Plains Exploration & Production 10-Q 2007 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, 2007

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-31470

PLAINS EXPLORATION & PRODUCTION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	33-0430755
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

700 Milam Street, Suite 3100

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 579-6000

(Registrant’s telephone number, including area code)

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

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

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

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

72.8 million shares of Common Stock, $0.01 par value, issued and outstanding at July 31, 2007.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION
ITEM 1. Unaudited Condensed Consolidated Financial Statements:
Condensed Consolidated Balance Sheets June 30, 2007 and December 31, 2006	1
Condensed Consolidated Statements of Income For the three months and six months ended June 30, 2007 and 2006	2
Condensed Consolidated Statements of Cash Flows For the six months ended June 30, 2007 and 2006	3
Condensed Consolidated Statements of Comprehensive Income For the three months and six months ended June 30, 2007 and 2006	4
Condensed Consolidated Statement of Stockholders’ Equity For the six months ended June 30, 2007	5
Notes to Condensed Consolidated Financial Statements	6
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
ITEM 3. Quantitative and Qualitative Disclosures About Market Risks	33
ITEM 4. Controls and Procedures	35
PART II. OTHER INFORMATION	36

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	June 30, 2007			December 31, 2006
ASSETS
Current Assets
Cash and cash equivalents	$	10,793		$	899
Accounts receivable		126,837			113,193
Inventories		13,357			12,394
Deferred income taxes		44,663			51,084
Other current assets		3,848			7,226
		199,498			184,796
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		3,342,246			2,624,277
Not subject to amortization		697,042			142,096
Other property and equipment		75,661			41,392
		4,114,949			2,807,765
Less allowance for depreciation, depletion and amortization		(809,880	)		(700,241	)
		3,305,069			2,107,524
Goodwill		153,093			158,515
Other Assets		73,065			12,393
	$	3,730,725		$	2,463,228
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	178,906		$	131,639
Commodity derivative contracts		83,611			95,162
Royalties and revenues payable		39,266			38,159
Stock appreciation rights		53,157			57,429
Interest payable		14,277			1,143
Income taxes payable		—			94,272
Other current liabilities		31,366			42,388
		400,583			460,192
Long-Term Debt
Revolving credit facility		375,000			235,500
7% Senior Notes		500,000			—
7 3/4% Senior Notes		600,000			—
		1,475,000			235,500
Other Long-Term Liabilities
Asset retirement obligation		140,971			133,420
Commodity derivative contracts		16,105			18,114
Other		11,705			19,040
		168,781			170,574
Deferred Income Taxes		482,752			466,279
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common stock		805			792
Additional paid-in capital		1,037,604			964,472
Retained earnings		511,130			463,864
Treasury stock, at cost		(345,930	)		(298,445	)
		1,203,609			1,130,683
	$	3,730,725		$	2,463,228

See notes to consolidated financial statements.

1

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Revenues
Oil sales	$	231,583		$	286,617		$	437,101		$	538,084
Oil hedging		—			(36,548	)		—			(73,087	)
Gas sales		23,210			27,601			40,745			63,155
Other operating revenues		754			716			2,394			1,853
		255,547			278,386			480,240			530,005
Costs and Expenses
Production costs
Lease operating expenses		50,112			44,738			94,775			86,903
Steam gas costs		27,924			12,844			54,281			25,620
Electricity		9,500			9,954			18,267			18,786
Production and ad valorem taxes		5,042			7,036			10,301			12,804
Gathering and transportation expenses		1,220			2,072			1,406			3,656
General and administrative		29,913			38,065			52,410			61,037
Depreciation, depletion and amortization		58,523			50,917			111,201			100,684
Accretion		2,273			2,476			4,535			4,942
		184,507			168,102			347,176			314,432
Income from Operations		71,040			110,284			133,064			215,573
Other Income (Expense)
Interest expense		(11,698	)		(19,210	)		(17,058	)		(35,004	)
Loss on mark-to-market derivative contracts		(15,837	)		(142,914	)		(36,427	)		(312,242	)
Gain on termination of merger agreement		—			37,902			—			37,902
Other		747			1,296			1,324			1,620
Income (Loss) Before Income Taxes and Cumulative Effect of Accounting Change		44,252			(12,642	)		80,903			(92,151	)
Income tax (expense) benefit
Current		—			(45	)		—			(8,757	)
Deferred		(18,934	)		5,560			(35,015	)		44,311
Income (Loss) Before Cumulative Effect of Accounting Change		25,318			(7,127	)		45,888			(56,597	)
Cumulative effect of accounting change, net of tax benefit		—			—			—			(2,182	)
Net Income (Loss)	$	25,318		$	(7,127	)	$	45,888		$	(58,779	)
Earnings (Loss) Per Share
Basic
Income (loss) before cumulative effect of accounting change	$	0.35		$	(0.09	)	$	0.63		$	(0.72	)
Cumulative effect of accounting change		—			—			—			(0.03	)
Net income (loss)	$	0.35		$	(0.09	)	$	0.63		$	(0.75	)
Diluted
Income (loss) before cumulative effect of accounting change	$	0.35		$	(0.09	)	$	0.63		$	(0.72	)
Cumulative effect of accounting change		—			—			—			(0.03	)
Net income (loss)	$	0.35		$	(0.09	)	$	0.63		$	(0.75	)
Weighted Average Shares Outstanding
Basic		72,171			78,694			72,316			78,567
Diluted		73,275			78,694			73,382			78,567

See notes to consolidated financial statements.

2

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

	Six Months Ended June 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	45,888		$	(58,779	)
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		115,736			105,626
Deferred income taxes		35,015			(44,311	)
Cumulative effect of adoption of accounting change		—			2,182
Commodity derivative contracts		36,427			385,329
Noncash compensation		15,190			23,418
Other noncash items		(31	)		(48	)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(7,548	)		6,124
Income taxes payable		(94,272	)		—
Accounts payable and other liabilities		(5,155	)		(13,778	)
Net cash provided by operating activities		141,250			405,763
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(258,182	)		(289,425	)
Acquistion of Piceance Basin properties		(973,875	)		—
Derivative settlements		(49,143	)		(42,731	)
Other		(27,595	)		(4,535	)
Net cash used in investing activities		(1,308,795	)		(336,691	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		1,456,250			728,900
Repayments		(1,316,750	)		(769,900	)
Proceeds from 7% Senior Notes		500,000			—
Proceeds from 7 3/4% Senior Notes		600,000			—
Cost incurred in connection with financing arrangements		(17,917	)		—
Derivative settlements		—			(28,579	)
Purchase of treasury stock		(47,485	)		—
Other		3,341			358
Net cash provided by (used in) financing activities		1,177,439			(69,221	)
Net increase (decrease) in cash and cash equivalents		9,894			(149	)
Cash and cash equivalents, beginning of period		899			1,552
Cash and cash equivalents, end of period	$	10,793		$	1,403

See notes to consolidated financial statements.

3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(in thousands of dollars)

	Three Months Ended June 30,					Six Months Ended June 30,
	2007		2006			2007		2006
Net Income (Loss)	$	25,318	$	(7,127	)	$	45,888	$	(58,779	)
Other Comprehensive Income (Loss)
Commodity hedging contracts
Reclassification adjustment for terminated contracts		—		36,548			—		73,087
Related income taxes		—		(14,267	)		—		(28,095	)
		—		22,281			—		44,992
Comprehensive Income (Loss)	$	25,318	$	15,154		$	45,888	$	(13,787	)

See notes to consolidated financial statements.

4

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)

	Common Stock			Additional Paid-in Capital		Retained Earnings		Treasury Stock					Total
	Shares	Amount						Shares		Amount
Balance, December 31, 2006	79,172	$	792	$	964,472	$	463,864	(6,730	)	$	(298,445	)	$	1,130,683
Cumulative effect of accounting change (Note 5)	—		—		—		1,378	—			—			1,378
Net income	—		—		—		45,888	—			—			45,888
Issuance of common stock	1,000		10		44,530		—	—			—			44,540
Restricted stock awards	344		3		28,541		—	—			—			28,544
Treasury stock transactions	—		—		—		—	(1,026	)		(47,485	)		(47,485	)
Exercise of stock options and other	6		—		61		—	—			—			61
Balance, June 30, 2007	80,522	$	805	$	1,037,604	$	511,130	(7,756	)	$	(345,930	)	$	1,203,609

See notes to consolidated financial statements.

