Plains Exploration & Production 10-Q 2008 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, 2008

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, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨    (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

107.6 million shares of Common Stock, $0.01 par value, issued and outstanding at July 31, 2008.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION
ITEM 1. Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets June 30, 2008 and December 31, 2007	1
Consolidated Statements of Income For the three months and six months ended June 30, 2008 and 2007	2
Consolidated Statements of Cash Flows For the six months ended June 30, 2008 and 2007	3
Consolidated Statement of Stockholders’ Equity For the six months ended June 30, 2008	4
Notes to Consolidated Financial Statements	5
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk	37
ITEM 4. Controls and Procedures	39
PART II. OTHER INFORMATION	40

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	June 30, 2008			December 31, 2007
ASSETS
Current Assets
Cash and cash equivalents	$	2,494		$	25,446
Restricted cash		-			59,092
Accounts receivable		406,745			304,972
Inventories		24,291			18,394
Deferred income taxes		175,793			229,893
Other current assets		12,946			37,123
		622,269			674,920
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		7,087,870			7,340,238
Not subject to amortization		1,384,611			1,951,783
Other property and equipment		110,955			85,928
		8,583,436			9,377,949
Less allowance for depreciation, depletion and amortization		(1,267,019	)		(1,000,722	)
		7,316,417			8,377,227
Goodwill		535,296			536,822
Other Assets		103,433			104,382
	$	8,577,415		$	9,693,351
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	284,148		$	319,583
Commodity derivative contracts		101,825			79,938
Royalties and revenues payable		169,196			132,919
Stock appreciation rights		23,977			63,106
Interest payable		19,228			25,330
Accrued merger expenses		2,764			77,980
Other current liabilities		79,483			119,190
		680,621			818,046
Long-Term Debt
Senior revolving credit facility		611,000			2,205,000
Senior notes		1,500,000			1,100,000
		2,111,000			3,305,000
Other Long-Term Liabilities
Asset retirement obligation		179,665			184,080
Commodity derivative contracts		31,428			33,821
Other		143,460			54,726
		354,553			272,627
Deferred Income Taxes		2,006,433			1,959,431
Commitments and Contingencies (Note 9)
Stockholders’ Equity
Common stock		1,128			1,128
Additional paid-in capital		2,710,212			2,711,617
Retained earnings		990,412			623,993
Accumulated other comprehensive income		1,519			1,566
Treasury stock		(278,463	)		(57	)
		3,424,808			3,338,247
	$	8,577,415		$	9,693,351

See notes to consolidated financial statements.

1

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Revenues
Oil sales	$	545,767		$	231,583		$	1,002,351		$	437,101
Gas sales		182,334			23,210			346,403			40,745
Other operating revenues		4,602			754			7,026			2,394
		732,703			255,547			1,355,780			480,240
Costs and Expenses
Production costs
Lease operating expenses		85,248			50,112			159,756			94,775
Steam gas costs		40,599			27,924			72,757			54,281
Electricity		10,661			9,500			22,298			18,267
Production and ad valorem taxes		24,181			5,042			50,409			10,301
Gathering and transportation expenses		2,462			1,220			10,951			1,406
General and administrative		45,203			29,913			85,131			52,410
Depreciation, depletion and amortization		130,749			58,523			271,602			111,201
Accretion		3,223			2,273			6,610			4,535
		342,326			184,507			679,514			347,176
Income from Operations		390,377			71,040			676,266			133,064
Other Income (Expense)
Gain on sale of assets		-			-			34,658			-
Interest expense		(23,511	)		(11,698	)		(54,120	)		(17,058	)
Debt extinguishment costs		-			-			(10,263	)		-
Loss on mark-to-market derivative contracts		(51,427	)		(15,837	)		(60,908	)		(36,427	)
Interest and other income		1,686			747			1,661			1,324
Income Before Income Taxes		317,125			44,252			587,294			80,903
Income tax expense
Current		(61,716	)		-			(102,253	)		-
Deferred		(52,491	)		(18,934	)		(118,622	)		(35,015	)
Net Income	$	202,918		$	25,318		$	366,419		$	45,888
Earnings per Share
Basic	$	1.88		$	0.35		$	3.33		$	0.63
Diluted	$	1.84		$	0.35		$	3.27		$	0.63
Weighted Average Shares Outstanding
Basic		107,707			72,171			109,939			72,316
Diluted		110,138			73,275			112,147			73,382

See notes to consolidated financial statements.

2

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

	Six Months Ended June 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	366,419		$	45,888
Items not affecting cash flows from operating activities
Gain on sale of assets		(34,658	)		-
Depreciation, depletion, amortization and accretion		278,212			115,736
Deferred income taxes		118,622			35,015
Debt extinguishment costs		10,263			-
Loss on commodity derivative contracts		60,908			36,427
Noncash compensation		40,451			21,621
Other noncash items		2,886			(31	)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(99,046	)		(7,548	)
Accounts payable and other liabilities		(76,847	)		(5,155	)
Stock appreciation rights		(58,357	)		(6,431	)
Income taxes receivable/payable		509			(94,272	)
Net cash provided by operating activities		609,362			141,250
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(441,123	)		(258,182	)
Acquisition of oil and gas properties		(331,293	)		(973,875	)
Acquisition of Pogo Producing Company		(74,844	)		-
Derivative settlements		(29,593	)		(49,143	)
Proceeds from property sales, net of costs and expenses		1,717,781			-
Decrease in restricted cash		59,092			-
Additions to other property and equipment		(27,443	)		(24,164	)
Other		(1,229	)		(3,431	)
Net cash provided by (used in) investing activities		871,348			(1,308,795	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		4,237,756			1,456,250
Repayments		(5,831,756	)		(1,316,750	)
Proceeds from issuance of long-term debt		400,000			1,100,000
Cost incurred in connection with financing arrangements		(6,064	)		(17,917	)
Derivative settlements		(13,088	)		-
Purchase of treasury stock		(304,192	)		(47,485	)
Other		13,682			3,341
Net cash (used in) provided by financing activities		(1,503,662	)		1,177,439
Net (decrease) increase in cash and cash equivalents		(22,952	)		9,894
Cash and cash equivalents, beginning of period		25,446			899
Cash and cash equivalents, end of period	$	2,494		$	10,793

See notes to consolidated financial statements.

3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)

	Common Stock			Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Income			Treasury Stock
	Shares	Amount										Shares		Amount			Total
Balance at December 31, 2007	112,841	$	1,128	$	2,711,617		$	623,993	$	1,566		(1	)	$	(57	)	$	3,338,247
Net income	-		-		-			366,419		-		-			-			366,419
Restricted stock awards	12		-		24,154			-		-		-			-			24,154
Treasury stock purchases	-		-		-			-		-		(5,771	)		(304,192	)		(304,192	)
Issuance of treasury stock for restricted stock awards	-		-		(25,786	)		-		-		475			25,786			-
Other comprehensive income	-		-		-			-		(47	)	-			-			(47	)
Exercise of stock options	13		-		227			-		-		-			-			227
Balance at June 30, 2008	112,866	$	1,128	$	2,710,212		$	990,412	$	1,519		(5,297	)	$	(278,463	)	$	3,424,808

See notes to consolidated financial statements.

4

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1—Organization and Significant Accounting Policies

The consolidated financial statements of Plains Exploration & Production Company, a Delaware corporation (“PXP”, “us”, “our”, or “we”), include the accounts of all its wholly owned subsidiaries. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior year statements to conform to the current year presentation.

We are an independent energy company engaged in the “upstream” oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are primarily located in the United States. We also have interests in exploration prospects offshore New Zealand and Vietnam.

These consolidated financial statements and related notes present our consolidated financial position as of June 30, 2008 and December 31, 2007, the results of our operations and comprehensive income for the three months and six months ended June 30, 2008 and 2007, our cash flows for the six months ended June 30, 2008 and 2007 and the changes in stockholders’ equity for the six months ended June 30, 2008. 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. The results of our operations for the six months ended June 30, 2008 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, 2007.

Asset Retirement Obligations. The following table reflects the changes in our asset retirement obligation during the six months ended June 30, 2008 (in thousands):

Asset retirement obligation - December 31, 2007	$	195,408
Property dispositions		(14,113	)
Settlements		(1,143	)
Accretion expense		6,610
Acquisitions		1,697
Asset retirement additions		2,111
Asset retirement obligation - June 30, 2008 (1)	$	190,570
(1) $10.9 million included in other current liabilities.

Earnings Per Share. For the three months and six months ended June 30, 2008 and 2007 the weighted average shares outstanding for computing basic and diluted earnings per share (“EPS”) were (in thousands):

	Three Months Ended June 30,		Six Months Ended June 30,
	2008	2007	2008	2007
Weighted average common shares outstanding - basic	107,707	72,171	109,939	72,316
Unvested restricted stock, restricted stock units and stock options	2,431	1,104	2,208	1,066
Weighted average common shares outstanding - diluted	110,138	73,275	112,147	73,382

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

5

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,       2008		December 31, 2007
Oil	$	7,535	$	6,066
Materials and supplies		16,756		12,328
	$	24,291	$	18,394

Stockholders’ Equity. Our Board of Directors has authorized the repurchase of up to $1.0 billion 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. During the six months ended June 30, 2008 we repurchased approximately 5.8 million common shares at a cost of approximately $304.2 million. We may expend an additional $695.8 million under the program.

Comprehensive Income. Other comprehensive income consisted of (in thousands):

	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008			2007
Net Income	$	202,918		$	25,318	$	366,419		$	45,888
Other Comprehensive Income Pension liability adjustment, net of tax benefit		(23	)		-		(47	)		-
Comprehensive Income	$	202,895		$	25,318	$	366,372		$	45,888

Recent Accounting Pronouncements. In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires companies with noncontrolling interests to disclose those interests clearly as a portion of equity but separate from the parent’s equity. The noncontrolling interest’s portion of net income must also be clearly presented on the income statement. SFAS 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and we do not expect this pronouncement to have a significant impact on our consolidated financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”). SFAS 141R broadens the guidance of SFAS 141, extending its applicability to all transactions and other events in which one entity obtains control over one or more other businesses. It broadens the fair value measurement and recognition of assets acquired, liabilities assumed, and interests transferred as a result of business combinations and requires that acquisition related costs incurred prior to the acquisition be expensed. SFAS 141R expands on the required disclosures to improve the financial statement users’ ability to evaluate the nature and financial effects of business combinations. SFAS 141R is effective for business combinations for which the acquisition date is on or after January 1, 2009, except for certain income tax effects of prior acquisitions for which SFAS 141R is now effective. We are currently evaluating the potential impact of this statement.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 is effective for fiscal years beginning after November 15, 2008, with early application encouraged. We do not expect this pronouncement to have a significant impact on our consolidated financial position, results of operations or cash flows.

6

In May 2008, the FASB issued SFAS No. 162 “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States of America. SFAS 162 is effective sixty days following the SEC’s approval of Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of ‘Present Fairly’ in Conformity With Generally Accepted Accounting Principles.” We do not expect this pronouncement to have a significant impact on our consolidated financial position, results of operations or cash flows.

