70.72	$	53.13	$	67.12	$	51.53
Gas		6.76		6.73		7.85		6.50
Average Realized Sales Price Before
Derivative Transactions
Oil (per Bbl)	$	59.44	$	43.56	$	56.41	$	42.22
Gas (per Mcf)		5.83		6.43		6.86		6.10
Per BOE		56.00		42.42		54.30		40.84
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	7.97	$	5.99	$	7.85	$	5.71
Steam gas costs		2.29		2.66		2.31		2.73
Electricity		1.77		1.33		1.70		1.22
Production and ad valorem taxes		1.25		0.97		1.16		1.10
Gathering and transportation		0.37		0.39		0.33		0.49
DD&A per BOE (oil and gas properties)		8.45		7.18		8.45		7.14

(1) 2005 amounts represent volumes presented on a basis consistent with 2006. See Note 2.

(2) In 2005 gas revenues included amounts attributable to buy-sell contracts related to our thermal recovery operations in California and associated costs were included in steam gas costs. As a result of our adoption of EITF 04-13 effective January 1, 2006, in 2006 certain costs associated with such contracts are reflected as a reduction in gas revenues and the associated volumes are not included in sales volumes. Amounts per BOE reflected in the foregoing table are based on production volumes for 2005 and sales volumes for 2006.

27

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Contracts accounted for using hedge accounting
Oil revenues	$	—		$	(24,869	)	$	—		$	(53,044	)
Gas revenues		—			(1,322	)		—			(2,357	)
Steam gas costs		—			1,812			—			3,207
Mark-to-market contracts
Oil sales		(22,338	)		(50,851	)		(44,430	)		(87,864	)
Gas purchases		(2,848	)		—			(5,665	)		—

28

Comparison of Three Months Ended June 30, 2006 to Three Months Ended June 30, 2005

Oil and gas revenues. Oil and gas revenues increased $61.1 million, to $277.7 million for 2006 from $216.6 million for 2005. The increase is primarily due to higher realized prices.

Oil revenues excluding the effects of hedging, increased $80.1 million to $286.6 million for 2006 from $206.5 million for 2005 reflecting higher realized prices ($75.2 million) and higher production ($4.9 million). Our average realized price for oil increased $15.88 to $59.44 per Bbl for 2006 from $43.56 per Bbl for 2005. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $70.72 per Bbl in 2006 versus $53.13 per Bbl in 2005. Oil sales volumes increased to 53.0 MBbls per day in 2006 from 52.1 MBbls per day in 2005.

Hedging had the effect of decreasing our oil revenues by $36.5 million, or $7.58 per Bbl in 2006 compared to $43.8 million or $9.24 per Bbl in 2005. The 2006 amount represents the deferred losses related to 2006 swaps that were terminated in 2005. These losses were deferred in OCI and are being recognized as a noncash reduction to oil revenues as the hedged production is sold.

Gas revenues excluding the effects of hedging, decreased $27.1 million to $27.6 million in 2006 from $54.7 million in 2005 due to decreased sales volumes ($14.1 million), a decrease in revenues due to a change in the presentation of certain costs related to buy-sell contracts ($8.3 million) and lower realized prices ($4.7 million). Gas revenues for 2005 include $8.3 million attributable to buy-sell contracts related to our thermal recovery operations in California. As a result of our adoption of EITF 04-13 effective January 1, 2006 (see note 1 to the consolidated financial statements), in 2006 certain costs associated with such contracts are reflected as a reduction in gas revenues. Our average realized price for gas was $5.83 per Mcf in 2006 compared to $6.43 per Mcf in 2005. Hedging had the effect of decreasing our 2005 gas revenues by $0.8 million, or $0.09 per Mcf.

Gas sales volumes decreased from 78.5 MMcf per day in 2005 to 52.0 MMcf per day in 2006 primarily due to the sale of our properties in East Texas and Oklahoma effective May 31, 2005.

Lease operating expenses. Lease operating expenses increased $7.8 million, to $44.7 million in 2006 from $36.9 million in 2005. The increase is primarily attributable to general cost increases from service providers as well as higher expenditures for repairs and maintenance and well workovers. On a per unit basis, lease operating expenses increased to $7.97 per BOE in 2006 versus $5.99 per BOE in 2005 due to lower volumes and increased costs.