5

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1—Organization and Significant Accounting Policies

The condensed 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, exploits, develops, explores for and produces oil and gas. Our upstream activities are all located in the United States.

These condensed consolidated financial statements and related notes present our consolidated financial position as of June 30, 2007 and December 31, 2006, the results of our operations and comprehensive income for the three months and six months ended June 30, 2007 and 2006 and our cash flows for the six months ended June 30, 2007 and 2006 and the changes in stockholders’ equity for the six months ended June 30, 2007. 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, 2007 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, 2006.

Asset Retirement Obligations. The following table reflects the changes in our asset retirement obligation during the six months ended June 30, 2007 (in thousands):

Asset retirement obligation - December 31, 2006	$	137,311
Settlements		(1,782	)
Accretion expense		4,535
Acquisitions		2,591
Asset retirement additions		974
Asset retirement obligation - June 30, 2007	$	143,629	(1)

(1) $2.7 million included in current liabilities.

Earnings Per Share. For the three months and six months ended June 30, 2007 and 2006 the weighted average shares outstanding for computing basic and diluted earnings per share (“EPS”) are as follows (in thousands):

	Three Months Ended June 30,		Six Months Ended June 30,
	2007	2006	2007	2006
Common shares outstanding - basic	72,171	78,694	72,316	78,567
Unvested restricted stock, restricted stock units and stock options	1,104	—	1,066	—
Common shares outstanding - diluted	73,275	78,694	73,382	78,567
Unvested restricted stock, restricted stock units and stock options not included in computing EPS due to antidilutive effect	—	730	—	812

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

6

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

	June 30, 2007		December 31, 2006
Oil	$	4,674	$	4,954
Materials and supplies		8,683		7,440
	$	13,357	$	12,394

Stockholders’ Equity. Our Board of Directors has authorized the repurchase of up to $500 million of our common stock. The shares will be repurchased from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. In the six months ended June 30, 2007 we repurchased approximately 1.0 million common shares at a cost of approximately $47 million. Since the inception of the repurchase program we have repurchased a total of approximately 7.7 million common shares at a cost of approximately $342 million and we may expend an additional $158 million under the program.

Stock Based Compensation. We account for stock based compensation in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No.123R “Share-Based Payment” (“SFAS 123R”) that requires that the compensation cost relating to share-based payment transactions be recognized in financial statements.

Stock based compensation expense for the three months ended June 30, 2007 was $18.9 million of which $14.3 million is included in general and administrative expense (“G&A”), $1.4 million is included in lease operating expense and $3.2 million is included in oil and natural gas properties. Stock based compensation expense for the three months ended June 30, 2006 was $22.6 million of which $21.3 million is included in G&A and $1.3 million is included in oil and natural gas properties. For the six months ended June 30, 2007, stock based compensation expense was $26.2 million of which $20.0 million is included in G&A, $1.6 million is included in lease operating expense and $4.6 million is included in oil and natural gas properties, and for the same period ended June 30, 2006, stock based compensation expense was $31.7 million of which $29.0 million is included in G&A and $2.7 million is included in oil and natural gas properties.

Certain of our restricted stock units (“RSUs”) were classified as liability awards at December 31, 2006 because we did not have sufficient shares available for issuance under the 2004 Stock Incentive Plan. On May 3, 2007, we received stockholder approval for an amendment to the 2004 Stock Incentive Plan, which increased the available shares. As a result, these RSUs were revalued to their fair value on that date and are now classified as equity awards (as defined in SFAS 123R) in our Consolidated Balance Sheet. These RSUs will no longer be revalued each period.

During the six months ended June 30, 2007, 0.7 million stock appreciation rights (“SARs”) were granted. At June 30, 2007 there were 2.7 million SARs outstanding with a weighted average exercise price of $27.74 and 1.4 million of such SARs were exercisable with a weighted average exercise price of $13.11. During the six months ended June 30, 2007 1.0 million RSUs were granted. At June 30, 2007 5.3 million RSUs were outstanding, all of which are classified as equity instruments.

Income Taxes. Effective January 1, 2007, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48 “Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement No. 109)” (“FIN 48”). This interpretation clarified the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. See Note 5.

Recent Accounting Pronouncements. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” which is effective for fiscal years beginning after November 15, 2007 and for interim periods within those years. This statement defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. We are currently evaluating the potential impact of this statement.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”, which is effective for fiscal years beginning after

7

November 15, 2007. This statement permits an entity to choose to measure many financial instruments and certain other items at fair value at specified election dates. Subsequent unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. We are currently evaluating the potential impact of this statement.

Note 2—Long-Term Debt

At June 30, 2007 and December 31, 2006, long-term debt consisted of (in thousands):

	June 30, 2007		December 31, 2006
Senior revolving credit facility	$	375,000	$	235,500
7% senior notes		500,000		—
7 3/4% senior notes		600,000		—
	$	1,475,000	$	235,500

In June 2007, we issued $600 million of 7 ³/4% Senior Notes due 2015 (the “7 ³/4% 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 ³/4% Senior Notes on or after June 15, 2011 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to June 15, 2010 we may, at our option, redeem up to 35% of the 7 ³/4% Senior Notes with the proceeds from 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 ³/4% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.

In March 2007, we issued $500 million of 7% Senior Notes due 2017 (the “7% Senior Notes”) at par. The net proceeds were used to repay borrowings under our senior revolving credit facility and for general corporate purposes. We may redeem all or part of the 7% Senior Notes on or after March 15, 2012 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to March 15, 2010 we may, at our option, redeem up to 35% of the 7% Senior Notes with the proceeds from 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% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.

The 7% Senior Notes and 7 ³/4% Senior Notes are our general unsecured, senior obligations. The 7% Senior Notes and 7 ³/4% 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 7% Senior Notes and 7 ³/4% 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 7% Senior Notes and 7 ³/4% 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 indentures governing the 7% Senior Notes and 7 ³/4% Senior Notes contain 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.

On May 31, 2007, we entered into an Amended and Restated Credit Agreement (the “Amended Credit Agreement”) under which the aggregate commitments of the lenders is $1.3 billion and can be increased to $1.55 billion if certain conditions are met. The Amended Credit Agreement provides for an initial borrowing base of $1.3 billion and a conforming borrowing base of $1.15 billion, each of which will be redetermined on an annual basis, with PXP and the lenders each having the right to one annual interim unscheduled redetermination, and may be adjusted based on PXP’s oil and gas properties, reserves, other indebtedness and other relevant factors. The borrowing base and commitments were reduced to $970 million on the date PXP issued the 7 ³/4% Senior Notes. The Amended Credit Agreement also contains a $150 million sub-limit on letters of credit. The Amended Credit Agreement matures on

8

April 23, 2012. Collateral consists of 100% of the shares of stock of our material domestic subsidiaries and mortgages covering at least 75% of the total present value of our domestic oil and gas properties.

The Amended Credit Agreement 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 gas imbalance or take-or-pay 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 1.00.

At June 30, 2007, we had $9.7 million in letters of credit outstanding under the Amended Credit Agreement. At that date we were in compliance with the covenants contained in the Amended Credit Agreement and could have borrowed the full amount available under the Amended Credit Agreement. The effective interest rate on our borrowings under the Amended Credit Agreement was 6.375% at June 30, 2007.

Note 3—Derivative Instruments and Hedging Activities

General

We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized currently in our income statement as 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, because the derivatives do not qualify or we have elected not to use hedge accounting. If a derivative is designated as a cash flow hedge and qualifies for hedge accounting, any unrealized gain or loss is deferred in Accumulated Other Comprehensive Income (“OCI”), a component of Stockholders’ Equity, until the hedged oil and gas production is sold. Realized gains and losses on derivative instruments that are designated as a hedge and qualify for hedge accounting are generally included in oil and gas revenues in the period the hedged volumes are sold. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain in OCI until the related product has been delivered.

