- Quarterly Report (10-Q)

Three Months Ended March 31,

Gain on mark-to-market derivative contracts

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 March 31, 2010

¨ 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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


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

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

140.1 million shares of Common Stock, $0.01 par value, issued and outstanding at April 30, 2010.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


PART I. FINANCIAL INFORMATION

ITEM 1 . Unaudited Consolidated Financial Statements:

Consolidated Balance Sheets March 31, 2010 and December 31, 2009		1

Consolidated Statements of Income For the three months ended March 31, 2010 and 2009		2

Consolidated Statements of Cash Flows For the three months ended March 31, 2010 and 2009		3

Consolidated Statement of Stockholders’ Equity For the three months ended March 31, 2010		4

Notes to Consolidated Financial Statements		5

ITEM 2 . Management’s Discussion and Analysis of Financial Condition and Results of Operations		20

ITEM 3 . Quantitative and Qualitative Disclosures About Market Risk		28

ITEM 4 . Controls and Procedures		30

PART II. OTHER INFORMATION		31

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)


	March 31, 2010		December 31, 2009
ASSETS
Current Assets
Cash and cash equivalents	$	60,746	$	1,859
Accounts receivable		193,368		258,585
Commodity derivative contracts		24,728		11,952
Inventories		17,871		19,934
Prepaid expenses and other current assets		25,626		14,305

		322,339		306,635

Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		9,403,577		9,044,146
Not subject to amortization		3,143,352		3,279,537
Other property and equipment		127,804		125,667

		12,674,733		12,449,350
Less allowance for depreciation, depletion, amortization and impairment		(5,736,965)		(5,616,628)

		6,937,768		6,832,722

Goodwill		535,237		535,237

Other Assets		61,314		60,137

	$	7,856,658	$	7,734,731

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	196,662	$	248,454
Commodity derivative contracts		54,322		59,176
Royalties and revenues payable		77,351		78,590
Interest payable		50,542		45,743
Deferred income taxes		109,126		153,473
Other current liabilities		87,320		97,115

		575,323		682,551

Long-Term Debt		2,720,962		2,649,689

Other Long-Term Liabilities
Asset retirement obligation		218,634		214,231
Other		50,578		55,531

		269,212		269,762

Deferred Income Taxes		1,020,719		933,748

Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common stock, $0.01 par value, 250.0 million shares authorized, 143.9 million shares issued at March 31, 2010 and December 31, 2009		1,439		1,439
Additional paid-in capital		3,361,383		3,381,566
Retained earnings		106,517		51,204
Treasury stock, at cost, 3.8 million shares and 4.5 million shares at March 31, 2010 and December 31, 2009, respectively		(198,897)		(235,228)

		3,270,442		3,198,981

	$	7,856,658	$	7,734,731

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)


	Three Months Ended March 31,
	2010		2009
Revenues
Oil sales	$	276,004	$	156,614
Gas sales		107,739		71,264
Other operating revenues		307		634

		384,050		228,512

Costs and Expenses
Lease operating expenses		62,503		70,884
Steam gas costs		19,663		15,557
Electricity		10,034		10,942
Production and ad valorem taxes		8,447		11,621
Gathering and transportation expenses		9,419		6,647
General and administrative		37,390		37,093
Depreciation, depletion and amortization		122,393		88,114
Accretion		4,411		3,531
Legal recovery		(8,423)		-
Other operating (income) expense		(569)		4,457

		265,268		248,846

Income (Loss) from Operations		118,782		(20,334)
Other (Expense) Income
Interest expense		(21,053)		(21,997)
Debt extinguishment costs		(728)		(10,243)
Gain on mark-to-market derivative contracts		7,856		88,139
Other income (expense)		1,306		(707)

Income Before Income Taxes		106,163		34,858
Income tax (expense) benefit
Current		(4,738)		(55,791)
Deferred		(42,897)		26,131

Net Income	$	58,528	$	5,198

Earnings per Share
Basic	$	0.42	$	0.05
Diluted	$	0.41	$	0.05
Weighted Average Shares Outstanding
Basic		139,741		107,755

Diluted		141,940		108,224

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)


	Three Months Ended March 31,
	2010		2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	58,528	$	5,198
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		122,393		88,114
Accretion		4,411		3,531
Deferred income tax expense (benefit)		42,897		(26,131)
Debt extinguishment costs		728		10,243
Gain on mark-to-market derivative contracts		(7,856)		(88,139)
Noncash compensation		16,900		14,499
Other noncash items		1,371		1,826
Change in assets and liabilities from operating activities
Accounts receivable and other assets		263		42,949
Accounts payable and other liabilities		(31,262)		(29,237)
Income taxes receivable/payable		13,405		(52,204)

Net cash provided by (used in) operating activities		221,778		(29,351)

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(267,015)		(416,350)
Acquisition of oil and gas properties		51,065		-
Derivative settlements		(9,460)		1,294,157
Additions to other property and equipment		(2,137)		(5,819)

Net cash (used in) provided by investing activities		(227,547)		871,988

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		625,935		2,240,090
Repayments of revolving credit facilities		(855,935)		(3,545,090)
Proceeds from issuance of Senior Notes		300,000		337,161
Costs incurred in connection with financing arrangements		(5,344)		(6,541)
Derivative settlements		-		1,392

Net cash provided by (used in) financing activities		64,656		(972,988)

Net increase (decrease) in cash and cash equivalents		58,887		(130,351)
Cash and cash equivalents, beginning of period		1,859		311,875

Cash and cash equivalents, end of period	$	60,746	$	181,524

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)


	Common Stock			Additional Paid-in Capital		Retained Earnings		Treasury Stock			Total
	Shares	Amount		Additional Paid-in Capital		Retained Earnings		Shares	Amount		Total
Balance at December 31, 2009	143,924	$	1,439	$	3,381,566	$	51,204	(4,512)	$	(235,228)	$	3,198,981
Net income	-		-		-		58,528	-		-		58,528
Restricted stock awards	-		-		12,929		-	-		-		12,929
Issuance of treasury stock for restricted stock awards	-		-		(33,112)		(3,215)	679		36,331		4

Balance at March 31, 2010	143,924	$	1,439	$	3,361,383	$	106,517	(3,833)	$	(198,897)	$	3,270,442

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1—Summary of Significant Accounting Policies

Plains Exploration & Production Company, a Delaware corporation formed in 2002 (“PXP”, “us”, “our” or “we”), is an independent energy company engaged in the “upstream” oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are primarily located in the United States. We also have an interest in an exploration block offshore Vietnam.

Our consolidated financial statements include the accounts of all our 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. 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 period, have been reflected. The results of our operations for the three months ended March 31, 2010 are not necessarily indicative of the results to be expected for the full year.

These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or 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 consolidated 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, 2009.

Asset Retirement Obligation . The following table reflects the changes in our asset retirement obligation during the three months ended March 31, 2010 (in thousands):


Asset retirement obligation - December 31, 2009	$	221,367
Settlements		(520)
Accretion expense		4,411
Asset retirement additions		350

Asset retirement obligation - March 31, 2010 ⁽¹⁾	$	225,608

(1)

$7.0 million is included in other current liabilities.