Note 2—Acquisitions

Pogo Producing Company

On November 6, 2007, we acquired Pogo Producing Company (“Pogo”), in a stock and cash transaction. We paid cash consideration of approximately $1.5 billion and issued approximately 40 million common shares valued at approximately $2.0 billion. In addition, we paid cash consideration of $35.4 million to redeem outstanding stock options. The total purchase price included $154.2 million of merger costs. We accounted for the Pogo acquisition as a purchase effective November 6, 2007, and the assets and liabilities were recorded at their fair value. The purchase price allocation is preliminary subject to our determination of Pogo’s final tax basis and fair value of certain liabilities that has not been completed as of June 30, 2008. We expect to finalize the purchase price allocation in the third quarter of 2008. During the first half of 2008, goodwill related to the acquisition was decreased by $1.5 million.

Unaudited Pro Forma Information

The following unaudited pro forma information shows the pro forma effect on our results for the three months and six months ended June 30, 2007 of the Pogo acquisition and certain other material acquisition and financing transactions, including: (1) the acquisition of certain properties located in the Piceance Basin for $975 million in cash and one million shares of common stock in May 2007, (2) the issuance by PXP of $500 million of 7% Senior Notes due 2017 in March 2007, (3) the issuance by PXP of $600 million of 7 ³/4% Senior Notes due 2015 in June 2007, (4) $2.0 billion of borrowings under the senior revolving credit facility, and (5) the retirement of Pogo’s $450 million 7.875% Senior Subordinated Notes due 2013, $300 million 6.625% Senior Subordinated Notes due 2015, and $500 million 6.875% Senior Subordinated Notes due 2017. We believe the assumptions used provide a reasonable basis for presenting the pro forma significant effects directly attributable to these transactions. This unaudited pro forma information assumes such transactions occurred on January 1, 2007. This pro forma financial information does not purport to represent what our results of operations would have been if such transactions had occurred on that date.

	Three Months Ended June 30, 2007		Six Months Ended June 30, 2007
	(in thousands except per share data)
	(unaudited)
Revenues	$	488,164	$	944,279
Income from continuing operations		28,346		(9,972	)
Net income		28,346		(9,972	)
Basic and diluted earnings per share
Income from continuing operations	$	0.25	$	(0.09	)
Net income	$	0.25	$	(0.09	)
Weighted average shares outstanding
Basic		112,830		113,146
Diluted		113,934		114,212

South Texas Properties

On April 17, 2008, we completed the acquisition of oil and gas producing properties in South Texas from a private company. After the exercise of third party preferential rights, we paid $291 million in cash, which included preliminary closing adjustments of approximately $10 million. We funded the acquisition primarily with proceeds from recently completed divestments through the use of a tax deferred like-kind exchange (See Note 3—Divestitures). We estimate that proved reserves were approximately 93 billion cubic feet of natural gas equivalent as of December 31, 2007. The effective date of the transaction is January 1, 2008.

7

Piceance Basin Expansion

On June 27, 2008, PXP and a subsidiary of Occidental Petroleum Corporation (“Oxy”) acquired from a third party working interests in acreage immediately adjacent to our existing Piceance Basin assets. PXP and Oxy, a 50% owner in our Piceance Basin assets, have agreed to pay an aggregate of $158.6 million for a 95% working interest comprising approximately 11,500 net acres. We will operate these properties, which include over 800 potential future drilling locations. Under the terms of the agreement, we paid approximately $20.3 million on June 27, 2008, with the remaining balance payable in equal amounts of approximately $20.3 million on July 1, 2009 and July 1, 2010 and approximately $18.5 million on July 1, 2011. PXP’s total consideration of $79.3 million was allocated to oil and gas properties not subject to amortization. The $59.0 million of unpaid consideration is included in Other Long-Term Liabilities on our Consolidated Balance Sheet at June 30, 2008.

Subsequent Event

On July 7, 2008, we acquired from a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) a 20% interest in Chesapeake’s Haynesville Shale leasehold as of June 30, 2008 for approximately $1.65 billion in cash, of which we paid $1.375 billion on July 7, 2008 and expect to pay the remainder on or before October 30, 2008, subject to customary post-closing adjustments. In connection with the acquisition we also agreed, over a multi-year period, to fund 50% of Chesapeake’s drilling and completion costs associated with future Haynesville Shale wells, up to an additional $1.65 billion. In addition, we will have the option to participate for 20% of any additional leasehold that Chesapeake, or its affiliates, acquires in the Haynesville Shale within a designated area of mutual interest. Chesapeake has publicly stated that its estimated Haynesville Shale leasehold as of June 30, 2008 was approximately 550,000 net acres, which will entitle us to approximately 110,000 net acres. There are no material proved reserves associated with the acreage.

Note 3—Divestitures

On February 15, 2008, we closed the sale to XTO Energy Inc. (“XTO”) of our interests in certain oil and gas properties located in the San Juan Basin in New Mexico and in the Barnett Shale in Texas. This transaction had an effective date of January 1, 2008, and we received $199.0 million in cash proceeds. On February 29, 2008 we completed the acquisition of XTO’s 50% working interest in the Big Mac prospect located on the Texas Gulf Coast for approximately $20.2 million.

On February 29, 2008, we closed the sale of certain oil and gas properties to a subsidiary of Oxy and certain other companies with contractual preferential rights to purchase, with an effective date of January 1, 2008, and received approximately $1.53 billion in cash proceeds. We sold 50% of our working interests in oil and gas properties located in the Permian Basin, West Texas and New Mexico. We retained 50% of our working interest in these properties, and Oxy will be the operator of all the assets previously operated by us. We acquired the above referenced properties in the Pogo acquisition on November 6, 2007, and the property revenues and expenses were included in our historical consolidated statement of income beginning on that date through the closing date of the sale. We also sold 50% of our working interests in oil and gas properties located in the Piceance Basin in Colorado, including a 50% interest in the entity that holds our interest in Collbran Valley Gas Gathering LLC (“CVGG”), and we retained 50% of our working interest in these oil and gas properties. We will remain the operator of these properties. We acquired these properties on May 31, 2007, and the property revenues and expenses were included in our historical consolidated statement of income beginning on that date through the closing date of the sale. We recorded a $34.7 million pretax gain on the sale of the 50% interest in the entity that holds our interest in CVGG.

Our aggregate working interest in the properties sold in February 2008 generated total sales volumes of approximately 11 thousand barrels of oil equivalent per day (“MBOEPD”) during the first quarter of 2008 and had 105 million barrels of oil equivalent (“BOE”) of estimated proved reserves as of December 31, 2007.

We follow the full cost method of accounting under which proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless these sales involve a significant change in the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. A gain or loss was not recognized on our sales of oil and gas properties, as the sales did not cause a significant change in the relationship between our capitalized costs and estimated proved reserves. The proceeds from the sales of oil and gas properties were recorded as reductions to capitalized costs.

8

Note 4—Long-Term Debt

At June 30, 2008 and December 31, 2007, long-term debt consisted of (in thousands):

	June 30, 2008		December 31, 2007
Senior revolving credit facility	$	611,000	$	2,205,000
7 3/4% Senior Notes		600,000		600,000
7% Senior Notes		500,000		500,000
7 5/8% Senior Notes		400,000		-
	$	2,111,000	$	3,305,000

On February 13, 2008, we entered into an amendment to our senior revolving credit facility. The amendment reduced the borrowing base and commitments to $2.5 billion and $1.9 billion, respectively from $2.9 billion upon the closing of the sale of certain properties to XTO and Oxy. In addition, the amendment allows us to repurchase up to $1.0 billion of our common stock subject to certain conditions being met. We recognized $10.3 million of debt extinguishment costs in connection with the reduction in our borrowing base. Further, the borrowing base was reduced again upon the May 2008 closing of the 7 ⁵/8% Senior Notes due 2018, from $2.5 billion to approximately $2.4 billion.

Our senior revolving credit facility, as amended, contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries to, among other things, incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into take-or-pay or other prepayment arrangements, merge or consolidate and enter into transactions with affiliates. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined) of no greater than 4.25 to 1.

We have an uncommitted short-term unsecured credit facility under the terms of which we may make borrowings from time to time until June 1, 2009, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding fourteen days and all amounts outstanding are due and payable no later than June 1, 2009. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and PXP.

In May 2008, we issued $400 million of 7 ⁵/8% Senior Notes due 2018 (the “7 ⁵/8% Senior Notes”) at par. We may redeem all or part of the 7 ⁵/8% Senior Notes on or after June 1, 2013 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to June 1, 2011 we may, at our option, redeem up to 35% of the 7 ⁵/8% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 7 ⁵/8% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 7 ³/4% Senior Notes due 2015, the 7% Senior Notes due 2017 and the 7 ⁵/8% Senior Notes (together, “the Senior Notes”) are our general unsecured, senior obligations. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. The Senior Notes rank senior in right of payment to all of our existing and future subordinated indebtedness;pari passu in right of payment with any of our existing and future unsecured indebtedness that is not by its terms subordinated to the Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility, to the extent of our assets constituting collateral securing that indebtedness; and effectively subordinate to all existing and future indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our non-guarantor subsidiaries.

The indenture governing the Senior Notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional debt; make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock; sell assets, including capital stock of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries; create liens that secure debt; enter into transactions with affiliates; and merge or consolidate with another company.

At June 30, 2008, we had $5.7 million in letters of credit outstanding under our senior revolving credit facility, and the effective interest rate on our borrowings under the facility was 3.82%.

9

Subsequent Events

In connection with the Chesapeake transaction (See Note 2—Acquisitions), we increased the aggregate commitments under, and entered into an amendment to, our senior revolving credit facility. On July 2, 2008, the aggregate commitments of the lenders under our senior revolving credit facility were increased by $400 million to $2.3 billion from $1.9 billion. In addition, on July 23, 2008, we entered into an amendment to our senior revolving credit facility to increase the borrowing base to $3.1 billion from approximately $2.4 billion and further increase the commitments to $2.7 billion from $2.3 billion.

Note 5—Derivative Instruments

We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized currently in our income statement as 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. We do not currently use hedge accounting for our derivative instruments.

Under SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”, certain of our derivatives were 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 not accounted for under hedge accounting and do not have a significant financing element are reflected as investing activities in the Statement of Cash Flows.

During June 2008, we entered into crude oil put option contracts on 40,000 barrels of oil per day in 2009 and 2010. The 2009 put options have an average strike price of $106.16 per barrel and an average deferred premium plus interest of $6.19 per barrel, and the 2010 put options have an average strike price of $111.49 per barrel and an average deferred premium plus interest of $12.08 per barrel. The put options for 2009 and 2010 are settled annually based on a calendar year average price. We also acquired natural gas collars with an average floor price of $10.00 per million British thermal units (“MMBtu”) and an average ceiling price of $20.00 per MMBtu on 150,000 MMBtu per day for the months of July 2008 through December 2009. The average deferred premium plus interest is $0.346 per MMBtu and is settled monthly. The deferred premium plus interest is recorded as an offset to commodity derivative assets or as a commodity derivative liability on our Consolidated Balance Sheet when a master netting agreement exists.