Under SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”, in 2006 certain of our derivatives were deemed to contain a significant financing element because they included off-market terms and cash settlements with respect to such derivatives are required to be reflected as financing activities in the Statement of Cash Flows. Cash settlements with respect to derivatives that are qualified for hedge accounting and do not have a significant financing element are reflected as operating activities in the Statement of Cash Flows. Cash settlements with respect to derivatives that are not qualified for hedge accounting and do not have a significant financing element are reflected as investing activities in the Statement of Cash Flows.

At June 30, 2007 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
2007
July - Dec	Put options	50,000 Bbls	$55.00 Strike price	WTI
2008
Jan - Dec	Put options	42,000 Bbls	$55.00 Strike price	WTI

The average strike prices for the put options do not reflect the cost to purchase such options. The only cash settlements we are required to make on these contracts are option premiums of $56 million for the last six months of 2007 and $58 million for 2008, including interest.

9

Income Statement, Cash Payments and Other Comprehensive Income

During the three and six months ended June 30, 2007 and 2006, pre-tax losses recognized in our income statement for derivatives were as follows (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2007		2006		2007		2006
Loss on mark-to-market derivative contracts	$	15,837	$	142,914	$	36,427	$	312,242
Loss reclassified from OCI and recognized in
Oil revenues		—		36,548		—		73,087

At December 31, 2006 there were no amounts in OCI. The 2006 amounts that were reclassified from OCI and recognized in oil revenues represent deferred losses attributable to 2006 swaps that were cancelled in 2005.

During the three and six months ended June 30, 2007 and 2006 cash (payments)/receipts for derivatives were as follows (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Mark-to-market contracts
Crude oil options	$	(25,615	)	$	(22,583	)	$	(49,143	)	$	(66,976	)
Natural gas call options		—			(2,848	)		—			(5,665	)
Contracts accounted for using hedge accounting
Natural gas purchases		—			—			—			1,331

Note 4—Acquisition

On May 31, 2007, we acquired certain Piceance Basin properties for $974 million in cash, including $10 million in related acquisition costs and $64 million for net cash outflows from the effective date to the closing date (primarily related to capital expenditures for drilling and acreage acquisitions) and issued one million shares of common stock with a fair value of approximately $45 million to the seller, Laramie Energy, LLC. The Piceance Basin properties include interests in oil and gas producing properties in the Mesaverde geologic section of the Piceance Basin in Colorado, plus associated midstream assets, including a 25% interest in the Collbran Valley Gas Gathering, LLC. We allocated the purchase price $511 million to oil and gas properties subject to amortization, $448 million to oil and gas properties not subject to amortization, $40 million to our investment in the Collbran Valley Gas Gathering, LLC and the remainder to inventory and other properties and equipment. We financed $946 million of the acquisition using our senior revolving credit facility.

Note 5—Income Taxes

Effective January 1, 2007 we adopted FIN 48. This interpretation clarified the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. At January 1, 2007 we recorded the cumulative effect of the change in accounting principle as a $1.4 million increase in the opening balance of retained earnings, a $0.8 million decrease in goodwill and a $2.2 million reduction in our existing reserves for uncertain tax positions. The adjustment to goodwill relates to tax positions taken with respect to Nuevo Energy Company (“Nuevo”) and 3TEC Energy Corporation in periods prior to our mergers in 2004 and 2003, respectively.

We file income tax returns in the U.S. federal jurisdiction, and various state jurisdictions. We are no longer subject to U.S. federal and state income tax examinations by tax authorities for years before 1996. The Internal Revenue

10

Service (“IRS”) commenced an examination of our U.S. income tax returns for 2003 and 2004 that is anticipated to be completed by the end of the first quarter 2008. In addition, the IRS has commenced an examination of Nuevo’s U.S. income tax returns for 2003 and 2004 that is anticipated to be completed by the end of the first quarter 2008. As of June 30, 2007, the IRS had not proposed any significant adjustments that would result in a material change to our financial position.

We recognize interest and penalties related to unrecognized tax positions in income tax expense. At January 1, 2007 and June 30, 2007 we had approximately $18.4 million and $18.2 million of unrecognized tax benefits, respectively, of these amounts approximately $5.5 million at January 1, 2007 and approximately $4.4 million at June 30, 2007 would affect our effective tax rate if recognized. Included in such amounts are interest and penalties of an immaterial amount.

Note 6—Commitments and Contingencies

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

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, $40 million ($78 million undiscounted), are included in our asset retirement obligation as reflected on our Consolidated Balance Sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $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, 2007 the escrow account had a balance of $6.0 million. The fair value of our guarantee, $0.3 million, is included in Other Long-Term Liabilities in our 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.

11

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 its notice of appeal and Plaintiffs intend to file 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.

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

Note 7—Consolidating Financial Statements

We are the issuer of $500 million of 7% Senior Notes due 2017 and $600 million of 7 ³/4% Senior Notes due 2015, 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.

12

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

JUNE 30, 2007

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	10,786		$	7		$	—	$	—		$	10,793
Accounts receivable and other current assets		151,635			37,070			—		—			188,705
		162,421			37,077			—		—			199,498
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		2,262,019			1,080,227			—		—			3,342,246
Not subject to amortization		219,109			477,933			—		—			697,042
Other property and equipment		52,949			10,671			12,041		—			75,661
		2,534,077			1,568,831			12,041		—			4,114,949
Less allowance for depreciation, depletion and amortization		(447,857	)		(417,912	)		—		55,889			(809,880	)
		2,086,220			1,150,919			12,041		55,889			3,305,069
Investment in and Advances to Subsidiaries		1,343,542			—			—		(1,343,542	)		—
Other Assets		5,289			220,869			—		—			226,158
	$	3,597,472		$	1,408,865		$	12,041	$	(1,287,653	)	$	3,730,725
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	272,116		$	50,356		$	—	$	(5,500	)	$	316,972
Commodity derivative contracts		83,611			—			—		—			83,611
		355,727			50,356			—		(5,500	)		400,583
Long-Term Debt		1,475,000			—			—		—			1,475,000
Other Long-Term Liabilities		146,102			22,679			—		—			168,781
Payable to Parent		—			694,178			9,035		(703,213	)		—
Deferred Income Taxes		417,034			42,278			—		23,440			482,752
Stockholders’ Equity		1,203,609			599,374			3,006		(602,380	)		1,203,609
	$	3,597,472		$	1,408,865		$	12,041	$	(1,287,653	)	$	3,730,725

13

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

DECEMBER 31, 2006

(in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	896		$	3		$	—	$	—		$	899
Accounts receivable and other current assets		156,242			27,655			—		—			183,897
		157,138			27,658			—		—			184,796
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		2,131,959			492,318			—		—			2,624,277
Not subject to amortization		124,830			17,266			—		—			142,096
Other property and equipment		31,237			1,564			8,591		—			41,392
		2,288,026			511,148			8,591		—			2,807,765
Less allowance for depreciation, depletion and amortization		(390,931	)		(309,310	)		—		—			(700,241	)
		1,897,095			201,838			8,591		—			2,107,524
Investment in and Advances to Subsidiaries		352,667			—			—		(352,667	)		—
Other Assets		(1,674	)		172,582			—		—			170,908
	$	2,405,226		$	402,078		$	8,591	$	(352,667	)	$	2,463,228
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	320,899		$	44,131		$	—	$	—		$	365,030
Commodity derivative contracts		95,162			—			—		—			95,162
		416,061			44,131			—		—			460,192
Long-Term Debt		235,500			—			—		—			235,500
Other Long-Term Liabilities		151,365			19,209			—		—			170,574
Payable to Parent		—			(101,526	)		5,585		95,941			—
Deferred Income Taxes		471,617			(5,338	)		—		—			466,279
Stockholders’ Equity		1,130,683			445,602			3,006		(448,608	)		1,130,683
	$	2,405,226		$	402,078		$	8,591	$	(352,667	)	$	2,463,228

14

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 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		6,202			45			—		(5,500	)		747
Income (Loss) Before Income Taxes		44,326			(10,544	)		—		10,470			44,252
Income tax benefit (expense)
Current		(12,788	)		12,788			—		—			—
Deferred		(6,220	)		(12,714	)		—		—			(18,934	)
Net Income (Loss)	$	25,318		$	(10,470	)	$	—	$	10,470		$	25,318