Earnings Per Share. For the three months ended March 31, 2010 and 2009 the weighted average shares outstanding for computing basic and diluted earnings per share were (in thousands):


	Three Months Ended March 31,
	2010	2009
Weighted average common shares outstanding - basic	139,741	107,755
Unvested restricted stock, restricted stock units and stock options	2,199	469

Weighted average shares outstanding - diluted	141,940	108,224

In the first quarter of 2010 and 2009, 12,660 and 3.4 million restricted stock units, respectively, were excluded in computing diluted earnings per share because they were antidilutive due to the impact of the unrecognized compensation cost on the calculation of assumed proceeds in the application of the treasury stock method. In computing earnings per share, no adjustments were made to reported net income.

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 consisted of (in thousands):


	March 31, 2010		December 31, 2009
Oil	$	6,474	$	6,488
Materials and supplies		11,397		13,446

	$	17,871	$	19,934

Stock Based Compensation. Stock based compensation for the three months ended March 31, 2010 was $21.7 million, of which $14.6 million is included in general and administrative expense (“G&A”), $2.3 million is included in lease operating expense and $4.8 million is included in oil and natural gas properties. Stock based compensation for the three months ended March 31, 2009 was $17.9 million, of which $14.5 million was included in G&A and $3.4 million was included in oil and natural gas properties.

During the first quarter of 2010, we granted 1.5 million restricted stock units at an average fair value of $31.58 per share and 837 thousand stock appreciation rights with an average exercise price of $31.59 per share.

Recent Accounting Pronouncements . In February 2010, the Financial Accounting Standards Board, or FASB, issued authoritative guidance on subsequent events that removes the requirement for an SEC filer to disclose the date through which subsequent events have been evaluated in both issued and revised financial statements. This guidance was effective upon issuance. The adoption of the subsequent events standard did not have a significant impact on our consolidated financial position, results of operations or cash flows.

In June 2009, the FASB issued authoritative guidance for improving financial reporting by enterprises involved with variable interest entities. This guidance eliminates the exemption for qualifying special purpose entities, includes a new approach for determining who should consolidate a variable interest entity, and presents changes as to when it is necessary to reassess who should consolidate a variable interest entity. The guidance is effective for fiscal years beginning after November 15, 2009, and for interim periods within that first annual reporting period. We adopted the provisions of this standard effective January 1, 2010 and it did not have a significant impact on our consolidated financial position, results of operations or cash flows.

Note 2—Long-Term Debt

At March 31, 2010 and December 31, 2009, long-term debt consisted of (in thousands):


	March 31, 2010		December 31, 2009
Senior revolving credit facility	$	-	$	230,000
7 ³ / 4 % Senior Notes due 2015		600,000		600,000
10% Senior Notes due 2016 ⁽¹⁾		527,389		526,222
7% Senior Notes due 2017		500,000		500,000
7 ⁵ / 8 % Senior Notes due 2018		400,000		400,000
8 ⁵ / 8 % Senior Notes due 2019 ⁽²⁾		393,573		393,467
7 ⁵ / 8 % Senior Notes due 2020		300,000		-

	$	2,720,962	$	2,649,689


(1) The amount is net of unamortized discount of $37.6 million and $38.8 million at March 31, 2010 and December 31, 2009, respectively.
(2) The amount is net of unamortized discount of $6.4 million and $6.5 million at March 31, 2010 and December 31, 2009, respectively.

Amounts borrowed under our senior revolving credit facility bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 2.00% to 2.75%; (ii) the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus ¹ / 2 of 1%, and (3) the adjusted LIBOR rate plus 1%; or (iii) the over-night federal funds rate plus an additional variable amount ranging from 2.00% to 2.75% for swingline loans. The additional variable amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under our senior revolving credit facility to the conforming borrowing base and (2) our long-term debt ratings. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and our long-term debt rating and range from 2.0% to 2.75%. Commitment fees are 0.50% of the amount available for borrowing.

Our senior revolving credit facility is secured by 100% of the shares of stock in certain of our domestic and 65% of the shares of stock in certain foreign subsidiaries and mortgages covering at least 75% of the total present value of our domestic oil and gas properties. Our senior revolving credit facility contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries to, among other things, incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into take-or-pay or other prepayment arrangements, merge or consolidate and enter into transactions with affiliates. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined) of no greater than 4.25 to 1.

In March 2010, we issued $300 million of 7 ⁵ / 8 % Senior Notes due 2020, or 7 ⁵ / 8 % Senior Notes, which were sold to the public at par. We received approximately $294 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes. We may redeem all or part of the 7 ⁵ / 8 % Senior Notes on or after April 1, 2015 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to April 1, 2013 we may, at our option, redeem up to 35% of the 7 ⁵ / 8 % Senior Notes with the proceeds of certain equity offerings. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 7 ⁵ / 8 % Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 7 ⁵ / 8 % Senior Notes are general unsecured senior obligations. They are jointly and severally guaranteed on a full and unconditional basis by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. These 7 ⁵ / 8 % 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 ⁵ / 8 % 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.

Subsequent Event

On April 12, 2010, we entered into an amendment to our senior revolving credit facility. The amendment increased the borrowing base to $1.3 billion from $1.13 billion. In addition, the amendment allows us to increase our investments in certain subsidiaries and joint ventures.

Note 3—Commodity Derivative Contracts

General

We are exposed to various market risks, including volatility in oil and gas commodity prices, interest rates and foreign currency exchange rates. The level of derivative activity we engage in depends on our view of market conditions,

available derivative prices and operating strategy. A variety of derivative instruments, such as swaps, collars, puts, calls and various combinations of these instruments, may be utilized to manage our exposure to the volatility of oil and gas commodity prices. Currently, we do not use derivatives to manage our interest rate or foreign currency risk. The interest rate on our senior revolving credit facility is variable, while our senior notes are at fixed interest rates, thereby mitigating our interest rate risk exposure. Our foreign currency risk in Vietnam has been minimal due to the size of our operations.

All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized 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. The derivative instruments we have in place are not classified as hedges for accounting purposes.

Cash settlements with respect to derivatives that contain a significant financing element are reflected as financing activities in the statement of cash flows. Cash settlements with respect to derivatives that are not accounted for under hedge accounting and do not have a significant financing element are reflected as investing activities in the statement of cash flows.

For put options, we pay a premium to the counterparty in exchange for the sale of a put option. If the index price is below the strike price of the put option, we receive the difference between the strike price and the index price multiplied by the contract volumes less the premium. If the market price settles at or above the strike price of the put option, we pay only the option premium.

In a typical collar transaction, if the floating price based on a market index is below the floor price in the derivative contract, we receive from the counterparty an amount equal to this difference multiplied by the specified volume. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, we must pay the counterparty an amount equal to the difference multiplied by the specified volume. We may pay a premium to the counterparty in exchange for a certain floor or ceiling. Any premium reduces amounts we would receive under the floor or increases amounts we would pay above the ceiling. If the floating price exceeds the floor price or is less than the ceiling price, then no payment, other than the premium, is required. If we have less production than the volumes specified under the collar transaction when the floating price exceeds the ceiling price, we must make payments against which there is no offsetting revenues from production.

See Note 4 – Fair Value Measurements of Assets and Liabilities, for additional discussion on the fair value measurement of our derivative contracts.