Steam gas costs. Steam gas costs decreased $3.6 million, to $12.8 million in 2006 from $16.4 million in 2005. Steam gas costs for 2005 include certain costs ($8.3 million) attributable to buy-sell contracts that after the adoption of EITF 04-13 would be included in gas revenues. On a basis comparable to 2006, 2005 steam gas costs would have been $8.1 million, or $1.36 per BOE, compared to $12.8 million, or $2.29 per BOE, in 2006, primarily reflecting the increased cost of natural gas.

Electricity. Electricity increased $1.8 million, to $10.0 million in 2006 from $8.2 million in 2005, primarily reflecting higher cost for natural gas used in electricity generation, higher cost for purchased electricity and the effect of the properties acquired in the second quarter of 2005. On a per unit basis, electricity increased to $1.77 per BOE in 2006 versus $1.33 per BOE in 2005.

Production and ad valorem taxes. Production and ad valorem taxes increased $1.0 million, to $7.0 million in 2006 from $6.0 million in 2005 primarily reflecting the effect of increased oil and gas prices, partially offset by the properties sold in the second quarter of 2005.

Gathering and transportation expenses. Gathering and transportation expenses decreased $0.3 million, to $2.1 million in 2006 from $2.4 million in 2005 primarily reflecting the properties sold in the second quarter of 2005.

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

	Three Months Ended June 30,
	2006		2005
G&A excluding stock-based compensation	$	16,812	$	11,511
Stock-based compensation		21,253		6,831
	$	38,065	$	18,342

29

G&A expense, excluding amounts attributable to stock based compensation, was $16.8 million in 2006 compared to $11.5 million in 2005. The 2006 expense includes $1.7 million related to officer resignations and organizational changes. The remainder of the increase from 2005 primarily reflects increased aircraft costs and increased employee headcount and related compensation costs.

Stock based compensation expense was $21.3 million in 2006 compared to $6.8 million in 2005. Stock based compensation costs for 2006 includes approximately $9 million related to officer resignations and organizational changes. The remainder of the increase in 2006 primarily reflects grants made subsequent to the first quarter of 2005. Certain of the Company’s stock compensation awards including SARs are subject to variable accounting and future compensation costs will be impacted by changes in the fair value of such awards.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. Capitalized costs increased to $8.0 million in 2006 compared to $5.6 million in 2005, primarily reflecting increased costs.

Depreciation, depletion and amortization, or DD&A. DD&A expense increased $5.2 million, to $50.9 million in 2006 from $45.7 million in 2005. Approximately $4.7 million of the increase was attributable to our oil and gas DD&A, primarily due to a higher per unit rate. Our oil and gas unit of production rate increased to $8.45 per BOE in 2006 compared to $7.18 per BOE in 2005. The increase primarily reflects the effect of property acquisitions, higher future development costs and 2005 capital costs for which there were no immediate reserve additions.

Accretion expense. Accretion expense increased $0.6 million, to $2.5 million in 2006 from $1.9 million in 2005, primarily reflecting higher estimated future costs of our abandonment obligations.

Interest expense. Interest expense increased $5.0 million, to $19.2 million in 2006 from $14.2 million in 2005 primarily due to higher outstanding debt and higher interest rates. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization. We capitalized $2.4 million and $0.7 million of interest in 2006 and 2005, 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 significant increase in oil prices, we recognized a $142.9 million loss related to mark-to-market derivative contracts in 2006. Cash payments related to these contracts that settled in 2006 totaled $25.2 million. In 2005 we recognized a loss on mark-to-market derivative contracts of $113.9 million. Cash payments related to these contracts that settled in 2005 totaled $50.9 million.

Gain on termination of merger agreement. On April 24, 2006 we announced that we had entered into a definitive agreement to acquire Stone in a stock-for-stock transaction. On June 22, 2006 the agreement was terminated by Stone in order for Stone to enter into a merger agreement with another company. In connection with the termination of the merger agreement we received a termination fee of $43.5 million. The gain recognized in 2006 reflects the termination fee net of certain merger related costs incurred by the Company.

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. Variances in our estimated annual effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes, changes in the estimated California apportionment factor, estimated permanent differences primarily reflecting expenses that are not deductible because of IRS limitations and, in 2005, the beneficial effect of certain tax credits related to our enhanced oil recovery operations in California. At June 30, 2006 our estimated 2006 annual effective tax rate was approximately 39% and at June 30, 2005 our estimated 2005 annual effective tax rate was approximately 35%.