15

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2006

(in thousands)

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

16

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			109,519			—		(55,889	)		115,736
		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		6,779			45			—		(5,500	)		1,324
Income (Loss) Before Income Taxes		85,891			(77,440	)		—		72,452			80,903
Income tax benefit (expense)
Current		(12,552	)		12,552			—		—			—
Deferred		(27,451	)		15,876			—		(23,440	)		(35,015	)
Net Income (Loss)	$	45,888		$	(49,012	)	$	—	$	49,012		$	45,888

17

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2006

(in thousands)

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

18

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
Commodity derivative contracts		36,427			—			—			—			36,427
Noncash compensation		14,037			1,153			—			—			15,190
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	)
Income tax payable		(94,272	)		—			—			—			(94,272	)
Accounts payable and other liabilities		(5,861	)		706			—			—			(5,155	)
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 Piceance Basin 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 senior notes		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

19

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2006

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(58,779	)	$	(361	)	$	361		$	(58,779	)
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		36,278			69,348			—			105,626
Equity in earnings of subsidiaries		361			—			(361	)		—
Deferred income taxes		(38,353	)		(5,958	)		—			(44,311	)
Cumulative effect of adoption of accounting change		2,182			—			—			2,182
Commodity derivative contracts		360,220			25,109			—			385,329
Noncash compensation		23,418			—			—			23,418
Other noncash items		(48	)		—			—			(48	)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(4,061	)		10,185			—			6,124
Accounts payable and other liabilities		(17,109	)		3,331			—			(13,778	)
Net cash provided by operating activities		304,109			101,654			—			405,763
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(185,569	)		(103,856	)		—			(289,425	)
Derivative settlements		(42,731	)		—			—			(42,731	)
Other		(4,080	)		(455	)		—			(4,535	)
Net cash used in investing activities		(232,380	)		(104,311	)		—			(336,691	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		728,900			—			—			728,900
Repayments		(769,900	)		—			—			(769,900	)
Derivative settlements		(28,579	)		—			—			(28,579	)
Investment in and advances to affiliates		(2,655	)		2,655			—			—
Other		358			—			—			358
Net cash provided by (used in) financing activities		(71,876	)		2,655			—			(69,221	)
Net decrease in cash and cash equivalents		(147	)		(2	)		—			(149	)
Cash and cash equivalents, beginning of period		1,548			4			—			1,552
Cash and cash equivalents, end of period	$	1,401		$	2		$	—		$	1,403

20

Note 8—Proposed Merger with Pogo Producing Company

On July 17, 2007, we announced that we had entered into a definitive agreement to acquire Pogo Producing Company (“Pogo”) in a stock and cash transaction valued at approximately $3.6 billion, based on our July 16, 2007 closing stock price of $51.19 per share. Under the terms of the definitive agreement, Pogo stockholders will receive 0.68201 shares of our common stock and $24.88 of cash for each share of Pogo common stock. Pogo stockholders will have the right to elect to receive cash or stock, subject to pro ration if either the cash or stock election is oversubscribed. If completed, we will issue approximately 40 million shares of common stock and pay approximately $1.5 billion in cash.

The transaction is expected to qualify as a tax free reorganization under Section 368(a) and is expected to be tax free to our stockholders and tax free for the stock portion of the consideration received by Pogo stockholders. The Boards of Directors of both companies have approved the merger agreement and each will recommend it to their respective stockholders for approval. The transaction will remain subject to stockholder approval from both companies and other customary conditions. Post closing, it is anticipated that our stockholders will own approximately 66% of the combined company and Pogo stockholders will own approximately 34% of the combined company.

The transaction is expected to close in the fourth quarter of 2007. We will account for the transaction as a purchase of Pogo under purchase accounting rules and we will continue to use the full cost method of accounting for our oil and gas properties.

21

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, 2006.

Company Overview

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

• the Los Angeles and San Joaquin Basins onshore California;

• the Santa Maria Basin offshore California;

• the Piceance Basin in Colorado; and

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

Assets in our principal focus areas include mature properties with long-lived reserves and significant development and exploitation opportunities as well as newer properties with development, exploitation and exploration potential. Our primary sources of liquidity are cash generated from our operations and our senior revolving credit facility. At June 30, 2007 we had approximately $585.3 million of availability under our senior revolving credit facility. We have a capital budget for 2007, excluding acquisitions, of $750 million. Currently we believe that we have sufficient liquidity through our cash from operations and borrowing capacity under the Amended Credit Agreement to meet our short-term and long-term normal recurring operating needs and anticipated capital expenditures. In addition, the majority of our capital expenditures is discretionary and could be curtailed if our cash flows declined from expected levels.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. For 2007 and 2008 our derivative position consists exclusively of purchased put option contracts with a strike price of $55.00 on 50,000 barrels per day for 2007 and 42,000 barrels per day for 2008. The only cash settlements we are required to make on these contracts are option premiums and interest, which are expected to total approximately $56 million in the last six months of 2007 and $58 million in 2008. In return, to the extent the daily average NYMEX price for West Texas Intermediate crude oil is less than $55.00, we will receive the difference between $55.00 and the daily average NYMEX price for West Texas Intermediate crude oil. Since our remaining derivative position consists entirely of crude oil put options, there will continue to be volatility in derivative gains or losses on our income statement, however, our ultimate potential loss will be limited to the cost of the options. See Item 3 – Quantitative and Qualitative Disclosures About Market Risks.

Property Acquisition

On May 31, 2007, we acquired interests in oil and gas producing properties covering over 60,000 gross (55,000 net) acres in the Mesaverde geologic section of the Piceance Basin in Colorado, plus associated midstream assets, including a 25% interest in the Collbran Valley Gas Gathering, LLC. These properties, which we refer to as the Piceance Basin properties, and which include over 200 producing/productive wells and over 3,000 additional potential drilling locations, produced approximately 6 thousand barrels of oil equivalent (“MBOE”) per day at the closing date, of which approximately 97% was natural gas. As of December 31, 2006, the properties had estimated proved developed reserves of approximately 15 million barrels of oil equivalent (“MMBOE”), of which approximately 97% was natural gas. We paid $974 million in cash, including $10 million in related acquisition costs and $64 million for net cash outflows from the effective date to the closing date (primarily related to capital expenditures for drilling activities and acreage acquisitions) and issued one million shares of common stock with a fair market value of approximately $45 million to the seller, Laramie Energy, LLC, a privately held Delaware limited liability company. We financed $946 million of the acquisition using our senior revolving credit facility.

22

Proposed Merger with Pogo Producing Company

On July 17, 2007 we announced that we had entered into a definitive agreement to acquire Pogo Producing Company (“Pogo”) in a stock and cash transaction valued at approximately $3.6 billion, based on our July 16, 2007 closing stock price of $51.19 per share. Under the terms of the definitive agreement, Pogo stockholders will receive 0.68201 shares of our common stock and $24.88 of cash for each share of Pogo common stock. Pogo stockholders will have the right to elect to receive cash or stock, subject to pro ration if either the cash or stock election is oversubscribed. If completed, we will issue approximately 40 million shares of common stock and pay approximately $1.5 billion in cash.

The transaction is expected to qualify as a tax free reorganization under Section 368(a) and is expected to be tax free to our stockholders and tax free for the stock portion of the consideration received by Pogo stockholders. The Boards of Directors of both companies have approved the merger agreement and each will recommend it to their respective stockholders for approval. The transaction will remain subject to stockholder approval from both companies and other customary conditions. Post closing, it is anticipated that our stockholders will own approximately 66% of the combined company and Pogo stockholders will own approximately 34% of the combined company.

The transaction is expected to close in the fourth quarter of 2007. We will account for the transaction as a purchase of Pogo under purchase accounting rules and we will continue to use the full cost method of accounting for our oil and gas properties.