As of March 31, 2010, we had the following outstanding commodity derivative contracts, all of which settle monthly, and none of which were designated as hedging instruments:


Period	Instrument Type	Daily Volumes	Average Price ⁽¹⁾	Average Deferred Premium	Index
Sales of Crude Oil Production
2010
Apr - Dec	Put options	40,000 Bbls	$55.00 Strike price	$5.00 per Bbl ⁽²⁾	WTI

Sales of Natural Gas Production
2010
Apr - Dec	Three-way collars ⁽³⁾	85,000 MMBtu	$6.12 Floor with a $4.64 Limit $8.00 Ceiling	$0.034 per MMBtu	Henry Hub

(1)

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

(2)

In addition to the deferred premium, a premium averaging $3.86 per barrel was paid upon entering into these derivative contracts.

(3)

If the index price is less than the $6.12 per MMBtu floor, we receive the difference between the $6.12 per MMBtu floor and the index price up to a maximum of $1.48 per MMBtu. We pay the difference between the index price and $8.00 per MMBtu if the index price is greater than the $8.00 ceiling.

Balance Sheet

At March 31, 2010 and December 31, 2009, we had the following outstanding commodity derivative contracts, none of

which were designated as hedging instruments, recorded in our balance sheets (in thousands):


Instrument Type	Balance Sheet Classification	Estimated Fair Value
Instrument Type	Balance Sheet Classification	March 31, 2010		December 31, 2009
Crude oil puts	Commodity derivative contracts - current assets	$	3,273	$	15,173
Natural gas collars	Commodity derivative contracts - current assets		28,724		14,312

Total derivative instruments		$	31,997	$	29,485

The following table provides supplemental information to reconcile the fair value of the derivative contracts to our consolidated balance sheets at March 31, 2010 and December 31, 2009, considering the deferred premiums and accrued interest and related settlement payable amounts, which are not included in the fair value amounts disclosed in the table above (in thousands):


	March 31, 2010		December 31, 2009
Net fair value asset	$	31,997	$	29,485
Deferred premium and accrued interest on derivative contracts		(55,391)		(73,305)
Settlement payable		(6,200)		(3,404)

Net commodity derivative liability	$	(29,594)	$	(47,224)


Commodity derivative contracts - current asset	$	24,728	$	11,952
Commodity derivative contracts - current liability		(54,322)		(59,176)

	$	(29,594)	$	(47,224)

We present the fair value of our derivative contracts on a net basis where the right of offset is provided for in our counterparty agreements.

Income Statement

During the three months ended March 31, 2010 and 2009, pre-tax amounts recognized in our income statement were as follows (in thousands):

Cash Payments and Receipts

During the three months ended March 31, 2010 and 2009, cash (payments) receipts for derivatives were as follows (in thousands):


	Three Months Ended March 31,
	2010		2009
Oil derivatives
Settlements	$	(14,549)	$	156,876
Monetization of crude oil puts and swaps		-		1,074,361
Natural gas derivatives		5,089		64,312

	$	(9,460)	$	1,295,549

Credit Risk

We generally do not require collateral or other security to support derivative instruments subject to credit risk. However, the agreements with each of the counterparties to our derivative instruments contain netting provisions within the agreements. If a default occurs under the agreements, the non-defaulting party can offset the amount payable to the defaulting party under the derivative contracts with the amount due from the defaulting party under the derivatives contracts. As a result of the netting provisions under the agreements, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. The maximum amount of loss due to credit risk that we would have incurred if all the counterparties to our derivative contracts failed to perform according to the terms of the derivative contracts at March 31, 2010 was $24.8 million.

Contingent Features

As of March 31, 2010, the counterparties to our commodity derivative contracts consist of six financial institutions. Our counterparties or their affiliates are generally also lenders under our senior revolving credit facility. As a result, the counterparties to our derivative agreements share in the collateral supporting our senior revolving credit facility. Therefore, we are not generally required to post additional collateral under our derivative agreements.

Certain of our derivative agreements contain provisions that require cross defaults and acceleration of those instruments to any material debt. If we were to default on any of our material debt agreements, it would be a violation of these provisions, and the counterparties to the derivative instruments could request immediate payment on derivative instruments that are in a net liability position at that time. As of March 31, 2010, we were in a net liability position with three of the counterparties to our derivative instruments, totaling $54.3 million.

Subsequent Event

In April 2010, we entered into crude oil put option spread contracts on 31,000 barrels of oil per day in 2011 and 40,000 barrels of oil per day in 2012. Both the 2011 and 2012 put options have a floor price of $80 with a limit of $60 per barrel. Under these agreements, if the index price is below $80 per barrel, we receive the difference between the floor price of $80 and the index price up to a maximum of $20 per barrel less the option premium. If the index price is at or above $80 per barrel, we pay only the option premium. The average deferred premium plus interest on the above contracts is $5.023 per barrel for 2011 and $6.087 per barrel for 2012.

Additionally, we acquired crude oil three-way collars that have a floor price of $80 with a limit of $60 and a ceiling price of $110 on 9,000 barrels of oil per day for 2011. Under these agreements, if the index price is below $80 per barrel, we receive the difference between the floor price of $80 and the index price up to a maximum of $20 per barrel less the option premium. If the index price is greater than $110 per barrel, we pay the difference between the index price and the ceiling price of $110 per barrel plus the option premium. If the index price is at or above $80 per barrel but at or below $110 per barrel, we pay only the option premium. The average deferred premium plus interest on the above contracts is $1.00 per barrel.

Note 4—Fair Value Measurements of Assets and Liabilities

Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. We follow a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Our commodity derivative instruments are recorded at fair value on a recurring basis in our consolidated balance sheets with the changes in fair value recorded in our consolidated statements of income. The following table presents, for each fair value hierarchy level, our commodity derivative assets and liabilities measured at fair value on a recurring basis as of March 31, 2010 and December 31, 2009 (in thousands):


	Fair Value ⁽¹⁾		Fair Value Measurements at Reporting Date Using
	Fair Value ⁽¹⁾		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
March 31, 2010
Crude oil puts	$	3,273	$	-	$	3,273	$	-
Natural gas collars		28,724		-		-		28,724

	$	31,997	$	-	$	3,273	$	28,724

December 31, 2009
Crude oil puts	$	15,173	$	-	$	15,173	$	-
Natural gas collars		14,312		-		-		14,312

	$	29,485	$	-	$	15,173	$	14,312

(1)

Option premium and accrued interest of $55.4 million in 2010 and $73.3 million in 2009 and settlement payable of $6.2 million in 2010
and $3.4 million in 2009 are not included in the fair value of derivatives.

The fair value amounts of our derivative instruments are estimated using an option-pricing model, which uses various inputs including NYMEX price quotations, volatilities, interest rates and contract terms. We adjust the valuations from the model for credit quality, using the counterparties’ credit quality for asset balances and our credit quality for liability balances. For asset balances, we use the credit default swap value for counterparties when available, or the spread between the risk-free interest rate and the yield on the counterparties’ publicly-traded debt for similar maturities. We consider the impact of netting agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability.