At June 30, 2008, we had the following open commodity derivative positions, none of which were designated as hedging instruments:

Period	Instrument Type	Daily Volumes	Average Price(1)	Index
Sales of Crude Oil Production
2008
July - Dec	Put options	42,000 Bbls	$55.00 Strike price	WTI
July - Dec	Collar	2,500 Bbls	$60.00 Floor - $80.13 Ceiling	WTI
2009
Jan - Dec	Put options	32,500 Bbls	$55.00 Strike price	WTI
Jan - Dec	Put options	40,000 Bbls	$106.16 Strike price	WTI
2010
Jan - Dec	Put options	40,000 Bbls	$111.49 Strike price	WTI
Sales of Natural Gas Production
2008
July - Dec	Collar	15,000 MMBtu	$8.00 Floor - $12.11 Ceiling	Henry Hub
July - Dec	Collar	150,000 MMBtu	$10.00 Floor - $20.00 Ceiling	Henry Hub
2009
Jan - Dec	Collar	150,000 MMBtu	$10.00 Floor - $20.00 Ceiling	Henry Hub

⁽¹⁾ The average strike prices do not reflect the cost to purchase the put options or collars.

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The only cash settlements we are required to make on the purchased put options are option premiums and interest. Commodity derivative liabilities at June 30, 2008 include deferred premium and associated accrued interest of (i) approximately $28.9 million for the last six months of 2008, which will be paid ratably each month, (ii) approximately $38.2 million which will be paid ratably each month and approximately $84.4 million which will be paid at the end of the annual period for 2009 and (iii) approximately $159.7 million for 2010, which will be paid at the end of the annual period.

For a collar contract, (i) we are required to pay cash settlements to the counterparty if the settlement price for any settlement period is above the ceiling price, (ii) the counterparty is required to pay cash settlements to us if the settlement price for any settlement period is below the floor price and (iii) neither party is required to pay cash settlements to the other party if the settlement price for any settlement period is equal to or between the floor and ceiling price. We are required to pay premiums and interest for the natural gas collars with daily volumes of 150,000 MMBtu per day. Commodity derivative liabilities at June 30, 2008 include deferred premium and associated accrued interest of approximately $9.4 million for the last six months of 2008 and approximately $18.5 million for 2009. These payments will be made on the monthly settlement dates.

At June 30, 2008 and December 31, 2007, commodity derivative assets and liabilities consisted of the following (in thousands):

	June 30, 2008			December 31, 2007
Commodity derivative assets
Crude oil puts	$	230,555		$	3,786
Natural gas collars		20,542			4,378
Commodity derivative liabilities
Crude oil collars		(27,599	)		-
Natural gas collars		(4,798	)		(13,314	)
Net derivative fair value asset (liability)		218,700			(5,150	)
Deferred premium and accrued interest on puts and collars		(339,147	)		(93,902	)
Settlement payable		(8,813	)		(12,521	)
Net commodity derivative liability	$	(129,260	)	$	(111,573	)
Commodity derivative short-term asset	$	-		$	2,186
Commodity derivative long-term asset		3,993	(1)		-
Commodity derivative short-term liability		(101,825	)		(79,938	)
Commodity derivative long-term liability		(31,428	)		(33,821	)
	$	(129,260	)	$	(111,573	)

⁽¹⁾ Included in Other Assets on our Consolidated Balance Sheet.

We present the fair value of our derivatives for which a master netting agreement exists on a net basis in accordance with FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts an interpretation of APB Opinion No. 10 and FASB Statement No. 105” (“FIN 39”).

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Note 6—Stock Based Compensation

We account for stock based compensation in accordance with the provisions of 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.

Stock based compensation for the three and six months ended June 30, 2008 and 2007 was (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
Stock based compensation included in:
General and administrative expense	$	20,571	$	14,346	$	32,316	$	19,974
Lease operating expenses		7,807		1,372		8,135		1,647
Oil and natural gas properties		8,704		3,172		11,543		4,580
Total stock based compensation	$	37,082	$	18,890	$	51,994	$	26,201

Stock Appreciation Rights (“SARs”)

The following table summarizes the status of our SARs at June 30, 2008 and the changes during the six months then ended:

	Outstanding (thousands)		Weighted Average Exercise Price		Aggregate Intrinsic Value ($ thousands)		Weighted Average Remaining Contractual Life (Years)
Outstanding at January 1, 2008	2,767		$	28.90
Granted	742			51.37
Exercised	(1,343	)		13.26
Forfeited or expired	(122	)		48.68
Outstanding at June 30, 2008	2,044			46.14	$	54,861	3.6
Exercisable at June 30, 2008	310		$	35.60	$	11,581	2.3

We paid $58.4 million for SARs exercised during the six months ended June 30, 2008 and our liability associated with SARs decreased from $68.4 million at December 31, 2007 to $29.5 million at June 30, 2008.

Restricted Stock and Restricted Stock Units (“RSUs”)

The following table summarizes the status of our restricted stock and RSUs at June 30, 2008 and the changes during the six months then ended:

	Equity Instruments (thousands)		Weighted Average Grant Date Fair Value		Aggregate Intrinsic Value ($ thousands)		Weighted Average Remaining Contractual Life (Years)
Nonvested at January 1, 2008	4,843		$	44.73
Granted	2,176	(1)		52.28
Vested	(774	)		42.55
Forfeited	(26	)		46.62
Nonvested at June 30, 2008	6,219		$	47.63	$	453,800	5.0

⁽¹⁾ The amount granted includes five annual grants of 200,000 RSUs commencing on September 30, 2015. The first three annual grants will each vest in full in 2020, and the fourth and fifth annual grants will each vest ratably over a three-year period from the date of grant. Under the provisions of SFAS 123R, the grant date for accounting purposes for all 1.0 million RSUs to be granted in the future is March 12, 2008.

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As of June 30, 2008, there was $244.9 million of total unrecognized compensation cost related to nonvested RSUs that is expected to be recognized over a period of 5.0 years.

In addition, under the terms of our Long-Term Retention and Deferred Compensation Plan, annual grants may be increased if certain common stock price performance targets are achieved. We estimated the value and number of RSUs expected to be granted in the future by using a Monte-Carlo simulation model. The 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 RSUs expected to be granted based on the results of the simulations. Pursuant to this simulation model, we estimated that 0.4 million RSUs are expected to be granted. Such units had a weighted average grant date fair value of $46.62 per unit, an aggregate fair value of $18.7 million and a weighted average remaining contractual life of 6 years.

Note 7—Fair Value Measurements of Assets and Liabilities

Effective January 1, 2008, we adopted SFAS No. 157 “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. SFAS 157 does not require any new fair value measurements but may require some entities to change their measurement practices. The adoption of SFAS 157 did not have a significant effect on our consolidated financial position, results of operations or cash flows.

As defined in SFAS 157, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (“exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of fair value under SFAS 157 are as follows:

• Level 1 – Quoted, unadjusted prices for assets or liabilities in active markets for identical assets or liabilities as of the reporting date.

• Level 2 – Market-based inputs that are directly or indirectly observable but not considered Level 1 quoted prices, including quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; or valuation techniques whose inputs are observable. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

• Level 3 – Valuation techniques whose significant inputs are unobservable.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement.

We value our derivative instruments, including crude oil put options, crude oil collars and natural gas collars using an option-pricing model. The model uses various inputs including NYMEX price quotations, volatilities, interest rates and time to expiry. We classify our derivatives as Level 2 if the inputs used in the valuation model are directly and indirectly observable as described above; however, if the significant inputs are not observable, we classify those derivatives as Level 3. For our derivatives classified as Level 3, certain inputs which were significant to the overall fair value measurement were not observable for substantially the full term of the instrument. For these inputs we utilize pricing and volatility information from other instruments with similar characteristics. Our crude oil put options that are settled annually and our natural gas collars with an average floor price of $10.00 and average ceiling price of $20.00 are classified as Level 3.

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The following table presents, for each fair value hierarchy level, our assets and liabilities related to continuing operations which are measured at fair value on a recurring basis as of June 30, 2008 (in thousands):

			Fair Value Measurements at Reporting Date Using:
	Total Fair Value at June 30, 2008(1)		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Commodity derivative contracts	$	251,097	$	-	$	1,454	$	249,643
Liabilities:
Commodity derivative contracts		32,397		-		32,397		-

⁽¹⁾ Option premium and interest are not included in the fair value of derivatives.

The following table presents a reconciliation of changes in fair value of financial assets and liabilities classified as Level 3 (in thousands):

	Commodity Derivative Contracts(1)
Balance of Level 3 as of January 1, 2008	$	-
Total unrealized gains and (losses) included in earnings(2)		(21,508	)
Purchases		271,151
Transfers in and out of Level 3		-
Balance of Level 3 as of June 30, 2008	$	249,643
Total unrealized gains and (losses) included in earnings related to financial assets and liabilities still on the Consolidated Balance Sheet as of June 30, 2008(2)	$	(21,508	)

⁽¹⁾      Option premium and interest are not included in the fair value of derivatives.

⁽²⁾         Realized and unrealized gains and losses included in earnings for the period are reported as gain or loss on mark-to-market derivative contracts in our Consolidated Statements of Income.

In November 2007, the FASB agreed to a one-year deferral of SFAS 157 fair value measurement requirements for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis. In February 2008, the FASB issued Financial Staff Position (“FSP”) SFAS 157-2 “Effective date of SFAS 157.” This FSP defers the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 and interim periods within those fiscal years for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We have elected to utilize this deferral and have only partially applied SFAS 157 (to financial assets and liabilities measured at fair value on a recurring basis, as described above). Accordingly, we will apply SFAS 157 to our nonfinancial assets and liabilities, which we disclose or recognize at fair value on a nonrecurring basis, such as asset retirement obligations,goodwill impairment and other assets and liabilities, in the first quarter of 2009.

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We adopted SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of SFAS No. 115” (“SFAS 159”) on January 1, 2008. SFAS 159 permits companies to choose to measure financial instruments and certain other items at fair value that were not previously required to be measured at fair value. We have not elected to present assets and liabilities at fair value that were not required to be measured at fair value prior to the adoption of SFAS 159.

Note 8—Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate plus any significant unusual or infrequently occurring items which are recorded in the period that the specific item occurs. For the three months ended June 30, 2008, income tax expense was approximately 36% of pretax income, and for the six months ended June 30, 2008, income tax expense was approximately 38% of pretax income. Variances in our estimated annual effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes and estimated permanent differences, which include (1) the special deduction for domestic production and (2) expenses that are not deductible because of Internal Revenue Service limitations. Specific items which affected income tax expense for the six months ended June 30, 2008 included state tax rate changes due to recent asset acquisitions and divestitures and changes to our balance of unrecognized tax positions.