30

In the second quarter of 2005 we revised our estimated effective annual tax rate to approximately 35% from the 40% estimated effective annual tax rate that was utilized in the first quarter of 2005. As a result, the effective tax rate for the second quarter of 2005 was approximately 1%. The change in the estimated effective annual tax rate was primarily the result of the sales and purchases of certain oil and gas properties in the second quarter of 2005 and the effect of a permanent difference primarily resulting from the accelerated vesting of certain restricted stock units in July 2005.

Comparison of Six Months Ended June 30, 2006 to Six Months Ended June 30, 2005

Oil and gas revenues. Oil and gas revenues increased $122.4 million, to $528.2 million for 2006 from $405.8 million for 2005. The increase is primarily due to higher realized prices.

Oil revenues excluding the effects of hedging, increased $151.5 million to $538.1 million for 2006 from $386.6 million for 2005 reflecting higher realized prices ($129.9 million) and higher production ($21.5 million). Our average realized price for oil increased $14.19 to $56.41 per Bbl for 2006 from $42.22 per Bbl for 2005. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $67.12 per Bbl in 2006 versus $51.53 per Bbl in 2005. Oil sales volumes increased 2.1 MBbls per day to 52.7 MBbls in 2006 from 50.6 MBbls per day in 2005.

Hedging had the effect of decreasing our oil revenues by $73.0 million, or $7.66 per Bbl in 2006 compared to $89.3 million or $9.75 per Bbl in 2005. The 2006 amount represents the deferred losses related to 2006 swaps that were terminated in 2005. These losses were deferred in OCI and are being recognized as a noncash reduction to oil revenues as the hedged production is sold.

Gas revenues excluding the effects of hedging, decreased $45.2 million to $63.2 million in 2006 from $108.4 million in 2005 due to decreased sales volumes ($40.0 million) and a decrease in revenues due to a change in the presentation of certain costs related to buy-sell contracts ($16.1 million), partially offset by higher realized prices ($10.9 million). Gas revenues for 2005 include $16.1 million attributable to buy-sell contracts related to our thermal recovery operations in California. As a result of our adoption of EITF 04-13 effective January 1, 2006 (see note 1 to the consolidated financial statements), in 2006 certain costs associated with such contracts are reflected as a reduction in gas revenues. Our average realized price for gas was $6.86 per Mcf in 2006 compared to $6.10 per Mcf in 2005.

Gas sales volumes decreased from 83.1 MMcf per day in 2005 to 50.8 MMcf per day in 2006 primarily due to the sale of our properties in East Texas and Oklahoma in the second quarter of 2005.

Lease operating expenses. Lease operating expenses increased $17.7 million, to $86.9 million in 2006 from $69.2 million in 2005. The increase is primarily attributable to general cost increases from service providers as well as higher expenditures for repairs and maintenance and well workovers. On a per unit basis, lease operating expenses increased to $7.85 per BOE in 2006 versus $5.71 per BOE in 2005 due to lower volumes and increased costs.

Steam gas costs. Steam gas costs decreased $7.5 million, to $25.6 million in 2006 from $33.1 million in 2005. Steam gas costs for 2005 include certain costs ($16.1 million) attributable to buy-sell contracts that after the adoption of EITF 04-13 would be included in gas revenues. On a basis comparable to 2006, 2005 steam gas costs would have been $17.0 million, or $1.46 per BOE, compared to $25.6 million, or $2.31 per BOE, in 2006, primarily reflecting the increased cost of natural gas.

Electricity. Electricity increased $4.0 million, to $18.8 million in 2006 from $14.8 million in 2005, primarily reflecting higher cost for natural gas used in electricity generation, higher cost for purchased electricity and the effect of the properties acquired in the second quarter of 2005. On a per unit basis, electricity increased to $1.70 per BOE in 2006 versus $1.22 per BOE in 2005.

Production and ad valorem taxes. Production and ad valorem taxes decreased $0.5 million, to $12.8 million in 2006 from $13.3 million in 2005 primarily reflecting the properties sold in the second quarter of 2005, partially offset by the effect of increased oil and gas prices.

Gathering and transportation expenses. Gathering and transportation expenses decreased $2.2 million, to $3.7 million in 2006 from $5.9 million in 2005 primarily reflecting the properties sold in the second quarter of 2005.