General

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

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

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

23

Results Overview

Our earnings are subject to volatility due to: (i) gains and losses on derivative contracts subject to mark-to-market accounting as changes occur in the NYMEX price indexes and (ii) stock appreciation rights (“SARs”), which are accounted for as liability awards under SFAS 123R and are remeasured to fair value each reporting period. The fair value of SARs units is related to the market price of our common stock and will fluctuate with movements in our stock price.

In the first half of 2007, we reported net income of $45.9 million, or $0.63 per diluted share. In the first half of 2006, primarily as a result of a $312.2 million derivative mark-to-market loss, we reported a net loss of $58.8 million, or $0.75 per share. Our net loss in 2006 includes a non-cash, after-tax expense related to the adoption of SFAS 123R of $2.2 million or $0.03 per share.

Results of Operations

On May 31, 2007, we acquired interests in oil and gas producing properties covering over 60,000 gross (55,000 net) acres in the Mesaverde geologic section of the Piceance Basin in Colorado, plus associated midstream assets, including a 25% interest in the Collbran Valley Gas Gathering, LLC. These properties, which we refer to as the Piceance Basin properties, and which include over 200 producing/productive wells and over 3,000 additional potential drilling locations, are currently producing approximately 6 MBOE per day, of which approximately 97% is natural gas.

On September 29, 2006, we closed the sale of non-strategic oil and gas properties located primarily in California and Texas to subsidiaries of Occidental Petroleum Corporation (“Occidental”). The properties included our interests in the Asphalto, Buena Vista and Mt. Poso fields in the San Joaquin Valley, the Sansinena field in the Los Angeles Basin, the Pakenham field in West Texas and various other minor properties. This transaction had an effective date of October 1, 2006. On a barrel of oil equivalent basis, these properties represented approximately 12% of our sales volume for the first half of 2006.

24

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2007		2006		2007		2006
Sales Volumes
Oil and liquids sales (MBbls)		4,264		4,822		8,526		9,538
Gas (MMcf)
Production		4,212		5,860		7,267		11,685
Used in steam operations		584		1,128		1,163		2,484
Sales		3,628		4,732		6,104		9,201
MBOE
Production		4,966		5,799		9,737		11,486
Sales		4,870		5,611		9,544		11,072
Daily Average Volumes
Oil and liquids sales (Bbls)		46,865		52,990		47,106		52,699
Gas (Mcf)
Production		46,285		64,384		40,148		64,553
Used in steam operations		6,415		12,390		6,423		13,721
Sales		39,870		51,994		33,725		50,832
BOE
Production		54,579		63,721		53,798		63,457
Sales		53,510		61,656		52,727		61,171
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	65.02	$	70.72	$	61.67	$	67.12
Gas		7.55		6.76		7.17		7.85
Average Realized Sales Price Before Derivative Transactions
Oil (per Bbl)	$	54.31	$	59.44	$	51.27	$	56.41
Gas (per Mcf)		6.40		5.83		6.68		6.86
Per BOE		52.32		56.00		50.07		54.30
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	10.29	$	7.97	$	9.93	$	7.85
Steam gas costs		5.73		2.29		5.69		2.31
Electricity		1.95		1.77		1.91		1.70
Production and ad valorem taxes		1.04		1.25		1.08		1.16
Gathering and transportation		0.25		0.37		0.15		0.33

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,
	2007			2006			2007			2006
Mark-to-market contracts
Crude oil options	$	(25,615	)	$	(22,583	)	$	(49,143	)	$	(66,976	)
Natural gas call options		—			(2,848	)		—			(5,665	)
Contracts accounted for using hedge accounting		—			—			—			1,331

25

Comparison of Three Months Ended June 30, 2007 to Three Months Ended June 30, 2006

Oil and gas revenues. Oil and gas revenues decreased $22.9 million, to $254.8 million for 2007 from $277.7 million for 2006. The decrease is primarily due to the Occidental property sale and a decrease in realized prices of $3.68 per BOE, partially offset by the absence of an oil revenue hedging loss in 2007. Excluding the properties sold from 2006 revenues, oil and gas revenues increased $11.0 million, to $254.8 million for 2007 from $243.8 million for 2006 primarily due to the absence of an oil revenue hedging loss in 2007 offset by a decrease in price of $4.71 per BOE in 2007.

Oil revenues excluding the effects of hedging, decreased $55.0 million to $231.6 million for 2007 from $286.6 million for 2006 reflecting lower production ($30.3 million) and lower realized prices ($24.7 million). Our average realized price for oil decreased $5.13 to $54.31 per Bbl for 2007 from $59.44 per Bbl for 2006. The decrease is primarily attributable to a decline in the NYMEX oil price, which averaged $65.02 per Bbl in 2007 versus $70.72 per Bbl in 2006. Oil sales volumes decreased 6.1 MBbls per day to 46.9 MBbls per day in 2007 from 53.0 MBbls per day in 2006, primarily reflecting the properties sold which had sales of 4.6 MBbls per day in the second quarter of 2006. Hedging had the effect of decreasing our oil revenues by $36.5 million or $7.58 per Bbl in 2006.

Gas revenues, decreased $4.4 million to $23.2 million in 2007 from $27.6 million in 2006 due to decreased sales volumes ($7.1 million) partially offset by higher realized prices ($2.7 million). Our average realized price for gas was $6.40 per Mcf in 2007 compared to $5.83 per Mcf in 2006. Gas sales volumes decreased from 52.0 MMcf per day in 2006 to 39.9 MMcf per day in 2007, primarily reflecting the impact of properties sold which had sales of 18.4 MMcf per day in the second quarter of 2006.

Lease operating expenses. Lease operating expenses increased $5.4 million, to $50.1 million in 2007 from $44.7 million in 2006. Excluding the properties sold from 2006 costs, lease operating expenses increased $12.2 million, to $50.1 million in 2007 from $37.9 in 2006. The increase is primarily attributable to higher expenditures for repairs and maintenance and well workovers, increased labor costs and general cost increases from service providers. Excluding the properties sold, on a per unit basis lease operating expenses increased to $10.29 per BOE in 2007 versus $7.72 per BOE in 2006.

Steam gas costs. Steam gas costs increased $15.1 million, to $27.9 million in 2007 from $12.8 million in 2006, primarily reflecting higher steam volumes and higher cost of gas used in steam generation. In 2007 we burned approximately 4.3 Bcf of natural gas at a cost of approximately $6.53 per Mcf compared to 3.4 Bcf at a cost of approximately $3.75 per Mcf in 2006. The higher cost per Mcf in 2007 principally reflects the fact that all the gas burned in 2007 was purchased while in 2006 almost half of the gas burned was produced from the Company’s properties and costs for these volumes consisted only of transportation costs.

Electricity. Electricity decreased $0.5 million, to $9.5 million in 2007 from $10.0 million in 2006. Excluding the properties sold from 2006 costs, electricity increased $0.3 million, to $9.5 million in 2007 from $9.2 million in 2006, primarily reflecting higher usage. Excluding the properties sold, on a per unit basis electricity increased to $1.95 per BOE in 2007 versus $1.86 per BOE in 2006.

Production and ad valorem taxes. Production and ad valorem taxes decreased $2.0 million, to $5.0 million in 2007 from $7.0 million in 2006. Excluding the properties sold from 2006 costs, production and ad valorem taxes increased $0.2 million, to $5.0 million in 2007 from $4.8 million in 2006.

Gathering and transportation expenses. Gathering and transportation expenses decreased $0.9 million, to $1.2 million in 2007 from $2.1 million in 2006. Excluding the properties sold from 2006 costs, gathering and transportation costs increased $1.0 million to $1.2 million in 2007 from $0.2 million in 2006, primarily reflecting the Piceance Basin property acquisition.

General and administrative expense. G&A expense decreased $8.2 million, to $29.9 million in 2007 compared to $38.1 million in 2006. The 2006 expense included approximately $9.0 million of stock based compensation related to officer resignations. No similar activity occurred in 2007.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. Capitalized costs increased to $10.2 million in 2007 compared to $8.0 million in 2006, primarily reflecting increases in our acquisition, exploration and development activities.