We file income tax returns in the U.S. and various state and foreign jurisdictions. With respect to the previously filed PXP, Nuevo Energy Company and 3TEC Energy Corporation tax returns, we are no longer subject to U.S. federal and state income tax examinations by authorities for years before 1996. For the previously filed Pogo tax returns, we are no longer subject to U. S. federal and state income tax examinations for years prior to 2004. The IRS reviewed Pogo’s federal income tax return for 2004 and indicated they do not intend to perform an examination of that return. During the second quarter of 2008, the IRS informed us that they intend to examine Pogo’s federal tax return for 2006.

The IRS is currently examining the PXP and Nuevo federal income tax returns for 2003 and 2004, the fieldwork for which is anticipated to be completed in the third quarter of 2008. As this IRS audit remains ongoing, it is possible that changes will occur to the balance of our unrecognized tax benefits during the next 12 months as the IRS finalizes its examination. The financial impact of these future changes cannot be determined at this time.

At June 30, 2008 we had approximately $43.7 million of gross unrecognized tax benefits. If all unrecognized tax benefits were recognized, approximately $36.8 million would impact our effective tax rate in future periods (including all indirect tax effects in other jurisdictions). Both of these amounts have increased over the corresponding amounts that existed at December 31, 2007 as a result of our ongoing assessment of developments related to the IRS examinations.

Note 9—Commitments and Contingencies

Environmental matters. As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. Often these regulations are more burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have operated for over 90 years. We have established policies for continuing compliance with environmental laws and regulations. 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.

On April 10, 2008, a coalition of California environmental organizations announced the signing of an agreement with us and the coalition’s support of our Tranquillon Ridge Project offshore California. We believe the organizations’ support will improve our chance of receiving a new state oil and gas lease and attendant operating permits. In return for the coalition’s support and upon completion of certain permitting and operational objectives, the agreement provides certain benefits to the communities in Santa Barbara County and to the state of California, including a firm end date prohibiting the extension of our existing oil and gas operations, our donation of 3,900 acres of lands and full mitigation of greenhouse gases from the project if Tranquillon Ridge is permitted and proves to be a commercial success. We also agreed to donate $1.5 million to further reduce greenhouse gas emissions in the county and withdraw permits for the approximately 800 acre Purisima Hills residential project if permitting, which is subject to approval by certain California agencies, is successful. We anticipate the permitting process to take place over the next several months.

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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, $42 million ($81 million undiscounted), is 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 $46 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At June 30, 2008, the escrow account had a balance of $9.6 million. The fair value of our guarantee at June 30, 2008 was $0.3 million and 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.

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 lawsuit Amber 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. On October 31, 2006, the Court issued an unfavorable decision on the plaintiff’s motion for partial summary judgment concerning plaintiffs’ 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. Plaintiffs filed a motion for final judgment on November 29, 2006 and the court granted such motion on January 11, 2007. Judgment on the $1.1 billion was filed January 12, 2007. The United States has filed an appeal and Plaintiffs have filed a cross-appeal concerning the Court’s October 31, 2006 decision. 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 if the plaintiffs are successful.

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.

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Subsequent event. On July 7, 2008, we acquired from Chesapeake a 20% interest in Chesapeake’s Haynesville Shale leasehold as of June 30, 2008, for approximately $1.65 billion in cash, of which we paid $1.375 billion on July 7, 2008 and expect to pay the remainder on or before October 30, 2008, subject to customary post-closing adjustments. In connection with the acquisition we also agreed, over a multi-year period, to fund 50% of Chesapeake’s drilling and completion costs associated with future Haynesville Shale wells, up to an additional $1.65 billion.

Note 10—Consolidating Financial Statements

We are the issuer of $600 million of 7 ³/4% Senior Notes, $500 million of 7% Senior Notes and $400 million of 7 ⁵/8% Senior Notes, which are jointly and severally guaranteed on a full and unconditional basis by certain of our existing domestic subsidiaries (referred to as “Guarantor Subsidiaries”). Certain of our subsidiaries do not guarantee the Senior Notes (referred to as “Non-Guarantor Subsidiaries”).

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

• PXP (the “Issuer”);

• the Guarantor Subsidiaries on a combined basis;

• the Non-Guarantor Subsidiaries on a combined basis;

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

• PXP on a consolidated basis.

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

JUNE 30, 2008

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	105		$	23		$	2,366		$	-		$	2,494
Accounts receivable and other current assets		216,174			402,163			1,438			-			619,775
		216,279			402,186			3,804			-			622,269
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		2,740,587			4,347,283			-			-			7,087,870
Not subject to amortization		241,897			1,124,334			18,380			-			1,384,611
Other property and equipment		41,353			46,395			23,207			-			110,955
		3,023,837			5,518,012			41,587			-			8,583,436
Less allowance for depreciation, depletion and amortization		(621,464	)		(967,334	)		(23	)		321,802			(1,267,019	)
		2,402,373			4,550,678			41,564			321,802			7,316,417
Investment in and Advances to Subsidiaries		4,057,340			603,067			(36,577	)		(4,623,830	)		-
Other Assets		21,301			569,780			47,648			-			638,729
	$	6,697,293		$	6,125,711		$	56,439		$	(4,302,028	)	$	8,577,415
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	296,277		$	281,559		$	960		$	-		$	578,796
Commodity derivative contracts		69,146			32,679			-			-			101,825
		365,423			314,238			960			-			680,621
Long-Term Debt		2,111,000			-			-			-			2,111,000
Other Long-Term Liabilities		184,210			170,343			-			-			354,553
Deferred Income Taxes		611,852			1,268,724			2,262			123,595			2,006,433
Stockholders’ Equity		3,424,808			4,372,406			53,217			(4,425,623	)		3,424,808
	$	6,697,293		$	6,125,711		$	56,439		$	(4,302,028	)	$	8,577,415

18

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2007

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	15,897		$	2,261		$	7,288		$	-		$	25,446
Accounts receivable and other current assets		255,049			385,720			8,705			-			649,474
		270,946			387,981			15,993			-			674,920
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		2,632,802			4,707,436			-			-			7,340,238
Not subject to amortization		174,837			1,761,489			15,457			-			1,951,783
Other property and equipment		57,384			11,903			16,641			-			85,928
		2,865,023			6,480,828			32,098			-			9,377,949
Less allowance for depreciation, depletion and amortization		(529,426	)		(788,164	)		(21	)		316,889			(1,000,722	)
		2,335,597			5,692,664			32,077			316,889			8,377,227
Investment in and Advances to Subsidiaries		5,120,045			(682,139	)		(26,292	)		(4,411,614	)		-
Other Assets		24,504			613,264			3,436			-			641,204
	$	7,751,092		$	6,011,770		$	25,214		$	(4,094,725	)	$	9,693,351
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	322,438		$	404,413		$	11,257		$	-		$	738,108
Commodity derivative contracts		68,580			11,358			-			-			79,938
		391,018			415,771			11,257			-			818,046
Long-Term Debt		3,305,000			-			-			-			3,305,000
Other Long-Term Liabilities		170,401			102,226			-			-			272,627
Deferred Income Taxes		546,426			1,286,567			2,262			124,176			1,959,431
Stockholders’ Equity		3,338,247			4,207,206			11,695			(4,218,901	)		3,338,247
	$	7,751,092		$	6,011,770		$	25,214		$	(4,094,725	)	$	9,693,351

19

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2008

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	393,543		$	152,224		$	-	$	-		$	545,767
Gas sales		14,784			167,550			-		-			182,334
Other operating revenues		296			4,306			-		-			4,602
		408,623			324,080			-		-			732,703
Costs and Expenses
Production costs		106,153			56,998			-		-			163,151
General and administrative		28,465			16,738			-		-			45,203
Depreciation, depletion, amortization and accretion		53,004			82,760			-		(1,792	)		133,972
		187,622			156,496			-		(1,792	)		342,326
Income from Operations		221,001			167,584			-		1,792			390,377
Other Income (Expense)
Equity in earnings of subsidiaries		97,811			733			-		(98,544	)		-
Interest expense		(15,914	)		(8,136	)		-		539			(23,511	)
Loss on mark-to-market derivative contracts		(23,991	)		(27,436	)		-		-			(51,427	)
Interest and other income (expense)		664			827			734		(539	)		1,686
Income (Loss) Before Income Taxes		279,571			133,572			734		(96,752	)		317,125
Income tax benefit (expense)		(76,653	)		(36,906	)		1		(649	)		(114,207	)
Net Income (Loss)	$	202,918		$	96,666		$	735	$	(97,401	)	$	202,918

20

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2007

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	199,998		$	31,585		$	-	$	-		$	231,583
Gas sales		6,894			16,316			-		-			23,210
Other operating revenues		654			100			-		-			754
		207,546			48,001			-		-			255,547
Costs and Expenses
Production costs		76,678			17,120			-		-			93,798
General and administrative		26,009			3,904			-		-			29,913
Depreciation, depletion, amortization and accretion		33,407			27,389			-		-			60,796
		136,094			48,413			-		-			184,507
Income (Loss) from Operations		71,452			(412	)		-		-			71,040
Other Income (Expense)
Equity in earnings of subsidiaries		(10,470	)		-			-		10,470			-
Interest expense		(7,021	)		(10,177	)		-		5,500			(11,698	)
Loss on mark-to-market derivative contracts		(15,837	)		-			-		-			(15,837	)
Interest and other income (expense)		6,202			45			-		(5,500	)		747
Income (Loss) Before Income Taxes		44,326			(10,544	)		-		10,470			44,252
Income tax benefit (expense)		(19,008	)		74			-		-			(18,934	)
Net Income (Loss)	$	25,318		$	(10,470	)	$	-	$	10,470		$	25,318

21

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2008

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	695,792		$	306,559		$	-		$	-		$	1,002,351
Gas sales		19,989			326,414			-			-			346,403
Other operating revenues		939			6,087			-			-			7,026
		716,720			639,060			-			-			1,355,780
Costs and Expenses
Production costs		188,555			127,616			-			-			316,171
General and administrative		51,598			33,533			-			-			85,131
Depreciation, depletion, amortization and accretion		101,480			181,645			-			(4,913	)		278,212
		341,633			342,794			-			(4,913	)		679,514
Income from Operations		375,087			296,266			-			4,913			676,266
Other Income (Expense)
Equity in earnings of subsidiaries		178,899			655			-			(179,554	)		-
Interest expense		(26,947	)		(42,253	)		-			15,080			(54,120	)
Debt extinguishment costs		(10,263	)		-			-			-			(10,263	)
Loss on mark-to-market derivative contracts		(23,557	)		(37,351	)		-			-			(60,908	)
Interest and other income (expense)		15,562			35,179			658			(15,080	)		36,319
Income (Loss) Before Income Taxes		508,781			252,496			658			(174,641	)		587,294
Income tax benefit (expense)		(142,362	)		(78,529	)		(3	)		19			(220,875	)
Net Income (Loss)	$	366,419		$	173,967		$	655		$	(174,622	)	$	366,419