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

	Six Months Ended June 30,
	2006		2005
G&A excluding stock-based compensation	$	32,038	$	23,238
Stock-based compensation		28,999		32,632
	$	61,037	$	55,870

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G&A expense, excluding amounts attributable to stock based compensation, was $32.0 million in 2006 compared to $23.2 million in 2005. The 2006 expense includes $2.6 million related to officer resignations and organizational changes. The remainder of the increase from 2005 primarily reflects increased aircraft costs and increased employee headcount and related compensation costs.

Stock based compensation expense was $29.0 million in 2006 compared to $32.6 million in 2005. SARs related expense decreased $20.4 million, primarily reflecting the effect of variable accounting, and other stock based compensation expense increased $16.8 million, including approximately $9 million related to officer resignations and organizational changes.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. Capitalized costs increased to $15.8 million in 2006 compared to $9.8 million in 2005, primarily reflecting increased costs.

Depreciation, depletion and amortization, or DD&A. DD&A expense increased $11.4 million, to $100.7 million in 2006 from $89.3 million in 2005. Approximately $10.3 million of the increase was attributable to our oil and gas DD&A, primarily due to a higher per unit rate. Our oil and gas unit of production rate increased to $8.45 per BOE in 2006 compared to $7.14 per BOE in 2005. The increase primarily reflects the effect of property acquisitions, higher future development costs and 2005 capital costs for which there were no immediate reserve additions.

Accretion expense. Accretion expense increased $1.2 million, to $4.9 million in 2006 from $3.7 million in 2005, primarily reflecting higher estimated future costs of our abandonment obligations.

Interest expense. Interest expense increased $9.4 million, to $35.0 million in 2006 from $25.6 million in 2005 primarily due to higher outstanding debt and higher interest rates. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization. We capitalized $3.9 million and $1.4 million of interest in 2006 and 2005, 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 significant increase in oil prices, we recognized a $312.2 million loss related to mark-to-market derivative contracts in 2006. Cash payments related to these contracts that settled in 2006 totaled $50.1 million. In 2005 we recognized a loss on mark-to-market derivative contracts of $487.9 million. Cash payments related to these contracts that settled in 2005 totaled $87.8 million. In addition, we paid $145.4 million in connection with the elimination of our 2006 collars.

Gain on termination of merger agreement. On April 24, 2006 we announced that we had entered into a definitive agreement to acquire Stone in a stock-for-stock transaction. On June 22, 2006 the agreement was terminated by Stone in order for Stone to enter into a merger agreement with another company. In connection with the termination of the merger agreement we received a termination fee of $43.5 million. The gain recognized in 2006 reflects the termination fee net of certain merger related costs incurred by the Company.

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. Variances in our estimated annual effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes, changes in the estimated California apportionment factor, estimated permanent differences primarily reflecting expenses that are not deductible because of IRS limitations and, in 2005, the beneficial effect of certain tax credits related to our enhanced oil recovery operations in California. At June 30, 2006 our estimated 2006 annual effective tax rate was approximately 39% and at June 30, 2005 our estimated 2005 annual effective tax rate was approximately 35%.

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Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At June 30, 2006 we had approximately $500 million of availability under our revolving credit facility. 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 2006, excluding acquisitions, of approximately $496 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, expenditures under our stock repurchase program, 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 use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil or gas prices above the maximum fixed amount specified in the derivative agreement. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. In addition, the majority of our capital expenditures and expenditures under our stock repurchase program are discretionary and could be curtailed if our cash flows declined from expected levels.

At June 30, 2006 we had a working capital deficit of approximately $235 million. Approximately $166 million of the working capital deficit is attributable to our commodity derivative instruments (net of related deferred income taxes). In accordance with SFAS 133, 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 seven financial institutions that are contract counterparties for our derivative commodity contracts all have Standard & Poor’s ratings of A or better and all seven of the financial institutions are participating lenders in our revolving credit facility. At June 30, 2006 we were in a net liability position with all such counterparties.

At December 31, 2005 we had collars on 22,000 barrels of oil per day for all of 2007 and 2008 with a floor price of $25.00 and an average ceiling price of $34.76. In April 2006, we executed a series of offsetting contracts to eliminate all of these crude oil price collars at a pre-tax cost of approximately $593 million. This amount represents the fair value of the collars on the date we entered into the offsetting positions. Since the collars were not designated as a hedge such amount has been recognized in our income statement as a loss on mark-to-market derivative contracts ($170 million in 2006 and $423 million in prior periods).