26

Depreciation, depletion and amortization, or DD&A. DD&A expense increased $7.6 million, to $58.5 million in 2007 from $50.9 million in 2006. The increase was attributable to our oil and gas DD&A, primarily due to a higher per unit rate. Our average oil and gas unit of production rate increased to $11.35 per BOE in 2007 compared to $8.45 per BOE in 2006. The increase primarily reflects the effect of increased future development costs, higher cost reserve additions, exploration costs and property acquisitions. Our DD&A rate in the third quarter of 2007 will be approximately $12.64 per BOE as a result of the acquisition of the Piceance Basin properties.

Accretion expense. Accretion expense decreased $0.2 million, to $2.3 million in 2007 from $2.5 million in 2006. Accretion expense for 2006 included $0.4 million attributable to the properties sold to Occidental. Excluding such expense the $0.2 million increase primarily reflects higher estimated future costs of our abandonment obligations.

Interest expense. Interest expense decreased $7.5 million, to $11.7 million in 2007 from $19.2 million in 2006 due to a $5.0 million decrease in interest on derivative contracts and increased capitalization of interest of $2.6 million. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization. We capitalized $5.0 million and $2.4 million of interest in 2007 and 2006, respectively.

Gain (loss) on mark-to-market derivative contracts. We do not currently use hedge accounting for our derivative instruments, because the derivatives do not qualify or we have elected not to use hedge accounting. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

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. In 2006 we recognized a $142.9 million loss related to mark-to-market derivative contracts and cash payments related to contracts that settled totaled $25.4 million.

Our derivative position in 2007 consists of crude oil put options and our ultimate potential loss on these contracts will be limited to the cost of the options. In 2006 the derivative losses were primarily related to crude oil collars.

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

Income taxes. During interim periods income tax expense is generally based on the estimated effective income tax rate that is expected for the entire year plus any significant, unusual or infrequently occurring items which are recorded in the period that the specific item occurs. In the second quarter of 2007 we revised our estimated effective annual tax rate to approximately 45% from the 42% estimated effective annual tax rate that was utilized in the first quarter of 2007. 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 primarily reflecting expenses that are not deductible because of IRS limitations.

For the second quarter of 2007 income tax expense was approximately 43% of pretax income. In addition to changes in our estimated annual tax rate for 2007, specific items affecting income tax expense for the second quarter included changes in the balances of state deferred tax liabilities as a result of state apportionment changes caused by the purchase of certain oil and gas properties in the second quarter of 2007 plus the impact of changes to certain tax credits related to our enhanced oil recovery operations as a result of a newly issued IRS computational guidelines.

Comparison of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2006

Oil and gas revenues. Oil and gas revenues decreased $50.3 million, to $477.8 million for 2007 from $528.2 million for 2006 primarily due to the Occidental property sale and a decrease in realized prices of $4.23 per BOE, partially offset by the absence of an oil revenue hedging loss in 2007. Excluding the properties sold from 2006 revenues, oil and gas revenues increased $15.4 million, to $477.8 million in 2007 from $462.4 million for 2006 primarily due to the absence of an oil revenue hedging loss in 2007 partially offset by a decrease in price of $5.08 per BOE in 2007.

Oil revenues excluding the effects of hedging, decreased $101.0 million to $437.1 million for 2007 from $538.1 million for 2006 reflecting lower realized prices ($49.1 million) and lower production ($51.9 million). Our average realized price for oil decreased $5.14 to $51.27 per Bbl for 2007 from $56.41 per Bbl for 2006. The decrease is primarily attributable to a decline in the NYMEX oil price, which averaged $61.67 per Bbl in 2007 versus $67.12 per Bbl in 2006. Oil sales volumes decreased 5.6 MBbls per day to 47.1 MBbls per day in 2007 from 52.7 MBbls per day in 2006, primarily reflecting the properties sold which had sales of 4.5 MBbls per day in 2006. Hedging had the effect of decreasing our oil revenues by $73.1 million or $7.66 per Bbl in 2006.

27

Gas revenues, decreased $22.5 million to $40.7 million in 2007 from $63.2 million in 2006 due to decreased sales volumes ($20.7 million) and a decrease in realized prices ($1.8 million). Our average realized price for gas was $6.68 per Mcf in 2007 compared to $6.86 per Mcf in 2006. Gas sales volumes decreased from 50.8 MMcf per day in 2006 to 33.7 MMcf per day in 2007 primarily reflecting the impact of properties sold which had sales of 18.3 MMcf per day in the 2006.

Lease operating expenses. Lease operating expenses increased $7.9 million, to $94.8 million in 2007 from $86.9 million in 2006. Excluding the properties sold and acquired, lease operating expenses increased $21.1 million, to $94.8 million in 2007 from $73.7 million in 2006. The increase is primarily attributable to higher expenditures for repairs and maintenance and well workovers, increased labor costs and general cost increases from service providers. Excluding the properties sold, on a per unit basis, lease operating expenses increased to $9.93 per BOE in 2007 versus $7.59 per BOE in 2006.

Steam gas costs. Steam gas costs increased $28.7 million, to $54.3 million in 2007 from $25.6 million in 2006, primarily reflecting higher steam volumes and higher cost of gas used in steam generation. In 2007 we burned approximately 8.4 Bcf of natural gas at a cost of approximately $6.44 per Mcf compared to 6.6 Bcf at a cost of $3.89 per Mcf in 2006. The higher cost per Mcf in 2007 principally reflects the fact that all the gas burned in 2007 was purchased while in 2006 almost half of the gas burned was produced from the Company’s properties and costs for these volumes consisted only of transportation costs.

Electricity. Electricity decreased $0.5 million, to $18.3 million in 2007 from $18.8 million in 2006. Excluding the properties sold from 2006 costs, electricity increased $1.0 million, to $18.3 million in 2007 from $17.3 million in 2006, primarily reflecting higher usage. Excluding the properties sold, on a per unit basis, electricity increased to $1.91 per BOE in 2007 versus $1.78 per BOE in 2006.

Production and ad valorem taxes. Production and ad valorem taxes decreased $2.5 million, to $10.3 million in 2007 from $12.8 million in 2006. Excluding the properties sold from 2006 costs, production and ad valorem taxes increased $1.5 million, to $10.3 million in 2007 from $8.8 million in 2006 primarily reflecting higher ad valorem taxes due to higher property tax basis.

Gathering and transportation expenses. Gathering and transportation expenses decreased $2.3 million, to $1.4 million in 2007 from $3.7 million in 2006. Excluding the properties sold from 2006 costs, gathering and transportation expenses increased $1.1 million to $1.4 million in 2007 from $0.3 million in 2006.

General and administrative expense. G&A expense decreased $8.6 million to $52.4 million in 2007 compared to $61.0 million in 2006. The 2006 expense includes approximately $9.0 million of stock based compensation related to officer resignations. No similar activity occurred in 2007.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. Capitalized costs increased to $18.5 million in 2007 compared to $15.8 million in 2006, primarily reflecting increased acquisition, exploration and development activities.

Depreciation, depletion and amortization, or DD&A. DD&A expense increased $10.5 million, to $111.2 million in 2007 from $100.7 million in 2006. The increase was attributable to our oil and gas DD&A, primarily due to a higher per unit rate. Our oil and gas unit of production rate increased to $11.01 per BOE in 2007 compared to $8.45 per BOE in 2006. The increase primarily reflects the effect of increased future development costs, higher costs of reserve additions, exploration costs and property acquisitions. Our DD&A rate in the third quarter of 2007 will be approximately $12.64 per BOE as a result of the acquisition of the Piceance Basin properties.

Accretion expense. Accretion expense decreased $0.4 million, to $4.5 million in 2007 from $4.9 million in 2006. Accretion expense for 2006 included $0.8 million attributable to the properties sold to Occidental. Excluding such expense the $0.4 million increase primarily reflects higher estimated future costs of our abandonment obligations.

Interest expense. Interest expense decreased $17.9 million, to $17.1 million in 2007 from $35.0 million in 2006 primarily due to lower outstanding debt and derivatives and higher interest capitalization. Interest expense on senior debt decreased by $8.7 million for the first six months of 2007 due to the retirement of senior notes in the fourth quarter of 2006 partially offset by interest on new senior notes issued in March and June 2007. Interest on derivative contracts decreased by $5.3 million in 2007 compared to 2006. We capitalized $7.1 million and $3.9 million of interest in 2007 and 2006, respectively.