We classify derivatives that have identical assets or liabilities with quoted, unadjusted prices in active markets as Level 1. We classify our derivatives as Level 2 if the inputs used in the valuation model are directly or indirectly observable for substantially the full term of the instrument; however, if the significant inputs are not observable for substantially the full term of the instrument, we classify those derivatives as Level 3. We determine whether the market for our derivative instruments is active or inactive based on transaction volume for such instruments and classify as Level 3 those instruments that are not actively traded. For these inputs, we utilize pricing and volatility information from other instruments with similar characteristics and extrapolate data between data points for thinly traded instruments. As of March 31, 2010, our crude oil put options are classified as Level 2, and our natural gas collars are classified as Level 3 instruments. We determine the appropriate level for each financial asset and liability on a quarterly basis and recognize any transfers at the beginning of the reporting period.

The following table presents a reconciliation of changes in fair value of financial assets and liabilities classified as Level 3 for the three months ended March 31, 2010 and 2009 (in thousands):


	Commodity Derivative Contracts ⁽¹⁾
	Three Months Ended March 31,
	2010		2009
Fair value at beginning of period	$	14,312	$	1,790,718
Transfers ⁽²⁾		-		(124,690)
Realized and unrealized gains included in earnings ⁽³⁾		19,757		187,897
Purchases		-		(127,202)
Settlements		(5,345)		(1,493,962)

Fair value at end of period	$	28,724	$	232,761


Change in unrealized gains and losses relating to assets and liabilities held as of the end of the period ⁽³⁾	$	18,100	$	17,369

(1)

Deferred option premiums and interest are not included in the fair value of derivatives.

(2)

During the first quarter of 2009, the inputs used to value our $55 crude put options were directly or indirectly observable and our $55 crude puts were transferred to Level 2.

(3)

Realized and unrealized gains included in earnings for the period are reported as gain on mark-to-market derivative contracts in our consolidated statements of income.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Nonfinancial assets and liabilities, such as goodwill and other property and equipment, are measured at fair value on a nonrecurring basis upon impairment; however, we have no material assets or liabilities that are reported at fair value on a nonrecurring basis in our consolidated balance sheets.

Fair Value of Other Financial Instruments

Authoritative guidance on financial instruments requires certain fair value disclosures, such as those on our long-term debt, to be presented in both interim and annual reports. The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.

The carrying values of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. Derivative financial instruments included in our consolidated balance sheets are stated at fair value; however, certain of our derivative financial instruments have a deferred premium, including our crude oil put option contracts and natural gas collars. The deferred premium reduces the asset or increases the liability depending on the fair value of the derivative financial instrument.

The following table presents the carrying amounts and fair values of our other financial instruments as of March 31, 2010 and December 31, 2009 (in thousands):


	March 31, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Current Liability
Deferred premium and accrued interest on derivative contracts	$	55,391	$	55,391	$	73,305	$	73,305
Long-Term Debt
Senior revolving credit facility		-		-		230,000		230,000
7 ³ / 4 % Senior Notes		600,000		608,250		600,000		610,500
10% Senior Notes		527,389		624,325		526,222		618,675
7% Senior Notes		500,000		492,500		500,000		491,250
7 ⁵ / 8 % Senior Notes		400,000		404,000		400,000		409,000
8 ⁵ / 8 % Senior Notes		393,573		424,000		393,467		411,000
7 ⁵ / 8 % Senior Notes		300,000		297,000		-		-

The carrying value of our senior revolving credit facility approximates fair value, as interest rates are variable, based on prevailing market rates. The fair value of our Senior Notes is based on quoted market prices from trades of such debt.

Note 5—Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate plus any significant unusual or infrequently occurring items which are recorded in the period that the specific item occurs. For the three months ended March 31, 2010, income tax expense was approximately 45% of pre-tax income. The variance in our estimated annual effective tax rate from the 35% federal statutory rate primarily results from the tax effects of estimated annual permanent differences, including (1) expenses that are not deductible because of Internal Revenue Service limitations, and (2) state income taxes. Specific items affecting income tax expense for the first quarter included adjustments to deferred taxes for differences in the reporting of stock based compensation expenses for financial statement and income tax reporting purposes and changes to our balance of accrued interest recorded on unrecognized tax benefits.

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 100 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 be assured 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, $59 million ($114 million undiscounted), is included in our asset retirement obligation as reflected on our consolidated balance sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $67 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At March 31, 2010, the escrow account had a balance of $14.7 million. The fair value of our guarantee at March 31, 2010, $0.7 million, considers the payment/performance risk of the purchaser and is included in other long-term liabilities in the consolidated balance sheet.

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

In the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers. While there are signs that the economy may be improving, business conditions may remain challenging. Volatility and disruption in the financial and credit markets may adversely affect the credit quality of our insurers and impact their ability to pay out claims.

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 these commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

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

Note 7—Consolidating Financial Statements

We are the issuer of $600 million of 7 ³ / 4 % Senior Notes, $565 million of 10% Senior Notes, $500 million of 7% Senior Notes, $400 million of 7 ⁵ / 8 % Senior Notes, $400 million of 8 ⁵ / 8 % Senior Notes and $300 million of 7 ⁵ / 8 % Senior Notes as of March 31, 2010, 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.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

MARCH 31, 2010

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	58,664		$	8		$	2,074		$	-	$	60,746
Accounts receivable and other current assets		162,061			120,177			1,344			(21,989)		261,593

		220,725			120,185			3,418			(21,989)		322,339

Property and Equipment, at cost
Oil and natural gas properties - full cost method		4,240,487			8,247,860			58,582			-		12,546,929
Other property and equipment		50,115			35,648			42,041			-		127,804

		4,290,602			8,283,508			100,623			-		12,674,733
Less allowance for depreciation, depletion, amortization and impairment		(2,266,239	)		(5,375,717	)		(1	)		1,904,992		(5,736,965	)

		2,024,363			2,907,791			100,622			1,904,992		6,937,768

Investment in and Advances to Affiliates		4,697,668			(1,715,793	)		(55,416	)		(2,926,459)		-

Other Assets		56,846			539,705			-			-		596,551


	$	6,999,602		$	1,851,888		$	48,624		$	(1,043,456)	$	7,856,658

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$	423,864		$	169,537		$	3,911		$	(21,989)	$	575,323
Long-Term Debt		2,720,962			-			-			-		2,720,962
Other Long-Term Liabilities		206,124			63,088			-			-		269,212
Deferred Income Taxes		378,210			(115,965	)		5,501			752,973		1,020,719
Stockholders’ Equity		3,270,442			1,735,228			39,212			(1,774,440)		3,270,442


	$	6,999,602		$	1,851,888		$	48,624		$	(1,043,456)	$	7,856,658

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2009

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1,304		$	11		$	544		$	-		$	1,859
Accounts receivable and other current assets		210,625			113,320			2,820			(21,989	)		304,776

		211,929			113,331			3,364			(21,989	)		306,635

Property and Equipment, at cost
Oil and natural gas properties - full cost method		4,161,478			8,104,424			57,781			-			12,323,683
Other property and equipment		49,403			35,648			40,616			-			125,667

		4,210,881			8,140,072			98,397			-			12,449,350
Less allowance for depreciation, depletion, amortization and impairment		(2,212,695	)		(5,346,513	)		(14	)		1,942,594			(5,616,628	)