22

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2007

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	380,385		$	56,716		$	-	$	-		$	437,101
Gas sales		14,206			26,539			-		-			40,745
Other operating revenues		2,145			249			-		-			2,394
		396,736			83,504			-		-			480,240
Costs and Expenses
Production costs		148,473			30,557			-		-			179,030
General and administrative		46,202			6,208			-		-			52,410
Depreciation, depletion, amortization and accretion		62,106			53,630			-		-			115,736
Full cost ceiling test writedown		-			55,889					(55,889	)		-
		256,781			146,284			-		(55,889	)		347,176
Income (Loss) from Operations		139,955			(62,780	)		-		55,889			133,064
Other Income (Expense)
Equity in earnings of subsidiaries		(16,563	)		-			-		16,563			-
Interest expense		(7,853	)		(14,705	)		-		5,500			(17,058	)
Loss on mark-to-market derivative contracts		(36,427	)		-			-		-			(36,427	)
Interest and other income (expense)		6,779			45			-		(5,500	)		1,324
Income (Loss) Before Income Taxes		85,891			(77,440	)		-		72,452			80,903
Income tax benefit (expense)		(40,003	)		28,428			-		(23,440	)		(35,015	)
Net Income (Loss)	$	45,888		$	(49,012	)	$	-	$	49,012		$	45,888

23

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2008

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	366,419		$	173,967		$	655		$	(174,622	)	$	366,419
Items not affecting cash flows from operating activities
Gain on sale of assets		-			(34,658	)		-			-			(34,658	)
Depreciation, depletion, amortization and accretion		101,480			181,645			-			(4,913	)		278,212
Equity in earnings of subsidiaries		(178,899	)		(655	)		-			179,554			-
Deferred income taxes		101,506			17,697			-			(581	)		118,622
Debt extinguishment costs		10,263			-			-			-			10,263
Loss on commodity derivative contracts		23,557			37,351			-			-			60,908
Noncash compensation		25,440			15,047			(36	)		-			40,451
Other noncash items		1,499			1,711			(324	)		-			2,886
Change in assets and liabilities from operating activities
Accounts receivable and other assets		12,890			(115,297	)		3,361			-			(99,046	)
Accounts payable and other liabilities		(27,194	)		(48,717	)		(936	)		-			(76,847	)
Stock appreciation rights		(58,357	)		-			-			-			(58,357	)
Income taxes receivable		509			-			-			-			509
Net cash provided by (used in) operating activities		379,113			228,091			2,720			(562	)		609,362
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(160,948	)		(275,111	)		(5,064	)		-			(441,123	)
Acquisition of oil and gas properties		-			(406,137	)		-			-			(406,137	)
Derivative settlements		(29,593	)		-			-			-			(29,593	)
Proceeds from property sales, net of costs and expenses		1,717,781			-			-			-			1,717,781
Decrease in restricted cash		-			59,092			-			-			59,092
Other		(20,200	)		(676	)		(7,796	)		-			(28,672	)
Net cash provided by (used in) investing activities		1,507,040			(622,832	)		(12,860	)		-			871,348
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		4,237,756			-			-			-			4,237,756
Repayments		(5,831,756	)		-			-			-			(5,831,756	)
Proceeds from issuance of long-term debt		400,000			-			-			-			400,000
Derivative settlements		(13,088	)		-			-			-			(13,088	)
Purchase of treasury stock		(304,192	)		-			-			-			(304,192	)
Investment in and advances to affiliates		(398,625	)		392,845			5,218			562			-
Other		7,960			(342	)		-			-			7,618
Net cash provided by (used in) financing activities		(1,901,945	)		392,503			5,218			562			(1,503,662	)
Net increase (decrease) in cash and cash equivalents		(15,792	)		(2,238	)		(4,922	)		-			(22,952	)
Cash and cash equivalents, beginning of period		15,897			2,261			7,288			-			25,446
Cash and cash equivalents, end of period	$	105		$	23		$	2,366		$	-		$	2,494

24

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2007

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	45,888		$	(49,012	)	$	-		$	49,012		$	45,888
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		62,106			109,519			-			(55,889	)		115,736
Equity in earnings of subsidiaries		16,563			-			-			(16,563	)		-
Deferred income taxes		27,451			(15,876	)		-			23,440			35,015
Loss on commodity derivative contracts		36,427			-			-			-			36,427
Noncash compensation		20,468			1,153			-			-			21,621
Other noncash items		14			(45	)		-			-			(31	)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		5,319			(12,867	)		-			-			(7,548	)
Accounts payable and other liabilities		(5,861	)		706			-			-			(5,155	)
Stock appreciation rights		(6,431	)		-			-			-			(6,431	)
Income taxes payable		(94,272	)		-			-			-			(94,272	)
Net cash provided by operating activities		107,672			33,578			-			-			141,250
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(174,379	)		(83,803	)		-			-			(258,182	)
Acquisition of oil and gas properties		(973,875	)		-									(973,875	)
Derivative settlements		(49,143	)		-			-			-			(49,143	)
Other		(21,712	)		(2,433	)		(3,450	)		-			(27,595	)
Net cash used in investing activities		(1,219,109	)		(86,236	)		(3,450	)		-			(1,308,795	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		1,456,250			-			-			-			1,456,250
Repayments		(1,316,750	)		-			-			-			(1,316,750	)
Proceeds for issuance of long-term debt		1,100,000			-			-			-			1,100,000
Cost incurred in connection with financing arrangements		(17,917	)		-			-			-			(17,917	)
Investment in and advances to affiliates		(56,112	)		52,662			3,450			-			-
Purchase of treasury stock		(47,485	)		-			-			-			(47,485	)
Other		3,341			-			-			-			3,341
Net cash provided by financing activities		1,121,327			52,662			3,450			-			1,177,439
Net increase in cash and cash equivalents		9,890			4			-			-��			9,894
Cash and cash equivalents, beginning of period		896			3			-			-			899
Cash and cash equivalents, end of period	$	10,786		$	7		$	-		$	-		$	10,793

25

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, 2007.

Company Overview

We are an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploring and producing oil and gas properties in the United States. Our core areas of operations are:

• the Los Angeles and San Joaquin Basins onshore California;

• the Santa Maria Basin offshore California;

• the Piceance and Wind River Basins in the Rocky Mountains;

• the Haynesville Shale in North Louisiana and East Texas;

• the Permian Basin in West Texas and New Mexico;

• the Anadarko Basin in the Texas Panhandle; and

• the South Texas and Gulf Coast regions, including the Gulf of Mexico.

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 and gas prices above the maximum fixed amount specified in the derivative agreement and subjects us to the credit risk of the counterparties to such agreements. See Item 3 – Quantitative and Qualitative Disclosures About Market Risk.

Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility, and periodic public offerings of debt. See Liquidity and Capital Resources.

Recent Events

Haynesville Shale Acquisition

On July 7, 2008, we acquired from a subsidiary of Chesapeake Energy Corporation (“Chesapeake”), a 20% interest in Chesapeake’s Haynesville Shale leasehold as of June 30, 2008 for approximately $1.65 billion in cash, of which we paid $1.375 billion on July 7, 2008 and expect to pay the remainder on or before October 30, 2008, subject to customary post-closing adjustments. In connection with the acquisition we also agreed, over a multi-year period, to fund 50% of Chesapeake’s drilling and completion costs associated with future Haynesville Shale wells, up to an additional $1.65 billion. In addition, we will have the option to participate for 20% of any additional leasehold that Chesapeake, or its affiliates, acquires in the Haynesville Shale within a designated area of mutual interest. We funded the transaction with borrowings under our senior revolving credit facility. Chesapeake has publicly stated that its estimated Haynesville Shale leasehold as of June 30, 2008 was approximately 550,000 net acres, which will entitle us to approximately 110,000 net acres. There are no material proved reserves associated with the acreage.

Other Acquisitions

On April 17, 2008, we completed the acquisition of oil and gas producing properties in South Texas from a private company. After the exercise of third party preferential rights, we paid $291 million in cash, which included preliminary closing adjustments of approximately $10 million. We funded the acquisition primarily with proceeds from recently completed divestments through the use of a tax deferred like-kind exchange. We estimate that proved reserves were approximately 93 billion cubic feet of natural gas equivalent as of December 31, 2007. The effective date of the transaction is January 1, 2008.

26

On June 27, 2008, PXP and a subsidiary of Occidental Petroleum Corporation (“Oxy”) acquired from a third party working interests in acreage immediately adjacent to our existing Piceance Basin assets. PXP and Oxy, a 50% owner in our Piceance Basin assets, have agreed to pay a total of $158.6 million for a 95% working interest comprising approximately 11,500 net acres. We will operate these properties, which include over 800 potential future drilling locations. Under the terms of the agreement, we paid approximately $20.3 million on June 27, 2008, with the remaining balance payable in equal amounts of approximately $20.3 million on July 1, 2009 and July 1, 2010 and approximately $18.5 million on July 1, 2011.

Divestments

On February 29, 2008, we closed the sale of certain oil and gas properties to a subsidiary of Oxy and certain other companies with contractual preferential rights to purchase, with an effective date of January 1, 2008, and received approximately $1.53 billion in cash proceeds. We sold 50% of our working interests in oil and gas properties located in the Permian Basin, West Texas and New Mexico. We retained 50% of our working interest in these properties, and Oxy will be the operator of all the assets previously operated by us. We acquired the above referenced properties in the Pogo acquisition on November 6, 2007, and the property revenues and expenses were included in our historical consolidated statement of income beginning on that date through the closing date of the sale. We also sold 50% of our working interests in oil and gas properties located in the Piceance Basin in Colorado, including a 50% interest in the entity that holds our interest in Collbran Valley Gas Gathering LLC (“CVGG”), and we retained 50% of our working interest in these oil and gas properties. We will remain the operator of these properties. We acquired these properties on May 31, 2007, and the property revenues and expenses were included in our historical consolidated statement of income beginning on that date through the closing date of the sale. We recorded a $34.7 million pretax gain on the sale of the 50% interest in the entity that holds our interest in CVGG.

On February 15, 2008, we closed the sale to XTO Energy Inc. (“XTO”) of our interests in certain oil and gas properties located in the San Juan Basin in New Mexico and in the Barnett Shale in Texas. This transaction had an effective date of January 1, 2008, and we received $199.0 million in cash proceeds. On February 29, 2008 we completed the acquisition of XTO’s 50% working interest in the Big Mac prospect located on the Texas Gulf Coast for approximately $20.2 million.

Our aggregate working interest in the properties sold in February 2008 generated total sales volumes of approximately 11 thousand barrels of oil equivalent per day (“MBOEPD”) during the first quarter of 2008 and had 105 million barrels of oil equivalent (“BOE”) of estimated proved reserves as of December 31, 2007.

General

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, 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.” 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 (including stock based compensation), 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 purposes of computing depletion, estimated proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary.

27

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

Results Overview

In the first half of 2008, we reported net income of $366.4 million, or $3.27 per diluted share compared to net income of $45.9 million, or $0.63 per diluted share in the first half of 2007.