28

Gain (loss) on mark-to-market derivative contracts. We do not currently use hedge accounting for our derivative instruments, because the derivatives do not qualify or we have elected not to use hedge accounting. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

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. In 2006 we recognized a $312.2 million loss related to mark-to-market derivative contracts and cash payments related to contracts that settled totaled $71.3 million.

Our derivative position in 2007 consists of crude oil put options and our ultimate potential loss on these contracts will be limited to the cost of the options. In 2006 the derivative losses were primarily related to crude oil collars.

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

Income taxes. During interim periods income tax expense is generally based on the estimated effective income tax rate that is expected for the entire year plus any significant, unusual or infrequently occurring items which are recorded in the period that the specific item occurs. In the second quarter of 2007 we revised our estimated effective annual tax rate to approximately 45% from the 42% estimated effective annual tax rate that was utilized in the first quarter of 2007. 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 primarily reflecting expenses that are not deductible because of IRS limitations.

For the six months ended June 30, 2007 income tax expense was approximately 43% of pretax income. In addition to changes in our estimated annual tax rate for 2007, specific items affecting income tax expense for the six months ended June 30, 2007 included changes in the balances of state deferred tax liabilities as a result of state apportionment changes caused by the purchase of certain oil and gas properties in the second quarter of 2007 plus the impact of changes to certain tax credits related to our enhanced oil recovery operations as a result of a newly issued IRS computational guidelines.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operations and our senior revolving credit facility. At June 30, 2007, we had approximately $585.3 million of availability under our senior revolving credit facility. We have made and will continue to make substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and gas. We have a capital budget for 2007, excluding acquisitions, of approximately $750 million. Currently, we believe that we have sufficient liquidity through our cash from operations and borrowing capacity under our Amended Credit Agreement to meet our short-term and long-term normal recurring operating needs and anticipated capital expenditures.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. In addition, the majority of our capital expenditures is discretionary and could be curtailed if our cash flows declined from expected levels.

Working Capital

At June 30, 2007, we had a working capital deficit of approximately $201 million. Our working capital deficit is affected by fluctuations in the fair value of our commodity derivative instruments and SARs. At June 30, 2007, we had net short-term liabilities of $57 million and $33 million for derivatives and SARs, respectively. Excluding such items our working capital deficit was approximately $111 million. We generally have a working capital deficit because we use excess cash to pay down borrowings under our senior revolving credit facility.

29

Financing Activities

7 ³/4% Senior Notes. In June 2007, we issued $600 million of 7 ³/4% Senior Notes due 2015 (the “7 ³/4% Senior Notes”) at par. We may redeem all or part of the 7 ³/4% Senior Notes on or after June 15, 2011 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to June 15, 2010 we may, at our option, redeem up to 35% of the 7 ³/4% Senior Notes with the proceeds from 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 ³/4% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.

7% Senior Notes. In March 2007 we issued $500 million of 7% Senior Notes due 2017 (the “7% Senior Notes”) at par. We may redeem all or part of the 7% Senior Notes on or after March 15, 2012 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to March 15, 2010 we may, at our option, redeem up to 35% of the 7% Senior Notes with the proceeds from 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% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 7% Senior Notes and 7 ³/4% Senior Notes are our general unsecured, senior obligations. The 7% Senior Notes and 7 ³/4% 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 7% Senior Notes and 7 ³/4% 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 7% Senior Notes and 7 ³/4% 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 indentures governing the 7% Senior Notes and 7 ³/4% 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 May 31, 2007, we entered into the Amended Credit Agreement under which the aggregate commitments of the lenders is $1.3 billion and can be increased to $1.55 billion if certain conditions are met. The Amended Credit Agreement provides for an initial borrowing base of $1.3 billion and a conforming borrowing base of $1.15 billion, each of which will be redetermined on an annual basis, with PXP and the lenders each having the right to one annual interim unscheduled redetermination, and may be adjusted based on PXP’s oil and gas properties, reserves, other indebtedness and other relevant factors. The borrowing base and commitments were reduced to $970 million on the date PXP issued the 7 ³/4% Senior Notes. The Amended Credit Agreement also contains a $150 million sub-limit on letters of credit. The Amended Credit Agreement matures on April 23, 2012. Collateral consists of 100% of the shares of stock of our material domestic subsidiaries and mortgages covering at least 75% of the total present value of our domestic oil and gas properties. At June 30, 2007, there was $375 million outstanding under the Amended Credit Agreement.

The Amended Credit Agreement 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 gas imbalance or take-or-pay 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 1.00.

At June 30, 2007, we had $9.7 million in letters of credit outstanding under the Amended Credit Agreement. At that date we were in compliance with the covenants contained in the Amended Credit Agreement and could have borrowed the full amount available under the Amended Credit Agreement. The effective interest rate on our borrowings under the Amended Credit Agreement was 6.375% at June 30, 2007.

30

Cash Flows

	Six Months Ended June 30,
	2007			2006
	(in millions)
Cash provided by (used in):
Operating activities	$	141.3		$	405.8
Investing activities		(1,308.8	)		(336.7	)
Financing activities		1,177.4			(69.2	)

Net cash provided by operating activities was $141.3 million in 2007 compared to $405.8 million in 2006. The decrease in net cash provided by operating activities in 2007 is primarily a result of (i) income tax payments of $94 million in 2007 primarily related to the 2006 property sales, (ii) lower operating income primarily related to the 2006 property sales, lower oil prices and increased operating expenses and (iii) the $37.9 million merger termination gain, net of certain merger related costs, received in 2006. As discussed below, certain of our derivative cash payments are classified as financing or investing activities.

Net cash used in investing activities was $1.3 billion in 2007 primarily reflecting 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. Net cash used in investing activities was $336.7 million in 2006 primarily reflecting additions to oil and gas properties of $289.4 million and derivative settlements of $42.7 million. 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 provided by financing activities in 2007 was $1.2 billion, primarily reflecting $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. Net cash used in financing activities in 2006 was $69.2 million, primarily reflecting $41.0 million in net repayments under our senior revolving credit facility and the payment of $28.6 million for financing derivative settlements. In 2006, certain of our derivatives are deemed to contain a significant financing element and cash settlements with respect to such derivatives are required to be reflected as financing activities.

Stock Repurchase Program

Our Board of Directors has authorized the repurchase of up to $500 million of our common stock. The shares will be repurchased from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. We expect that the funds for these purchases will come primarily from cash flow in excess of capital investments. Since the inception of the repurchase program we have made purchases totaling approximately $342 million under this program and we may expend an additional $158 million under the program.

Critical Accounting Policies and Factors that May Affect Future Results

Based on the accounting policies that we have in place, certain factors may impact our future financial results. Critical accounting policies related to commodity pricing and risk management activities, write-downs under full cost ceiling test rules, oil and gas reserves, 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, 2006.

Recent Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” which is effective for fiscal years beginning after November 15, 2007 and for interim periods within those years. This statement defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. We are currently evaluating the potential impact of this statement.

31

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115” which is effective for fiscal years beginning after November 15, 2007. This statement permits an entity to choose to measure many financial instruments and certain other items at fair value at specified election dates. Subsequent unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. We are currently evaluating the potential impact of this statement.

Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking information regarding Plains Exploration & Production Company that is intended to be covered by the safe harbor for “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995. Statements that are predictive in nature, that depend upon or refer to future events or conditions, or that include words such as “will”, “would”, “should”, “plans”, “likely”, “expects”, “anticipates”, “intends”, “believes”, “estimates”, “thinks”, “may”, and similar expressions, are forward-looking statements. Although we believe that our expectations are based on reasonable assumptions, there are risks, uncertainties and other factors that could cause actual results to be materially different from those in the forward-looking statements. These factors include, among other things:

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

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

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

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

• the success of our derivative activities;

• the success of our risk management activities;

• unexpected difficulties in integrating our operations as a result of any significant acquisitions, including the proposed acquisition of Pogo Producing Company;

• the effects of competition;

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

• the impact of current and future laws and governmental regulations;

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

• general economic, market, industry or business conditions.