		1,998,186			2,793,559			98,383			1,942,594			6,832,722

Investment in and Advances to Affiliates		4,668,480			(1,650,163	)		(68,081	)		(2,950,236	)		-

Other Assets		55,994			539,380			-			-			595,374


	$	6,934,589		$	1,796,107		$	33,666		$	(1,029,631	)	$	7,734,731

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$	528,157		$	171,529		$	4,854		$	(21,989	)	$	682,551
Long-Term Debt		2,649,689			-			-			-			2,649,689
Other Long-Term Liabilities		207,035			62,727			-			-			269,762
Deferred Income Taxes		350,727			(151,610	)		5,699			728,932			933,748
Stockholders’ Equity		3,198,981			1,713,461			23,113			(1,736,574	)		3,198,981


	$	6,934,589		$	1,796,107		$	33,666		$	(1,029,631	)	$	7,734,731

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED MARCH 31, 2010

(in thousands of dollars)


	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	234,175	$	41,829	$	-	$	-	$	276,004
Gas sales		25,514		82,225		-		-		107,739
Other operating revenues		106		201		-		-		307

		259,795		124,255		-		-		384,050

Costs and Expenses
Production costs		75,460		34,606		-		-		110,066
General and administrative		24,858		12,527		5		-		37,390
Depreciation, depletion, amortization and accretion		59,134		30,067		-		37,603		126,804
Legal recovery		-		(8,423)		-		-		(8,423)
Other operating income		-		(569)		-		-		(569)

		159,452		68,208		5		37,603		265,268

Income (Loss) from Operations		100,343		56,047		(5)		(37,603)		118,782
Other (Expense) Income
Equity in earnings of subsidiaries		(386)		129		-		257		-
Interest expense		(13)		(20,509)		(531)		-		(21,053)
Debt extinguishment costs		(728)		-		-		-		(728)
Gain on mark-to-market derivative contracts		7,856		-		-		-		7,856
Other income		615		594		97		-		1,306

Income (Loss) Before Income Taxes		107,687		36,261		(439)		(37,346)		106,163
Income tax (expense) benefit		(49,159)		(14,494)		198		15,820		(47,635)


Net Income (Loss)	$	58,528	$	21,767	$	(241)	$	(21,526)	$	58,528

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED MARCH 31, 2009

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	130,608		$	26,006		$	-		$	-		$	156,614
Gas sales		17,694			53,570			-			-			71,264
Other operating revenues		321			313			-			-			634

		148,623			79,889			-			-			228,512

Costs and Expenses
Production costs		76,762			38,889			-			-			115,651
General and administrative		26,939			9,977			177			-			37,093
Depreciation, depletion, amortization and accretion		52,584			40,440			4			(1,383	)		91,645
Impairment of oil and gas properties		-			636,227			-			(636,227	)		-
Other operating expense		4,457			-			-			-			4,457

		160,742			725,533			181			(637,610	)		248,846

(Loss) Income from Operations		(12,119	)		(645,644	)		(181	)		637,610			(20,334	)
Other (Expense) Income
Equity in earnings of subsidiaries		(70,269	)		(193	)		-			70,462			-
Interest expense		(7,313	)		(14,684	)		-			-			(21,997	)
Debt extinguishment costs		(10,243	)		-			-			-			(10,243	)
Gain on mark-to-market derivative contracts		88,139			-			-			-			88,139
Other expense		(84	)		(611	)		(12	)		-			(707	)

(Loss) Income Before Income Taxes		(11,889	)		(661,132	)		(193	)		708,072			34,858
Income tax benefit (expense)		17,087			249,322			-			(296,069	)		(29,660	)


Net Income (Loss)	$	5,198		$	(411,810	)	$	(193	)	$	412,003		$	5,198

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

THREE MONTHS ENDED MARCH 31, 2010

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	58,528		$	21,767		$	(241	)	$	(21,526	)	$	58,528
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		59,134			30,067			-			37,603			126,804
Equity in earnings of subsidiaries		386			(129	)		-			(257	)		-
Deferred income tax (benefit) expense		(16,591	)		35,645			(198	)		24,041			42,897
Debt extinguishment costs		728			-			-			-			728
Gain on mark-to-market derivative contracts		(7,856	)		-			-			-			(7,856	)
Noncash compensation		13,225			3,675			-			-			16,900
Other noncash items		1,367			4			-			-			1,371
Change in assets and liabilities from operating activities
Accounts receivable and other assets		6,582			(6,987	)		668			-			263
Accounts payable and other liabilities		(28,335	)		(2,921	)		(6	)		-			(31,262	)
Income taxes receivable/payable		13,405			-			-			-			13,405

Net cash provided by operating activities		100,573			81,121			223			39,861			221,778


CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(123,009	)		(143,076	)		(930	)		-			(267,015	)
Acquisition of oil and gas properties		-			51,065			-			-			51,065
Derivative settlements		(9,460	)		-			-			-			(9,460	)
Additions to other property and equipment		(712	)		(1	)		(1,424	)		-			(2,137	)

Net cash used in investing activities		(133,181	)		(92,012	)		(2,354	)		-			(227,547	)


CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		625,935			-			-			-			625,935
Repayments of revolving credit facilities		(855,935	)		-			-			-			(855,935	)
Proceeds from issuance of Senior Notes		300,000			-			-			-			300,000
Costs incurred in connection with financing arrangements		(5,344	)		-			-			-			(5,344	)
Investment in and advances to affiliates		25,312			10,888			3,661			(39,861	)		-

Net cash provided by financing activities		89,968			10,888			3,661			(39,861	)		64,656

Net increase (decrease) in cash and cash equivalents		57,360			(3	)		1,530			-			58,887
Cash and cash equivalents, beginning of period		1,304			11			544			-			1,859

Cash and cash equivalents, end of period	$	58,664		$	8		$	2,074		$	-		$	60,746

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

THREE MONTHS ENDED MARCH 31, 2009

(in thousands of dollars)


	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	5,198		$	(411,810	)	$	(193	)	$	412,003		$	5,198
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		52,584			676,667			4			(637,610	)		91,645
Equity in earnings of subsidiaries		70,269			193			-			(70,462	)		-
Deferred income tax expense (benefit)		180,738			(237,462	)		-			30,593			(26,131	)
Debt extinguishment costs		10,243			-			-			-			10,243
Gain on mark-to-market derivative contracts		(88,139	)		-			-			-			(88,139	)
Noncash compensation		12,860			1,639			-			-			14,499
Other noncash items		1,816			10			-			-			1,826
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(11,508	)		54,462			(5	)		-			42,949
Accounts payable and other liabilities		1,314			(30,538	)		(13	)		-			(29,237	)
Income taxes receivable/payable		(52,204	)		-			-			-			(52,204	)

Net cash provided by (used in) operating activities		183,171			53,161			(207	)		(265,476	)		(29,351	)


CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(197,918	)		(216,513	)		(1,919	)		-			(416,350	)
Derivative settlements		1,294,157			-			-			-			1,294,157
Additions to other property and equipment		(2,358	)		121			(3,582	)		-			(5,819	)

Net cash provided by (used in) investing activities		1,093,881			(216,392	)		(5,501	)		-			871,988


CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		2,240,090			-			-			-			2,240,090
Repayments of revolving credit facilities		(3,545,090	)		-			-			-			(3,545,090	)
Proceeds from issuance of Senior Notes		337,161			-			-			-			337,161
Costs incurred in connection with financing arrangements		(6,541	)		-			-			-			(6,541	)
Derivative settlements		1,392			-			-			-			1,392
Investment in and advances to affiliates		(432,780	)		162,964			4,340			265,476			-

Net cash (used in) provided by financing activities		(1,405,768	)		162,964			4,340			265,476			(972,988	)

Net decrease in cash and cash equivalents		(128,716	)		(267	)		(1,368	)		-			(130,351	)
Cash and cash equivalents, beginning of period		309,362			285			2,228			-			311,875

Cash and cash equivalents, end of period	$	180,646		$	18		$	860		$	-		$	181,524

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, 2009.