On May 31, 2007, we acquired interests in oil and gas producing properties in the Piceance Basin in Colorado, plus associated midstream assets, and on November 6, 2007, we acquired Pogo Producing Company, or Pogo, which was engaged in oil and gas exploration, development, acquisition and production activities primarily located in the onshore United States.

Results of Operations

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
Sales Volumes
Oil and liquids sales (MBbls)		5,019		4,264		10,265		8,526
Gas (MMcf)
Production		18,232		4,212		39,598		7,267
Used as fuel		547		584		1,135		1,163
Sales		17,685		3,628		38,463		6,104
MBOE
Production		8,057		4,966		16,864		9,737
Sales		7,966		4,870		16,675		9,544
Daily Average Volumes
Oil and liquids sales (Bbls)		55,153		46,865		56,399		47,106
Gas (Mcf)
Production		200,358		46,285		217,573		40,148
Used as fuel		6,015		6,415		6,236		6,423
Sales		194,343		39,870		211,337		33,725
BOE
Production		88,546		54,579		92,662		53,798
Sales		87,543		53,510		91,622		52,727
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	123.80	$	65.02	$	111.12	$	61.67
Gas		10.90		7.55		9.50		7.17
Average Realized Sales Price Before
Derivative Transactions
Oil (per Bbl)	$	108.74	$	54.31	$	97.65	$	51.27
Gas (per Mcf)		10.31		6.40		9.01		6.68
Per BOE		91.40		52.32		80.89		50.07
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	10.70	$	10.29	$	9.58	$	9.93
Steam gas costs		5.10		5.73		4.36		5.69
Electricity		1.34		1.95		1.34		1.91
Production and ad valorem taxes		3.04		1.04		3.02		1.08
Gathering and transportation		0.31		0.25		0.66		0.15
Depreciation, depletion and amortization of oil and gas properties (“DD&A”)		15.70		11.35		15.73		11.01

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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,
	2008			2007			2008			2007
Mark-to-market contracts
Crude oil put options and collars	$	(20,844	)	$	(25,615	)	$	(43,108	)	$	(49,143	)
Natural gas collars		-			-			427			-

Comparison of Three Months Ended June 30, 2008 to Three Months Ended June 30, 2007

Oil and gas revenues. Oil and gas revenues increased $473.3 million, to $728.1 million for 2008 from $254.8 million for 2007 due to increased volumes primarily as a result of the Pogo acquisition, which closed in November 2007, and an increase in realized prices of $39.08 per BOE.

Oil revenues increased $314.2 million to $545.8 million for 2008 from $231.6 million for 2007 reflecting higher realized prices ($232.1 million) and higher sales volumes ($82.1 million). Our average realized price for oil increased $54.43 to $108.74 per Bbl for 2008 from $54.31 per Bbl for 2007. Approximately 92% of the revenue increase attributable to prices is due to an improvement in the NYMEX oil price, which averaged $123.80 per Bbl in 2008 versus $65.02 per Bbl in 2007, and the remainder is due to an improved differential to NYMEX as a result of an increase in the percentage of the NYMEX index price we receive on a portion of our heavy crude oil sold under a contract in California. Oil sales volumes increased 8.3 MBbls per day to 55.2 MBbls per day in 2008 from 46.9 MBbls per day in 2007, primarily reflecting production from the properties acquired in the Pogo acquisition, which had sales of 9.1 MBbls per day in the second quarter of 2008.

Gas revenues increased $159.1 million to $182.3 million in 2008 from $23.2 million in 2007 due to increased sales volumes ($144.9 million) and an increase in realized prices ($14.2 million). Our average realized price for gas was $10.31 per Mcf in 2008 compared to $6.40 per Mcf in 2007. Approximately 86% of the gas revenue increase attributable to prices is due to an improvement in the NYMEX gas price, which averaged $10.90 per Mcf in 2008 versus $7.55 per Mcf in 2007, and the remainder is due to an improvement in our average differential to NYMEX, which averaged $1.15 per Mcf in the second quarter of 2007 versus $0.59 in the second quarter of 2008. Gas sales volumes increased from 39.9 MMcf per day in 2007 to 194.3 MMcf per day in 2008, primarily reflecting production from the properties acquired in the Pogo acquisition in November 2007, which had sales of 141.2 MMcf per day in the second quarter of 2008, and increased production from the Piceance Basin properties. Production from the Piceance Basin properties increased 155% to 27.5 MMcf per day in the second quarter of 2008 compared to 10.8 MMcf per day in the second quarter of 2007.

Lease operating expenses. Lease operating expenses increased $35.1 million, to $85.2 million in 2008 from $50.1 million in 2007. Lease operating expenses for 2008 includes $23.1 million attributable to the Pogo and Piceance Basin properties acquired in November and May of 2007, respectively. Lease operating expense for the second quarter of 2007 includes $0.6 million of Piceance Basin costs. Excluding these incremental costs, lease operating expenses increased $12.6 million due primarily to increased charges for stock appreciation rights ($6.4 million) as a result of an increase in the price of our common stock and repairs and maintenance expense and workover expense ($4.0 million). On a per unit basis, lease operating expenses increased to $10.70 per BOE in 2008 versus $10.29 per BOE in 2007 due to increased costs.

Steam gas costs. Steam gas costs increased $12.7 million, to $40.6 million in 2008 from $27.9 million in 2007, primarily reflecting the higher cost of gas used in steam generation. In 2008, we burned approximately 4.2 billion cubic feet (“Bcf”) of natural gas at a cost of approximately $9.70 per Mcf compared to 4.3 Bcf at a cost of approximately $6.53 per Mcf in 2007.

Electricity. Electricity increased $1.2 million, to $10.7 million in 2008 from $9.5 million in 2007, primarily reflecting rate increases from providers. On a per unit basis, electricity decreased to $1.34 per BOE in 2008 versus $1.95 per BOE in 2007 due to increased sales volume.

Production and ad valorem taxes. Production and ad valorem taxes increased $19.2 million, to $24.2 million in 2008 from $5.0 million in 2007, primarily reflecting increased volumes from the Pogo and Piceance Basin acquisitions ($18.1 million).

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Gathering and transportation expenses. Gathering and transportation expenses increased $1.3 million, to $2.5 million in 2008 from $1.2 million in 2007, primarily reflecting increased volumes from the Piceance Basin properties.

General and administrative expense. G&A expense increased $15.3 million, to $45.2 million in 2008 compared to $29.9 million in 2007. The increase, net of capitalization, is due to increased personnel costs primarily as a result of the Pogo and Piceance Basin acquisitions (approximately $7.1 million), stock based compensation (approximately $11.8 million) and transition and other expenses related to the Pogo acquisition (approximately $0.8 million). These expenses were partially offset by an increase in capitalized G&A related to our acquisition, exploration and development activities. We capitalized $19.9 million and $10.2 million of G&A costs in 2008 and 2007, respectively. The increase in capitalized G&A is attributable to increased acquisition, exploration and development activities.

Depreciation, depletion and amortization. DD&A expense increased $72.2 million, to $130.7 million in 2008 from $58.5 million in 2007. The increase was attributable to our oil and gas DD&A, primarily due to increased production ($48.6 million) and a higher per unit rate ($21.6 million). Our oil and gas unit of production rate increased to $15.70 per BOE in 2008 compared to $11.35 per BOE in 2007. The increase primarily reflects the acquisition of the Pogo and Piceance Basin properties.

Accretion expense. Accretion expense increased $0.9 million, to $3.2 million in 2008 from $2.3 million in 2007. Accretion expense for 2008 included $0.8 million attributable to an increase in our asset retirement obligation associated with the Pogo and Piceance Basin properties acquired in November and May of 2007, respectively.

Interest expense. Interest expense increased $11.8 million, to $23.5 million in 2008 from $11.7 million in 2007 due to higher outstanding debt associated with the Pogo and Piceance Basin acquisitions. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization or other assets being prepared for use. We capitalized $12.0 million and $5.0 million of interest in 2008 and 2007, respectively. The increase in capitalized interest is due to a higher unevaluated property balance associated with the Pogo and Piceance Basin acquisitions.

Loss on mark-to-market derivative contracts. We do not currently use hedge accounting for our derivative instruments. Consequently, our 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 a payment to or receiving a payment from the counterparty.

In 2008, we recognized a $51.4 million loss related to mark-to-market derivative contracts and cash payments related to contracts that settled totaled $20.8 million. In 2007, we recognized a $15.8 million loss related to mark-to-market derivative contracts and cash payments related to contracts that settled totaled $25.6 million. The increase in the loss related to mark-to-market derivative contracts is primarily due to (i) additional contracts entered into during the second quarter of 2008 (See Item 3 – Quantitative and Qualitative Disclosures About Market Risk) and (ii) price increases in oil and natural gas.

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 plus any significant, unusual or infrequently occurring items that are recorded in the period that the specific item occurs. As pretax book income changes in future quarters, our effective tax rate may increase or decrease. Variances in our estimated annual effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes and estimated permanent differences, which include (1) the special deduction for domestic production and (2) expenses that are not deductible because of Internal Revenue Service limitations.

For the second quarter of 2008, income tax expense was approximately 36% of pretax income. Specific items affecting income tax expense for the second quarter included state tax rate changes due to recent asset acquisitions and divestitures plus changes to our balance of unrecognized tax positions. For the second quarter 2007, income tax expense was approximately 43% of pretax income.

Comparison of Six Months Ended June 30, 2008 to Six Months Ended June 30, 2007

Oil and gas revenues. Oil and gas revenues increased $870.9 million, to $1.3 billion for 2008 from $477.8 million for 2007, primarily due to increased volumes as a result of the Pogo acquisition and an increase in realized prices of $30.82 per BOE.

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Oil revenues increased $565.2 million to $1.0 billion for 2008 from $437.1 million for 2007 reflecting higher realized prices ($395.4 million) and higher sales volumes ($169.8 million). Our average realized price for oil increased $46.38 to $97.65 per Bbl for 2008 from $51.27 per Bbl for 2007. Approximately 93% of the revenue increase attributable to price is due to an improvement in the NYMEX oil price, which averaged $111.12 per Bbl in 2008 versus $61.67 per Bbl in 2007, and the remainder is due to an improved differential to NYMEX as a result of an increase in the percentage of the NYMEX index price we receive on a portion of our heavy crude oil sold under a contract in California. Oil sales volumes increased 9.3 MBbls per day to 56.4 MBbls per day in 2008 from 47.1 MBbls per day in 2007, primarily reflecting production from the properties acquired in the Pogo acquisition, which had sales of 10.8 MBbls per day in 2008.

Gas revenues increased $305.7 million to $346.4 million in 2008 from $40.7 million in 2007 due to increased sales volumes ($291.4 million) and an increase in realized prices ($14.2 million). Our average realized price for gas was $9.01 per Mcf in 2008 compared to $6.68 per Mcf in 2007. Gas sales volumes increased from 33.7 MMcf per day in 2007 to 211.3 MMcf per day in 2008 primarily reflecting production from the properties acquired in the Pogo acquisition, which had sales of 149.5 MMcf per day in 2008, and increased production from the Piceance Basin properties. Production from the Piceance Basin properties increased 542%to 34.7 MMcf per day for the first half of 2008 compared to 5.4 MMcf per day in the same period of 2007.