All forward-looking statements in this report are made as of the date hereof, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report and our other filings with the SEC. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. Except for any obligation to disclose material information under the Federal securities laws, we do not intend to update these forward-looking statements and information. See Item 1A – “Risk Factors” and Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Factors That May Affect Future Results” in our Annual Report on Form 10-K for the year ended December 31, 2006 for additional discussions of risks and uncertainties.

32

Item 3 – Quantitative and Qualitative Disclosures About Market Risks

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, because the derivatives do not qualify or we have elected not to use hedge accounting. If a derivative is designated as a cash flow hedge and qualifies for hedge accounting, any unrealized gain or loss is deferred in OCI, a component of Stockholders’ Equity, until the hedged oil and gas production is sold. Realized gains and losses on derivative instruments that are designated as a hedge and qualify for hedge accounting are generally included in oil and gas revenues in the period the hedged volumes are sold. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain in OCI until the related product has been delivered.

See Note 3 to the Consolidated Financial Statements – “Derivative Instruments and Hedging Activities” for a discussion of our derivative activities.

At June 30, 2007, 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
2007
July - Dec	Put options	50,000 Bbls	$55.00 Strike price	WTI
2008
Jan - Dec	Put options	42,000 Bbls	$55.00 Strike price	WTI

The only cash settlements we are required to make on these put contracts are option premiums and interest, which are expected to total approximately $56 million in the last six months of 2007 and $58 million in 2008. Such amounts are not included in the fair value of derivatives not designated as hedging instruments in the following table.

The fair value of outstanding crude oil commodity derivative instruments at June 30, 2007 and the change in fair value that would be expected from a 10% price increase/decrease are shown in the table below (in millions):

	Fair Value		Effect of 10%
			Price Increase			Price Decrease
Derivatives not designated as hedging instruments	$	19.9	$	(10.3	)	$	21.4

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

33

The five financial institutions that are contract counterparties for our derivative commodity contracts all have Standard & Poor’s ratings of A or better and all such financial institutions are participating lenders in our revolving credit facility. At June 30, 2007 we were in a net liability position with all such counterparties. Our management intends to continue to maintain derivative arrangements for a portion of our production. These contracts may expose us to the risk of financial loss in certain circumstances.

34

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, 2007 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, 2007 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

35

PART II. OTHER INFORMATION

ITEM 2–Unregistered Sales of Equity Securities and Use of Proceeds

On May 31, 2007, we issued one million shares of our common stock to Laramie Energy, LLC as a portion of the purchase price of the Piceance Basin properties. The Piceance Basin properties include interests in oil and gas producing properties covering over 60,000 gross (55,000 net) acres in the Mesaverde geologic section of the Piceance Basin in Colorado, plus associated midstream assets, including a 25% interest in the Collbran Valley Gas Gathering, LLC. The foregoing transaction was made pursuant to Section 4(2) of the Securities Act.

Our Board of Directors has authorized the repurchase of up to $500 million 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 all repurchases by the Company of its common stock during the three month period ended June 30, 2007.

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, 2007	323,200	$	46.98	7,667,300	$	158,364,000

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

The following items were presented for approval to stockholders of record on March 22, 2007 at the Company’s 2007 annual meeting of stockholders, held on May 3, 2007 in Houston, Texas:

	For	Against	Abstained or Withheld
(i) Election of Directors
James C. Flores	61,786,817	—	464,903
Isaac Arnold, Jr.	62,066,939	—	184,781
Alan R. Buckwalter, III	62,077,685	—	174,035
Jerry L. Dees	59,595,350	—	2,656,370
Tom H. Delimitros	61,551,852	—	699,868
Robert L. Gerry, III	61,979,736	—	271,984
John H. Lollar	61,534,564	—	717,156
(ii) Amendments to the Company’s 2004 Stock Incentive Plan (a)	37,806,684	20,326,085	68,725
(iii) Ratification of PricewaterhouseCoopers LLP, independent certified public accountants, as auditors of the Company’s financial statements for the fiscal year ended December 31, 2007	62,186,749	51,266	13,705

(a) There were 4,050,226 broker non-votes.

Of the 72,498,189 shares of common stock issued and outstanding on March 22, 2007, 62,251,720 were present, either in person or by proxy.

36

ITEM 6 – Exhibits

1.1		Underwriting Agreement, dated June 13, 2007, 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 June 19, 2007 Form 8-K (the “June 19, 2007 Form 8-K”)).
4.1		Second Supplemental Indenture, dated June 5, 2007, to Indenture, dated March 13, 2007, between Plains Exploration & Production Company, the subsidiary guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.6 to the Company’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3 (file no. 333-141110) filed on June 11, 2007).
4.2		Third Supplemental Indenture, dated June 19, 2007, 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 7 3/4% Senior Notes due 2015) (incorporated by reference to Exhibit 4.2 to the June 19, 2007 Form 8-K).
4.3		Amended and Restated Credit Agreement dated as of May 31, 2007, among Plains Exploration & Production Company, as borrower, each of the lenders that is a signatory thereto, and JPMorgan Chase Bank as Administrative Agent (incorporated by reference to Exhibit 4.1 of the June 1, 2007 Form 8-K).
10.1		Amended and Restated Plains Exploration & Production Company 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the May 7, 2007 Form 8-K).
10.2	*	First Amendment to Employment Agreement effective as of November 8, 2006, and dated as of April 26, 2007, between Plains Exploration & Production Company and Winston M. Talbert.
10.3	*	First Amendment to Employment Agreement effective as of November 8, 2006, and dated as of April 26, 2007, between Plains Exploration & Production Company and Doss R. Bourgeois.
10.4		Asset Purchase and Sale Agreement dated April 18, 2007, between Laramie Energy, LLC and Plains Exploration & Production Company (incorporated by reference to Exhibit 10.1 to the April 24, 2007 Form 8-K (the “April 24, 2007 Form 8-K”)).
10.5		Membership Interests Purchase and Sale Agreement dated April 18, 2007 between Laramie Energy, LLC and Plains Exploration & Production Company (incorporated by reference to Exhibit 10.2 to the April 24, 2007 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.

37

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 7, 2007	By:	/s/ Winston M. Talbert
			Winston M. Talbert
			Executive Vice President and Chief Financial Officer (Principal Financial Officer)

38

EXHIBIT INDEX

Exhibit No.		Description
1.1		Underwriting Agreement, dated June 13, 2007, 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 June 19, 2007 Form 8-K (the “June 19, 2007 Form 8-K”)).
4.1		Second Supplemental Indenture, dated June 5, 2007, to Indenture, dated March 13, 2007, between Plains Exploration & Production Company, the subsidiary guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.6 to the Company’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3 (file no. 333-141110) filed on June 11, 2007).
4.2		Third Supplemental Indenture, dated June 19, 2007, 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 7 3/4% Senior Notes due 2015) (incorporated by reference to Exhibit 4.2 to the June 19, 2007 Form 8-K).
4.3		Amended and Restated Credit Agreement dated as of May 31, 2007, among Plains Exploration & Production Company, as borrower, each of the lenders that is a signatory thereto, and JPMorgan Chase Bank as Administrative Agent (incorporated by reference to Exhibit 4.1 of the June 1, 2007 Form 8-K).
10.1		Amended and Restated Plains Exploration & Production Company 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the May 7, 2007 Form 8-K).
10.2	*	First Amendment to Employment Agreement effective as of November 8, 2006, and dated as of April 26, 2007, between Plains Exploration & Production Company and Winston M. Talbert.
10.3	*	First Amendment to Employment Agreement effective as of November 8, 2006, and dated as of April 26, 2007, between Plains Exploration & Production Company and Doss R. Bourgeois.
10.4		Asset Purchase and Sale Agreement dated April 18, 2007, between Laramie Energy, LLC and Plains Exploration & Production Company (incorporated by reference to Exhibit 10.1 to the April 24, 2007 Form 8-K (the “April 24, 2007 Form 8-K”)).
10.5		Membership Interests Purchase and Sale Agreement dated April 18, 2007 between Laramie Energy, LLC and Plains Exploration & Production Company (incorporated by reference to Exhibit 10.2 to the April 24, 2007 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

39