We may settle these contracts as they mature (i.e., on a monthly basis throughout 2007 and 2008) or, at our option, we may pay the amounts due at an earlier date. If the contracts are settled as they mature, our total cost would be approximately $644 million and the $51 million in excess of the fair value on the date we entered into the offsetting positions would be recognized in our income statement as interest expense.

Financing Activities

At June 30, 2006 we had $231 million outstanding under the terms of our senior revolving credit facility that matures May 16, 2010, $275.0 million principal amount of 8.75% Senior Subordinated Notes due 2012 and $250.0 million principal amount of 7.125% Senior Notes due 2014. No amounts were outstanding under the terms of our short-term credit facility.

Cash Flows

	Six Months Ended June 30,
	2006			2005
	(in millions)
Cash provided by (used in):
Operating activities	$	405.8		$	113.5
Investing activities		(336.7	)		39.2
Financing activities		(69.2	)		(153.3	)

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Net cash provided by operating activities was $405.8 million in 2006 compared to $113.5 million in 2005. The increase in net cash provided by operating activities in 2006 is primarily a result of increased oil and gas prices, the proceeds from the termination of the merger agreement with Stone and the effect in 2005 of a $147.3 million payment to eliminate our 2006 oil price swaps. As discussed below, certain of our derivative cash payments are classified as financing or investing activities.

Net cash used in investing activities was $336.7 million in 2006 primarily reflecting additions to oil and gas properties of $289.4 million and derivative settlements of $42.7 million. Net cash provided by investing activities was $39.2 million in 2005 primarily reflecting property sales proceeds of $341.0 million partially offset by additions to oil and gas properties of $299.1 million. Derivative settlements related to derivatives that have not been qualified for hedge accounting and do not contain a significant financing element are reflected as investing activities.

Net cash used in financing activities in 2006 was $69.2 million, primarily reflecting $41.0 million in net repayments under our senior revolving credit facility and the payment of $28.6 million in financing derivative settlements. Net cash used in financing activities in 2005 was $153.3 million, primarily reflecting $116.5 million in net borrowings under our senior revolving credit facility and the payment of $270.7 million in financing derivative settlements. 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.

Stock Repurchase Program

Our Board of Directors has authorized the repurchase of up to $500 million of our common stock. The shares will be repurchased from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. In July 2006 we repurchased 2,461,900 common shares at a cost of $100.8 million.

Stock Appreciation Rights

We incur cash expenditures upon the exercise of SARs, but our common shares outstanding do not increase. At June 30, 2006 we had approximately 2.7 million SARs outstanding of which 1.7 million were vested. If all of the vested SARs were exercised, based on $40.54, the price of our common stock as of June 30, 2006, we would pay $50.4 million to holders of the SARs. In the first half of 2006 we made cash payments of $5.6 million for SARs that were exercised during that period.

Commitments and Contingencies

Contractual obligations. In March 2006 we entered into an operating lease with respect to an aircraft under the terms of which we will be required to make lease payments as follows: 2006 - $2.3 million, 2007 and 2008 - $6.1 million, 2009 and 2010 - $6.1 million and thereafter - $16.0 million.

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 based compensation and goodwill are discussed in our Annual Report on Form 10-K for the year ended December 31, 2005.

Recent Accounting Pronouncements

In February 2006, the FASB issued SFAS 155 which eliminates the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. SFAS 155 also allows the election of fair value measurement at acquisition, at issuance, or when a

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previously recognized financial instrument is subject to a remeasurement event. Adoption is effective for all financial instruments acquired or issued after the beginning of the first fiscal year that begins after September 15, 2006. Early adoption is permitted. The adoption of SFAS 155 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.

In March 2006, the FASB issued SFAS 156 which requires all separately recognized servicing assets and servicing liabilities be initially measured at fair value. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities at fair value. Adoption is required as of the beginning of the first fiscal year that begins after September 15, 2006. Early adoption is permitted. The adoption of SFAS 156 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.

In June 2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement No. 109)” which is effective for fiscal years beginning after December 15, 2006 with earlier adoption encouraged. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We are currently evaluating the potential impact of this interpretation.

Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking information regarding Plains Exploration & Production Company that is intended to be covered by the safe harbor for “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 future capital expenditures (including the amount and nature thereof);

• impact of oil and gas price fluctuations, including the impact on our reserve volumes and values and 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;

• the success of our derivative activities;

• the success of our risk management activities;

• unexpected difficulties in integrating our operations as a result of any significant acquisitions;

• the effects of competition;

• 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 Item 1A – “Risk Factors” and Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Factors That May Affect Future Results” in our Annual Report on Form 10-K for the year ended December 31, 2005 for additional discussions of risks and uncertainties.