Company Overview

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

•

Onshore California;

•

Offshore California;

•

the Gulf Coast Region;

•

the Gulf of Mexico;

•

the Mid-Continent Region; and

•

the Rocky Mountains.

We also have an interest in an exploration block offshore Vietnam.

Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities, including our significant Haynesville Shale acreage position and our Gulf of Mexico exploration discoveries. Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum fixed amount specified in the derivative agreement and subjects us to the credit risk of the counterparties to such agreements. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on derivative contracts on our income statement as changes occur in the NYMEX price indices. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. See Item 3 – Quantitative and Qualitative Disclosures About Market Risk.

General

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, and development activities are capitalized. Our revenues are derived from the sale of oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SEC’s full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. These rules generally require that we price our future oil and gas production at the twelve-month average first-day-of-the-month reference prices as adjusted for location and quality differentials to determine a ceiling value of our properties. Prior to the fourth quarter of 2009, we were required to price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts that qualify and are designated for hedge accounting treatment. The derivative instruments we have

in place are not classified as hedges for accounting purposes. The rules require an impairment if our capitalized costs exceed the allowed “ceiling.” At March 31, 2010, the ceiling with respect to our oil and gas properties exceeded the net capitalized costs of those properties by approximately 11%.

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 change in the near term. If oil and gas prices decline in the future, impairments of our oil and gas properties could occur. Impairment charges required by these rules do not directly impact our cash flows from operating activities.

Our oil and gas production expenses include salaries and benefits of personnel involved in production activities (including stock based compensation), steam gas costs, electricity costs, maintenance costs, production, ad valorem and severance taxes, and other costs necessary to operate our producing properties. Depreciation, depletion, and amortization, or DD&A, of producing oil and gas properties is calculated using the units of production method based upon estimated proved reserves. For the purposes of computing DD&A, estimated proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary.

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

Results Overview

In the first quarter of 2010, we reported net income of $58.5 million, or $0.41 per diluted share, compared to net income of $5.2 million, or $0.05 per diluted share, in the first quarter of 2009. The increase reflects higher commodity prices partially offset by a reduced gain on mark-to-market derivative contracts.

Results of Operations

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


	Three Months Ended March 31,
	2010		2009
Sales Volumes
Oil and liquids sales (MBbls)		4,070		4,445
Gas (MMcf)
Production		22,013		17,635
Used as fuel		478		646
Sales		21,535		16,989
MBOE
Production		7,738		7,385
Sales		7,659		7,277
Daily Average Volumes
Oil and liquids sales (Bbls)		45,217		49,394
Gas (Mcf)
Production		244,594		195,943
Used as fuel		5,313		7,175
Sales		239,281		188,768
BOE
Production		85,983		82,052
Sales		85,097		80,856
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	78.88	$	43.31
Gas		5.27		4.87
Average Realized Sales Price Before
Derivative Transactions
Oil (per Bbl)	$	67.82	$	35.23
Gas (per Mcf)		5.00		4.19
Per BOE		50.11		31.31
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	8.16	$	9.74
Steam gas costs		2.57		2.14
Electricity		1.31		1.50
Production and ad valorem taxes		1.10		1.60
Gathering and transportation		1.23		0.91
Depreciation, depletion and amortization of oil and gas properties		15.33		11.49

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


	Three Months Ended March 31,
	2010		2009
Oil derivatives
Settlements	$	(14,549)	$	156,876
Monetization of crude oil puts and swaps		-		1,074,361
Natural gas derivatives		5,089		64,312

	$	(9,460)	$	1,295,549

Comparison of Three Months Ended March 31, 2010 to Three Months Ended March 31, 2009

Oil and gas revenues. Oil and gas revenues increased $155.8 million, to $383.7 million for 2010 from $227.9 million for 2009 primarily due an increase in realized prices of $18.80 per BOE.

Oil revenues increased $119.4 million to $276.0 million for 2010 from $156.6 million for 2009 primarily reflecting higher average realized prices. Our average realized price for oil increased $32.59 per Bbl to $67.82 per Bbl for 2010 from $35.23 per Bbl for 2009. The increase is primarily attributable to an increase in the NYMEX oil price, which averaged $78.88 per Bbl in 2010 versus $43.31 per Bbl in 2009. Oil sales volumes decreased 4.2 MBbls per day to 45.2 MBbls per day in 2010 from 49.4 MBbls per day in 2009, primarily reflecting decreased production in our onshore and offshore California properties.

Gas revenues increased $36.4 million to $107.7 million in 2010 from $71.3 million in 2009 due to an increase in sales volumes ($22.7 million) and an increase in realized prices ($13.7 million). Our average realized price for gas was $5.00 per Mcf in 2010 compared to $4.19 per Mcf in 2009. Gas sales volumes increased from 188.8 MMcf per day in 2009 to 239.3 MMcf per day in 2010, primarily reflecting increased production from our Haynesville Shale properties. Our realized price for gas increased primarily due to an increase in the NYMEX natural gas price, which averaged $5.27 per MMBtu in 2010 versus $4.87 per MMBtu in 2009.

Lease operating expenses . Lease operating expenses decreased $8.4 million, to $62.5 million in 2010 from $70.9 million in 2009, primarily reflecting the results of our cost reduction program. On a per unit basis, lease operating expenses decreased to $8.16 per BOE in 2010 from $9.74 per BOE in 2009.

Steam gas costs . Steam gas costs increased $4.1 million, to $19.7 million in 2010 from $15.6 million in 2009, primarily reflecting higher cost of gas used in steam generation partially offset by reduced volumes. In 2010, we burned approximately 3.7 billion cubic feet, or Bcf, of natural gas at a cost of approximately $5.35 per MMBtu compared to 3.9 Bcf at a cost of approximately $4.01 per MMBtu in 2009.

Production and ad valorem taxes. Production and ad valorem taxes decreased $3.2 million, to $8.4 million in 2010 from $11.6 million in 2009, reflecting lower ad valorem taxes, partially offset by increased production taxes. The reduction in ad valorem taxes reflects lower commodity prices at the time of assessment, while the increase in production taxes is the result of higher current commodity prices.

Gathering and transportation expense. Gathering and transportation expenses increased $2.8 million, to $9.4 million in 2010 from $6.6 million in 2009, primarily reflecting increased production from our Haynesville Shale properties.

General and administrative expense . G&A was $37.4 million in 2010 compared to $37.1 million in 2009, an insignificant change, due primarily to our cost savings program.