Lease operating expenses. Lease operating expenses increased $65.0 million, to $159.8 million in 2008 from $94.8 million in 2007. Lease operating expenses for 2008 includes $47.4 million attributable to the Pogo and Piceance Basin properties acquired in November and May of 2007, respectively. Lease operating expense for 2007 includes $0.6 million of Piceance Basin costs. Excluding these incremental costs, lease operating expenses increased $16.8 million due primarily to increased charges for stock appreciation rights ($6.5 million) as a result of the increased price of our common stock and repairs and maintenance and workover expense ($7.8 million). On a per unit basis, lease operating expenses decreased to $9.58 per BOE in 2008 versus $9.93 per BOE in 2007 due to the increased sales volumes.

Steam gas costs. Steam gas costs increased $18.5 million, to $72.8 million in 2008 from $54.3 million in 2007, primarily reflecting the higher cost of gas used in steam generation. In 2008, we burned approximately 8.4 Bcf of natural gas at a cost of approximately $8.70 per Mcf compared to 8.4 Bcf at a cost of $6.44 per Mcf in 2007.

Electricity. Electricity increased $4.0 million, to $22.3 million in 2008 from $18.3 million in 2007, primarily reflecting the Pogo acquisition ($2.2 million) and increased rates. On a per unit basis, electricity decreased to $1.34 per BOE in 2008 versus $1.91 per BOE in 2007 due to increased sales volumes.

Production and ad valorem taxes. Production and ad valorem taxes increased $40.1 million, to $50.4 million in 2008 from $10.3 million in 2007, primarily reflecting increased volumes from the Pogo and Piceance Basin acquisitions ($38.2 million).

Gathering and transportation expenses. Gathering and transportation expenses increased $9.6 million, to $11.0 million in 2008 from $1.4 million in 2007, primarily reflecting increased volumes from the Pogo and Piceance Basin acquisitions.

General and administrative expense. G&A expense increased $32.7 million to $85.1 million in 2008 compared to $52.4 million in 2007. The increase, net of capitalization, is due to increased personnel costs primarily as a result of the Pogo and Piceance Basin acquisitions (approximately $14.3 million), stock based compensation (approximately $19.3 million) and transition and other expenses related to the Pogo acquisition (approximately $5.3 million). These expenses were partially offset by an increase in capitalized G&A related to our acquisition, exploration and development activities. We capitalized $34.1 million and $18.5 million of G&A costs in 2008 and 2007, respectively. The increase in capitalized G&A is attributable to increased acquisition, exploration and development activities.

Depreciation, depletion and amortization. DD&A expense increased $160.4 million, to $271.6 million in 2008 from $111.2 million in 2007. The increase was attributable to our oil and gas DD&A, primarily due to increased production ($112.1 million) and a higher per unit rate ($46.0 million). Our oil and gas unit of production rate increased to $15.73 per BOE in 2008 compared to $11.01 per BOE in 2007. The increase primarily reflects the acquisition of the Pogo and Piceance Basin properties.

Accretion expense. Accretion expense increased $2.1 million, to $6.6 million in 2008 from $4.5 million in 2007. Accretion expense for 2008 included $1.8 million attributable to an increase in our asset retirement obligation associated with the Pogo and Piceance Basin properties acquired in November and May of 2007, respectively.

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Gain on sale of assets. In February 2008, we completed the sale to Oxy of 50% of the entity which holds our investment in CVGG and recorded a gain on the sale of $34.7 million.

Interest expense. Interest expense increased $37.0 million, to $54.1 million in 2008 from $17.1 million in 2007 due to higher outstanding debt associated with the Pogo and Piceance Basin acquisitions. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization and other assets being prepared for use. We capitalized $29.7 million and $7.1 million of interest in 2008 and 2007, respectively. The increase in capitalized interest is due to a higher unevaluated property balance associated with the Pogo and Piceance Basin acquisitions.

Debt extinguishment costs.In connection with a reduction of the borrowing base on our senior revolving credit facility in February 2008, we recorded $10.3 million of debt extinguishment costs.

Loss on mark-to-market derivative contracts. We do not currently use hedge accounting for our derivative instruments. Consequently, our 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 a payment to or receiving a payment from the counterparty.

In 2008, we recognized a $60.9 million loss related to mark-to-market derivative contracts and cash payments related to contracts that settled totaled $42.7 million. In 2007, we recognized a $36.4 million loss related to mark-to-market derivative contracts and cash payments related to contracts that settled totaled $49.1 million. The increase in the loss related to mark-to-market derivative contracts is primarily due to (i) additional contracts entered into during the second quarter of 2008 (See Item 3 – Quantitative and Qualitative Disclosures About Market Risk) and (ii) price increases in oil and natural gas.

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 plus any significant, unusual or infrequently occurring items that are recorded in the period that the specific item occurs. As pretax book income changes in future quarters, our effective tax rate may increase or decrease. Variances in our estimated annual effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes and estimated permanent differences, which include (1) the special deduction for domestic production and (2) expenses that are not deductible because of Internal Revenue Service limitations.

For the six months ended June 30, 2008 income tax expense was approximately 38% of pretax income. Specific items affecting income tax expense for the six months ended June 30, 2008 included state tax rate changes due to recent asset acquisitions and divestitures plus changes to our balance of unrecognized tax positions. For the six months ended June 30, 2007, income tax expense was approximately 43% of pretax income.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operations and our senior revolving credit facility, and periodic public offerings of debt. At June 30, 2008, we had approximately $1.3 billion available under our senior revolving credit facility, which had aggregate commitments of $1.9 billion. In connection with the Chesapeake transaction, we increased the aggregate commitments and entered into an amendment to our senior revolving credit facility that increased the commitments to $2.7 billion. On July 7, 2008, we borrowed $1.375 billion under our senior revolving credit facility to fund the Chesapeake transaction.

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, commitments and contingencies and anticipated capital expenditures. In addition, our discretionary capital expenditures could be curtailed if our cash flows declined from expected levels. We have no current debt maturities and our senior revolving credit facility matures on November 6, 2012.

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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 natural gas prices above the maximum fixed amount specified in the derivative agreement and subjects us to the credit risk of the counterparties to such agreements. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. Our ability to raise capital is dependent on the current state of the financial markets, which are subject to general economic and industry conditions. Therefore, the availability of and cost of capital in the financial markets could negatively affect our liquidity position.

Working Capital

At June 30, 2008, we had a working capital deficit of approximately $58.4 million. Our working capital deficit is affected by fluctuations in the fair value of our commodity derivative instruments and SARs. At June 30, 2008, we had net short-term liabilities of $68.2 million and $15.3 million for derivatives and SARs, respectively. Excluding these items our working capital was approximately $25.1 million. We generally have a working capital deficit or a minimal working capital balance because we use excess cash to pay down borrowings under our senior revolving credit facility.

Financing Activities

7 ⁵/8% Senior Notes. In May 2008, we issued $400 million of 7 ⁵/8% Senior Notes due 2018 (the “7 ⁵/8% Senior Notes”) at par. The net proceeds were used to repay borrowings under our senior revolving credit facility. We may redeem all or part of the 7 ⁵/8% Senior Notes on or after June 1, 2013 at specified redemption prices and prior to that date at a “make-whole” redemption price. In addition, prior to June 1, 2011 we may, at our option, redeem up to 35% of the 7 ⁵/8% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 7 ⁵/8% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 7 ³/4% Senior Notes due 2015, the 7% Senior Notes due 2017 and the 7 ⁵/8% Senior Notes (together, “the Senior Notes”) are our general unsecured, senior obligations. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. The Senior Notes rank senior in right of payment to all of our existing and future subordinated indebtedness;pari passu in right of payment with any of our existing and future unsecured indebtedness that is not by its terms subordinated to the Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility, to the extent of our assets constituting collateral securing that indebtedness; and effectively subordinate to all existing and future indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our non-guarantor subsidiaries.

The indenture governing the Senior Notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional debt; make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock; sell assets, including capital stock of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries; create liens that secure debt; enter into transactions with affiliates; and merge or consolidate with another company.

Amended Credit Agreement.On February 13, 2008, we entered into an amendment to our senior revolving credit facility. The amendment reduced the borrowing base and commitments to $2.5 billion and $1.9 billion, respectively, from $2.9 billion upon the closing of the sale of certain properties to XTO and Oxy. In addition, the amendment allows us to repurchase up to $1.0 billion of our common stock subject to certain conditions being met. The effective interest rate on our borrowings under the senior revolving credit facility was 3.82% at June 30, 2008. Further, the borrowing base was reduced again upon the May 2008 closing of the 7 ⁵/8% Senior Notes, from $2.5 billion to approximately $2.4 billion.

In connection with the Chesapeake transaction, we increased the aggregate commitments and entered into an amendment to our senior revolving credit facility. On July 2, 2008, the aggregate commitments of the lenders under our senior revolving credit facility were increased by $400 million to $2.3 billion from $1.9 billion. In addition, on July 23, 2008, we entered into an amendment to our senior revolving credit facility to increase the borrowing base to $3.1 billion from approximately $2.4 billion and further increase the commitments to $2.7 billion from $2.3 billion.

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The senior revolving credit facility, as amended, contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into take-or-pay or other prepayment arrangements, merge or consolidate and enter into transactions with affiliates. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined) of no greater than 4.25 to 1.

Short-term Credit Facility. We have an uncommitted short-term unsecured credit facility under the terms of which we may make borrowings from time to time until June 1, 2009, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding fourteen days and all amounts outstanding are due and payable no later than June 1, 2009. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and PXP.

Cash Flows

	Six Months Ended June 30,
	2008			2007
	(in millions)
Cash provided by (used in):
Operating activities	$	609.4		$	141.3
Investing activities		871.3			(1,308.8	)
Financing activities		(1,503.7	)		1,177.4

Net cash provided by operating activities was $609.4 million in 2008 compared to $141.3 million in 2007. The increase in net cash provided by operating activities in 2008 reflects higher operating income primarily related to the Pogo acquisition and higher commodity prices, partially offset by interest expense. As discussed below, certain of our derivative cash payments are classified as financing or investing activities.

Net cash provided by investing activities of $871.3 million in 2008 primarily reflects net proceeds from property sales of $1.7 billion and reduction in restricted cash of $59.1 million, partially offset by additions to oil and gas properties of $847.3 million, additions to other property and equipment of $27.4 million and derivative settlements of $29.6 million. Net cash used in investing activities of $1.3 billion in 2007 primarily reflects the purchase of the Piceance Basin properties of $973.9 million, additions to oil and gas properties of $258.2 million and derivative settlements of $49.1 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 of $1.5 billion in 2008 primarily reflects the $1.6 billion net reduction in borrowings under our senior revolving credit facility and $304.2 million for treasury stock purchases, partially offset by $400 million from the issuance of the 7 ⁵/8% Senior Notes. Net cash provided by financing activities in 2007 of $1.2 billion, primarily reflects $1.2 billion in net borrowings, including $1.1 billion from the issuance of the 7% and 7 ³/4% Senior Notes, partially offset by $47.5 million for treasury stock purchases. In 2008, 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 $1.0 billion 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. During the six months ended June 30, 2008, we repurchased approximately 5.8 million common shares at a cost of approximately $304.2 million. We may expend an additional $695.8 million under the program.