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Item 3 – Quantitative and Qualitative Disclosures About Market Risks

Commodity Price Risk

We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production and the purchase of natural gas used in our thermal recovery operations. 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 a gain or (loss) on mark-to-market derivative contracts. Cash flows are only impacted to the extent the actual settlements under the contracts result in making a payment to 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.

See Note 2 to the Consolidated Financial Statements – “Derivative Instruments and Hedging Activities” for a discussion of our derivative activities.

At December 31, 2005 we had collars on 22,000 barrels of oil per day for all of 2007 and 2008 with a floor price of $25.00 and an average ceiling price of $34.76. In April 2006, we executed a series of offsetting contracts to eliminate all of these crude oil price collars at a pre-tax cost of approximately $593 million. This amount represents the fair value of the collars on the date we entered into the offsetting positions. Since the collars were not designated as a hedge such amount has been recognized in our income statement as a loss on mark-to-market derivative contracts ($170 million in 2006 and $423 million in prior periods).

We may settle these contracts as they mature (i.e., on a monthly basis throughout 2007 and 2008) or, at our option, we may pay the amounts due at an earlier date. If the contracts are settled as they mature, our total cost would be approximately $644 million and the $51 million in excess of the fair value on the date we entered into the offsetting positions would be recognized in our income statement as interest expense.

At June 30, 2006 we also had the following open commodity derivative positions, none of which were designated as hedging instruments:

Period	Instrument Type	Daily Volumes	Average Price	Index
Sales of Crude Oil Production
2006
Jul - Dec	Put options	50,000 Bbls	$55.00 Strike price	WTI
2007
Jan - Dec	Put options	50,000 Bbls	$55.00 Strike price	WTI
2008
Jan - Dec	Put options	42,000 Bbls	$55.00 Strike price	WTI
Purchases of Natural Gas
2006
Jul - Dec	Call options	30,000 MMBtu	$12.00 Strike price	Socal

The average strike price for the put options and call options do not reflect the cost to purchase such options. The crude oil put options cost an average of $4.91 per barrel for 2006, $5.57 per barrel for 2007 and $3.35 per barrel for 2008. The natural gas call options cost an average of $1.04 per MMBtu. The premiums for the put and call options will be paid when the options are settled.

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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, 2006
	Asset (Liability) Fair Value			Effect of 10% Price Increase
Crude oil put options and natural gas call options	$	42.1		$	(18.7	)
Crude oil collars (1)		(593.3	)		—

(1) Since we have offsetting positions, price changes have no effect on our liability.

The fair value of the commodity derivative 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 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. The cost of our puts and calls is not included in the fair value of derivatives in the foregoing table.

The seven financial institutions that are contract counterparties for our derivative commodity contracts all have Standard & Poor’s ratings of A or better and all seven of the financial institutions are participating lenders in our revolving credit facility. At June 30, 2006 we were in a net liability position with all such counterparties.

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

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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, 2006 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, 2006 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 13, 2006 at the Company’s 2006 annual meeting of stockholders, held on May 4, 2006 in Houston, Texas:

		For	Against	Abstained or Withheld
(i)	Election of Directors
	James C. Flores	69,090,681	—	388,979
	Isaac Arnold, Jr.	69,381,607	—	98,053
	Alan R. Buckwalter, III	68,963,813	—	515,847
	Jerry L. Dees	66,290,594	—	3,189,066
	Tom H. Delimitros	66,289,380	—	3,190,280
	Robert L. Gerry, III	68,965,620	—	514,040
	John H. Lollar	65,925,040	—	3,554,620
(ii)	Ratification of PricewaterhouseCoopers LLP, independent certified public accountants, as auditors of the Company’s financial statements for the fiscal year ended December 31, 2006	68,708,941	743,530	27,189

Of the 78,555,369 shares of common stock issued and outstanding on March 13, 2006, 69,479,660 were present, either in person or by proxy.

ITEM 6 – Exhibits

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, 1A, 2, 3 and 5 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 4, 2006

By:	/s/ Winston M. Talbert
	Winston M. Talbert Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

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EXHIBIT INDEX

Exhibit No.	Description
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

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