Depreciation, depletion and amortization. DD&A expense increased $34.3 million, to $122.4 million in 2010 from $88.1 million in 2009. The increase is attributable to our oil and gas DD&A, primarily due to a higher per unit rate ($28.4 million) and increased production ($5.4 million). Our oil and gas unit of production rate increased to $15.33 per BOE in 2010 compared to $11.49 per BOE in 2009.

Legal recovery. We received a net recovery of $8.4 million in 2010 as our share of a portion of the judgments in the Amber Resources Company et al. v. United States related lawsuits.

Interest expense . Interest expense decreased $0.9 million, to $21.1 million in 2010 from $22.0 million in 2009, primarily due to increased capitalized interest attributable to a higher average interest rate and a higher unevaluated property balance. This decrease is offset by higher interest expense in 2010 on our Senior Notes compared to our borrowings under the senior revolving credit facility in 2009. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization and in the process of development. We capitalized $34.3 million and $19.7 million of interest in 2010 and 2009, respectively.

Debt extinguishment costs. In connection with reductions of the borrowing base on our senior revolving credit facility we recorded $0.7 million and $10.2 million of debt extinguishment costs in the first quarters of 2010 and 2009, respectively.

Gain on mark-to-market derivative contracts . The derivative instruments we have in place are not classified as hedges for accounting purposes. 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 a payment to or receiving a payment from the counterparty.

We recognized a $7.9 million gain related to mark-to-market derivative contracts in the first quarter of 2010, which was primarily associated with an increase in fair value of our natural gas collars. In the first quarter of 2009, we recognized an $88.1 million gain related to mark-to-market derivative contracts.

Income taxes. For the first quarter of 2010, income tax expense was approximately 45% of pre-tax income. The variance between this effective tax rate and the 35% federal statutory rate results from the tax effects of estimated annual permanent differences, including (1) expenses that are not deductible because of Internal Revenue Service limitations, and (2) state income taxes. In addition, specific items affecting our income tax expense for the first quarter of 2010 included adjustments to deferred taxes for differences in the reporting of stock based compensation expenses for financial statement and income tax reporting purposes and changes to our balance of accrued interest recorded on unrecognized tax benefits. For the first quarter of 2009, income tax expense was approximately 85% of pre-tax income. This unusual rate resulted from the relationship of 2009 estimated pre-tax income relative to the estimated permanent differences used in our annual effective tax rate computation for this period. As income before income taxes changes in future quarters, our effective tax rate may increase or decrease.

Liquidity and Capital Resources

Our liquidity may be affected by declines in oil and gas prices, an inability to access the capital and credit markets and the success of our commodity price risk management activities, which may subject us to the credit risk of the counterparties to such agreements. This situation may arise due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions that cause substantial or extended declines in oil and gas prices. While there are signs that the economy may be improving, the potential remains for further volatility and disruption in the capital and credit markets. The recent volatility and disruption have created conditions that may adversely affect the financial condition of lenders in our senior revolving credit facility, the counterparties to our commodity price risk management agreements, our insurers and our oil and natural gas purchasers. These market conditions may adversely affect our liquidity by limiting our ability to access the capital and credit markets.

Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity. At March 31, 2010, we had approximately $1.129 billion available for future secured borrowings under our senior revolving credit facility, which had an aggregate borrowing base of $1.13 billion. Under the terms of the senior revolving credit facility, the borrowing base will be redetermined on an annual basis, with PXP and the lenders each having the right to one annual interim unscheduled redetermination. Declines in oil and gas prices may adversely affect our liquidity by lowering the amount of the borrowing base that the lenders are willing to extend. On April 12, 2010, we entered into an amendment to our senior revolving credit facility, which increased the borrowing base to $1.3 billion.

The commitments of each lender to make loans to us are several and not joint under our senior revolving credit facility. Accordingly, if any lender fails to make loans to us, our available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the credit facility. The commitments are from a diverse syndicate of 22 lenders. At March 31, 2010, no single lender’s commitment represented more than 10% of the total commitments.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisitions and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil or gas prices above the maximum fixed amount specified in the derivative agreement. Further, we become subject to the credit risk of the counterparties to these agreements when the price of oil and natural gas decreases below the floor specified in the derivative agreement. See Item 3 – Quantitative and Qualitative Disclosures About Market Risk. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy.

Our 2010 capital budget is approximately $1.2 billion, including capitalized interest and general and administrative expense. We intend to fund our 2010 capital budget from internally generated funds, cash on hand, and borrowings under our senior revolving credit facility.

We believe that we have sufficient liquidity through our forecasted cash flow from operations and borrowing capacity under our senior revolving credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies and anticipated capital expenditures. We have no near-term debt maturities. At March 31, 2010, our senior revolving credit facility has no amounts outstanding and matures on November 6, 2012. The next maturity of our senior notes will occur on June 15, 2015.

Working Capital

At March 31, 2010, we had a working capital deficit of approximately $253.0 million. We generally have a working capital deficit because we use excess cash to pay down borrowings under our senior revolving credit facility. Our working capital fluctuates for various reasons, including the fair value of our commodity derivative instruments and stock appreciation rights.

Financing Activities

Our borrowing base under our senior revolving credit facility was $1.13 billion, $1.129 billion of which was available at March 31, 2010. Our borrowing base was adjusted from $1.22 billion to $1.13 billion in recognition of our issuance of the 7 ⁵ / 8 % Senior Notes due 2020 in March 2010. On April 12, 2010, we entered into an amendment to our senior revolving credit facility. The amendment increased the borrowing base to $1.3 billion from $1.13 billion. In addition, the amendment allows us to increase our investments in certain subsidiaries and joint ventures. Our senior revolving credit facility contains a $250 million limit on letters of credit, a $50 million commitment for swingline loans and matures on November 6, 2012. As of March 31, 2010, we had $1.2 million in letters of credit outstanding.

Our senior revolving credit facility is secured by 100% of the shares of stock in certain of our domestic and 65% of certain foreign subsidiaries and mortgages covering at least 75% of the total present value of our domestic oil and gas properties. Our senior revolving credit facility contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries to, among other things, incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into take-or-pay or other prepayment arrangements, merge or consolidate and enter into transactions with affiliates. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined) of no greater than 4.25 to 1.

In March 2010, we issued $300 million of 7 ⁵ / 8 % Senior Notes due 2020 which were sold to the public at par. We received approximately $294 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes. We may redeem all or part of the 7 ⁵ / 8 % Senior Notes on or after April 1, 2015 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to April 1, 2013 we may, at our option, redeem up to 35% of the 7 ⁵ / 8 % Senior Notes with the proceeds of certain equity offerings. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 7 ⁵ / 8 % Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

Cash Flows


	Three Months Ended March 31,
	2010		2009
	(in millions)
Cash provided by (used in):
Operating activities	$	221.8	$	(29.4)
Investing activities		(227.5)		872.0
Financing activities		64.7		(973.0)

Net cash provided by operating activities was $221.8 million for the first quarter of 2010 compared to net cash used in operating activities of $29.4 million for the first quarter of 2009. The increase primarily reflects higher operating income in 2010 as a result of higher commodity prices. Additionally, cash used in operations in 2009 included income tax payments related to 2008 taxable income.