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Commitments and Contingencies

On July 7, 2008, we acquired from Chesapeake a 20% interest in Chesapeake’s Haynesville Shale leasehold as of June 30, 2008, for approximately $1.65 billion in cash, of which we paid $1.375 billion on July 7, 2008 and expect to pay the remainder on or before October 30, 2008, subject to customary post-closing adjustments. In connection with the acquisition we also agreed, over a multi-year period, to fund 50% of Chesapeake’s drilling and completion costs associated with future Haynesville Shale wells, up to an additional $1.65 billion.

On June 27, 2008, PXP and a subsidiary of Oxy acquired from a third party working interests in acreage immediately adjacent to our existing Piceance Basin assets. PXP and Oxy, a 50% owner in our Piceance Basin assets, have agreed to pay an aggregate of $158.6 million for a 95% working interest comprising approximately 11,500 net acres. Under the terms of the agreement, we paid approximately $20.3 million on June 27, 2008, with the remaining balance payable in equal amounts of approximately $20.3 million on July 1, 2009 and July 1, 2010 and approximately $18.5 million on July 1, 2011. The $59.0 million of unpaid consideration is included in Other Long-Term Liabilities on our Consolidated Balance Sheet at June 30, 2008.

Critical Accounting Policies and Factors that May Affect Future Results

We adopted SFAS 157 and SFAS 159 effective January 1, 2008, each of which address the fair value measurement of assets and liabilities. We have elected to partially adopt SFAS 157 as provided by FSP SFAS 157-2, which deferred the effective date of SFAS 157 for nonfinancial assets and liabilities that are recognized and disclosed at fair value in the financial statements on a nonrecurring basis. We have provided additional disclosure concerning our crude oil and natural gas derivative contracts (See Note 7—Fair Value Measurements of Assets and Liabilities). Pursuant to SFAS 157, we have revised our fair value calculation to consider our credit rating and the credit rating of our counterparties.

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, future development and abandonment costs, DD&A, stock based compensation and goodwill are discussed in our Annual Report on Form 10-K for the year ended December 31, 2007.

Recent Accounting Pronouncements

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires companies with noncontrolling interests to disclose such interests clearly as a portion of equity but separate from the parent’s equity. The noncontrolling interest’s portion of net income must also be clearly presented on the income statement. SFAS 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and we do not expect this pronouncement to have a significant impact on our consolidated financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”). SFAS 141R broadens the guidance of SFAS 141, extending its applicability to all transactions and other events in which one entity obtains control over one or more other businesses. It broadens the fair value measurement and recognition of assets acquired, liabilities assumed, and interests transferred as a result of business combinations and requires that acquisition related costs incurred prior to the acquisition be expensed. SFAS 141R expands on the required disclosures to improve the financial statement users’ ability to evaluate the nature and financial effects of business combinations. SFAS 141R is effective for business combinations for which the acquisition date is on or after January 1, 2009, except for certain income tax effects of prior acquisitions for which SFAS 141R is now effective. We are currently evaluating the potential impact of this statement.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 is effective for fiscal years beginning after November 15, 2008, with early application encouraged. We do not expect this pronouncement to have a significant impact on our consolidated financial position, results of operations or cash flows.

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In May 2008, the FASB issued SFAS No. 162 “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. SFAS 162 is effective sixty days following the SEC’s approval of Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of ‘Present Fairly’ in Conformity With Generally Accepted Accounting Principles.” We do not expect this pronouncement to have a significant impact on our consolidated financial position, results of operations or cash flows.

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

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

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

• the effects of competition;

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

• the availability (or lack thereof) of capital to fund our business strategy and/or operations;

• 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, 2007 for additional discussions of risks and uncertainties.

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Item 3 – Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our primary market risk is oil and gas commodity prices. Historically the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized currently in our income statement as 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. We do not currently use hedge accounting for our derivative instruments.

See Note 5 to the Consolidated Financial Statements – Derivative Instruments for a discussion of our derivative activities.

During June 2008, we entered into crude oil put option contracts on 40,000 barrels of oil per day in 2009 and 2010. The 2009 put options have an average strike price of $106.16 per barrel and an average deferred premium plus interest of $6.19 per barrel and the 2010 put options have an average strike price of $111.49 per barrel and an average deferred premium plus interest of $12.08 per barrel. The put options for 2009 and 2010 are settled annually on a calendar year average price. We also acquired natural gas collars with an average floor price of $10.00 per million British thermal units (“MMBtu”) and an average ceiling price of $20.00 per MMBtu on 150,000 MMBtu per day for the months of July 2008 through December 2009. The average deferred premium plus interest is $0.346 per MMBtu and is settled monthly.

At June 30, 2008, we 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
2008
July - Dec	Put options	42,000 Bbls	$55.00 Strike price	WTI
July - Dec	Collar	2,500 Bbls	$60.00 Floor -$80.13 Ceiling	WTI
2009
Jan - Dec	Put options	32,500 Bbls	$55.00 Strike price	WTI
Jan - Dec	Put options	40,000 Bbls	$106.16 Strike price	WTI
2010
Jan - Dec	Put options	40,000 Bbls	$111.49 Strike price	WTI
Sales of Natural Gas Production
2008
July - Dec	Collar	15,000 MMBtu	$8.00 Floor - $12.11 Ceiling	Henry Hub
July - Dec	Collar	150,000 MMBtu	$10.00 Floor - $20.00 Ceiling	Henry Hub
2009
Jan - Dec	Collar	150,000 MMBtu	$10.00 Floor - $20.00 Ceiling	Henry Hub

The only cash settlements we are required to make on the purchased put options are option premiums and interest. Commodity derivative liabilities at June 30, 2008 include deferred premiums and associated accrued interest of (i) approximately $28.9 million for the last six months of 2008, which will be paid ratably each month, (ii) approximately $38.2 million which will be paid ratably each month and approximately $84.4 million which will be paid at the end of the annual period for 2009 and (iii) approximately $159.7 million for 2010, which will be paid at the end of the annual period.

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For a collar contract, (i) we are required to pay cash settlements to the counterparty if the settlement price for any settlement period is above the ceiling price, (ii) the counterparty is required to pay cash settlements to us if the settlement price for any settlement period is below the floor price and (iii) neither party is required to pay cash settlements to the other party if the settlement price for any settlement period is equal to or between the floor and ceiling price. We are required to pay premiums and interest for the natural gas collars with daily volumes of 150,000 MMBtu per day. Commodity derivative liabilities at June 30, 2008 include deferred premiums and associated accrued interest of approximately $9.4 million for the last six months of 2008 and approximately $18.5 million for 2009. These payments will be made on the monthly settlement dates.

The fair value of outstanding crude oil and natural gas commodity derivative instruments at June 30, 2008 and the change in fair value that would be expected from a 10% price increase or decrease is shown below (in millions). The fair value does not include the deferred premiums on the purchased put options and natural gas collars.

				Effect of 10%
	Fair Value Asset (Liability)			Price Increase			Price Decrease
Put options	$	230.6		$	(65.5	)	$	91.8
Crude oil collars		(27.6	)		(6.3	)		6.3
Natural gas collars		15.7			(27.7	)		28.9
	$	218.7		$	(99.5	)	$	127.0

We estimate the fair values of our derivatives using an option-pricing model. The option-pricing model utilizes various factors including NYMEX price quotations, volatilities and the time value of options. 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 or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price.

The ten financial institutions that are contract counterparties for our derivative commodity contracts all have Standard & Poor’s ratings of A+ or better and all but one of the financial institutions are participating lenders in our senior revolving credit facility. At June 30, 2008, we were in a net derivative liability position with all of the 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 revenue 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, 2008 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, 2008 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 2 – Unregistered Sales of Equity Securities and Use of Proceeds

On December 17, 2007, we announced that our Board of Directors had authorized the repurchase of up to $1.0 billion of PXP common stock. The shares are repurchased from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. The following is a summary of our repurchases of common stock during the three-month period ended June 30, 2008 under this plan:

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 1 to April 30, 2008	610,000	$	53.07	5,770,858	$	695,936,000

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

The following items were presented for approval to stockholders of record on March 21, 2008 at the Company’s 2008 annual meeting of stockholders, held on May 8, 2008 in Houston, Texas:

		For	Against	Abstained or Withheld
(i)	Election of Directors
	James C. Flores	96,399,250	-	3,081,851
	Isaac Arnold, Jr.	96,513,115	-	2,967,986
	Alan R. Buckwalter, III	96,553,680	-	2,927,421
	Jerry L. Dees	84,332,455	-	15,148,646
	Tom H. Delimitros	84,341,117	-	15,139,984
	Thomas A. Fry, III	96,550,676	-	2,930,425
	Robert L. Gerry, III	96,548,437	-	2,932,664
	Charles G. Groat	96,542,886	-	2,938,215
	John H. Lollar	84,185,943	-	15,295,158
(ii)	Ratification of PricewaterhouseCoopers LLP, independent certified public accountants, as auditors of the Company’s financial statements for the fiscal year ending December 31, 2008	99,385,341	53,774	41,985

Of the 109,897,282 shares of common stock issued and outstanding on March 21, 2008, the record date for the Company’s 2008 annual meeting of stockholders, 99,481,101 were present, either in person or by proxy.

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ITEM 6 – Exhibits

1.1 Underwriting Agreement, dated May 20, 2008, by and among Plains Exploration & Production Company, the guarantors parties thereto, J.P. Morgan Securities Inc. and the underwriters parties thereto (incorporated by reference to Exhibit 1.1 to the May 23, 2008 Form 8-K (the “May 23, 2008 Form 8-K”)).

4.1 Seventh Supplemental Indenture, dated May 23, 2008, to Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the subsidiary guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (including form of 7⁵/₈% Senior Notes due 2018) (incorporated by reference to Exhibit 4.1 to the May 23, 2008 Form 8-K).

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, 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 5, 2008
	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
1.1	Underwriting Agreement, dated May 20, 2008, by and among Plains Exploration & Production Company, the guarantors parties thereto, J.P. Morgan Securities Inc. and the underwriters parties thereto (incorporated by reference to Exhibit 1.1 to the May 23, 2008 Form 8-K (the “May 23, 2008 Form 8-K”)).
4.1	Seventh Supplemental Indenture, dated May 23, 2008, to Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the subsidiary guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (including form of 75/8% Senior Notes due 2018) (incorporated by reference to Exhibit 4.1 to the May 23, 2008 Form 8-K).
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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