Net cash used in investing activities of $227.5 million in 2010 primarily reflects additions to oil and gas properties of $267.0 million, offset by a $51.1 million cash inflow associated with an adjustment to the final settlement of the $1.1 billion payment to Chesapeake Energy Corporation in September 2009 related to the prepayment of the Haynesville drilling carry. Net cash provided by investing activities of $872.0 million in 2009 primarily reflects derivative settlements received of $1.3 billion, partially offset by additions to oil and gas properties of $416.4 million.

Net cash provided by financing activities of $64.7 million in 2010 primarily reflects proceeds from the $300 million offering of 7 ⁵ / ₈ % Senior Notes partially offset by the net reduction in borrowings under our senior revolving credit facility of $230.0 million. Net cash used in financing activities of $973.0 million in 2009 primarily reflects the $1.3 billion net reduction in borrowings under our senior revolving credit facility partially offset by proceeds from the $365 million offering of 10% Senior Notes.

Stock Repurchase Program

In December 2007, our Board of Directors authorized the repurchase of up to $1.0 billion of our common stock. The shares may 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 currently have $695.8 million in authorized repurchases remaining under the program.

Critical Accounting Policies and Estimates

Management makes many estimates and assumptions in the application of generally accepted accounting principles that may have a material impact on our consolidated financial statements and related disclosures and on the comparability of this information over different reporting periods. All of these estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on information available prior to the issuance of the financial statements. Changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates. Critical accounting policies related to oil and gas reserves, impairments of oil and gas properties, oil and natural gas properties not subject to amortization, DD&A, commodity pricing and risk management activities, stock based compensation, allocation of purchase price in business combinations and goodwill are discussed in our Annual Report on Form 10-K for the year ended December 31, 2009.

Recent Accounting Pronouncements

In February 2010, the FASB issued authoritative guidance on subsequent events that removes the requirement for an SEC filer to disclose the date through which subsequent events have been evaluated in both issued and revised financial statements. This guidance was effective upon issuance. The adoption of the subsequent events standard did not have a significant impact on our consolidated financial position, results of operations or cash flows.

necessary to reassess who should consolidate a variable interest entity. The guidance is effective for fiscal years beginning after November 15, 2009, and for interim periods within that first annual reporting period. We adopted the provisions of this standard effective January 1, 2010, and it did not have a significant impact on our consolidated financial position, results of operations or cash flows.

Statement Regarding Forward-Looking Statements

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

•

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

•

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

•

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

•

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

•

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

•

the success of our derivative activities;

•

the success of our risk management activities;

•

the effects of competition;

•

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

•

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

•

the impact of current and future laws and governmental regulations, including those related to climate change;

•

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

•

the ability and willingness of our current or potential counterparties to fulfill their obligations to us or to enter into transactions with us in the future; 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. We do not intend to update these forward-looking statements and information except as required by law. See our filings with the SEC, including Item 1A – Risk Factors and Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates in our Annual Report on Form 10-K for the year ended December 31, 2009 for additional discussion of risks and uncertainties.

ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

See Note 3 – Commodity Derivative Contracts and Note 4 – Fair Value Measurement of Assets and Liabilities to the consolidated financial statements for a discussion of our derivative activities and fair value measurements.

In April 2010, we entered into crude oil put option spread contracts and crude oil three-way collars for a portion of our 2011 and 2012 production volumes. As of April 30, 2010, we have the following outstanding commodity derivative contracts, all of which settle monthly and none of which were designated as hedging instruments:


Period	Instrument Type	Daily Volumes	Average Price ⁽¹⁾	Average Deferred Premium	Index
Sales of Crude Oil Production
2010
Apr - Dec	Put options	40,000 Bbls	$55.00 Strike price	$5.00 per Bbl ⁽²⁾	WTI
2011
Jan - Dec	Put options ⁽³⁾	31,000 Bbls	$80.00 Floor with a $60.00 Limit	$5.023 per Bbl	WTI
Jan - Dec	Three-way collars ⁽⁴⁾	9,000 Bbls	$80.00 Floor with a $60.00 Limit $110.00 Ceiling	$1.00 per Bbl	WTI
2012
Jan - Dec	Put options ⁽³⁾	40,000 Bbls	$80.00 Floor with a $60.00 Limit	$6.087 per Bbl	WTI
Sales of Natural Gas Production
2010
Apr - Dec	Three-way collars ⁽⁵⁾	85,000 MMBtu	$6.12 Floor with a $4.64 Limit $8.00 Ceiling	$0.034 per MMBtu	Henry Hub

(1)

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

(2)

In addition to the deferred premium, a premium averaging $3.86 per barrel was paid upon entering into these derivative contracts.

(3)

(4)

If the index price is less than the $80 per barrel floor, we receive the difference between the $80 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. We pay the difference between the index price and $110 per barrel plus the option premium if the index price is greater than the $110 per barrel ceiling. If the index price is at or above $80 per barrel but at or below $110 per barrel, we pay only the option premium.

(5)

If the index price is less than the $6.12 per MMBtu floor, we receive the difference between the $6.12 per MMBtu floor and the index price up to a maximum of $1.48 per MMBtu less the option premium. We pay the difference between the index price and $8.00 per MMBtu plus the option premium if the index price is greater than the $8.00 ceiling.

The fair value of outstanding 2010 crude oil and natural gas commodity derivative instruments at March 31, 2010 and the change in fair value that would be expected from a 10% price increase/decrease is shown below (in millions):


	Fair Value Asset		Effect of 10%
	Fair Value Asset		Price Increase		Price Decrease
Crude oil put options	$	3	$	(2)	$	4
Natural gas collars		29		(3)		2

	$	32	$	(5)	$	6

None of our offsetting physical positions are included in the above table. Price risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price.

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

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, or 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 March 31, 2010 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.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2010 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 6 – Exhibits


Exhibit No.		Description

4.1		Eleventh Supplemental Indenture, dated as of March 29, 2010, to Indenture, dated March 13, 2007, among Plains Exploration & Production Company, the subsidiary guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 29, 2010, File No. 1-31470).

4.2		Amendment No. 5 to Amended and Restated Credit Agreement, dated as of April 12, 2010, among Plains Exploration & Production Company, as borrower, each of the lenders that is a signatory thereto, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed April 12, 2010, File No. 1-31470).

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.

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Presentation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith

Items 1, 1A, 2, 3 and 5 are not applicable and have been omitted.

SIGNATURES

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


	PLAINS EXPLORATION & PRODUCTION COMPANY

Date: May 6, 2010
	By:	/s/ Winston M. Talbert
		Winston M. Talbert Executive Vice President and Chief Financial Officer (Principal Financial Officer)

EXHIBIT INDEX


Exhibit No.		Description

4.1		Eleventh Supplemental Indenture, dated as of March 29, 2010, to Indenture, dated March 13, 2007, among Plains Exploration & Production Company, the subsidiary guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 29, 2010, File No. 1-31470).

4.2		Amendment No. 5 to Amended and Restated Credit Agreement, dated as of April 12, 2010, among Plains Exploration & Production Company, as borrower, each of the lenders that is a signatory thereto, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed April 12, 2010, File No. 1-31470).

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.

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Presentation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith