- Quarterly Report (10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

¨ 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 website, 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

141.0 million shares of Common Stock, $0.01 par value, issued and outstanding at July 29, 2011.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



PART I. FINANCIAL INFORMATION

ITEM 1. Unaudited Consolidated Financial Statements:

Consolidated Balance Sheets June 30, 2011 and December 31, 2010			1

Consolidated Statements of Income For the three months ended and six months ended June 30, 2011 and 2010			2

Consolidated Statements of Cash Flows For the six months ended June 30, 2011 and 2010			3

Consolidated Statement of Stockholders’ Equity For the six months ended June 30, 2011			4

Notes to Consolidated Financial Statements			5

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			27

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			39

ITEM 4. Controls and Procedures			40

PART II. OTHER INFORMATION			41

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

		December		December
	June 30, 2011		December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents	$	5,331	$	6,434
Accounts receivable		250,413		269,024
Inventories		27,166		24,406
Deferred income taxes		66,002		74,086
Prepaid expenses and other current assets		27,412		28,937

		376,324		402,887

Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		10,844,515		9,975,056
Not subject to amortization		3,309,642		3,304,554
Other property and equipment		143,684		137,150

		14,297,841		13,416,760
Less allowance for depreciation, depletion, amortization and impairment		(6,475,951)		(6,196,008)

		7,821,890		7,220,752

Goodwill		535,142		535,144

Investment		774,907		664,346

Other Assets		76,179		71,808

	$	9,584,442	$	8,894,937


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	315,242	$	284,628
Commodity derivative contracts		59,786		52,971
Royalties and revenues payable		82,818		70,990
Interest payable		58,446		49,127
Other current liabilities		74,338		75,973

		590,630		533,689

Long-Term Debt		3,637,447		3,344,717

Other Long-Term Liabilities
Asset retirement obligation		239,361		225,571
Commodity derivative contracts		20,400		24,740
Other		23,146		28,205

		282,907		278,516

Deferred Income Taxes		1,480,598		1,355,050

Commitments and Contingencies (Note 7)
Stockholders’ Equity
Common stock, $0.01 par value, 250.0 million shares authorized, 143.9 million shares issued at June 30, 2011 and December 31, 2010		1,439		1,439
Additional paid-in capital		3,410,856		3,427,869
Retained earnings		328,624		148,620
Treasury stock, at cost, 2.9 million shares and 3.8 million shares at June 30, 2011 and December 31, 2010, respectively		(148,059)		(194,963)

		3,592,860		3,382,965

	$	9,584,442	$	8,894,937

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

		October		October		October		October
	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Revenues
Oil sales	$	399,306	$	276,263	$	731,149	$	552,267
Gas sales		113,670		87,678		210,472		195,417
Other operating revenues		1,809		652		3,478		959

		514,785		364,593		945,099		748,643

Costs and Expenses
Lease operating expenses		82,142		57,536		154,393		120,039
Steam gas costs		16,865		15,357		32,626		35,020
Electricity		10,371		11,115		20,091		21,149
Production and ad valorem taxes		16,920		3,828		28,448		12,275
Gathering and transportation expenses		16,841		12,912		29,588		22,331
General and administrative		30,783		30,301		66,806		67,691
Depreciation, depletion and amortization		150,757		123,810		285,300		246,203
Impairment of oil and gas properties		-		59,475		-		59,475
Accretion		4,314		4,407		8,571		8,818
Legal recovery		-		-		-		(8,423)
Other operating income		(303)		(3,945)		(607)		(4,514)

		328,690		314,796		625,216		580,064

Income from Operations		186,095		49,797		319,883		168,579
Other (Expense) Income
Interest expense		(37,242)		(28,039)		(69,646)		(49,092)
Debt extinguishment costs		-		-		-		(728)
Gain (loss) on mark-to-market derivative contracts		18,912		57,984		(32,084)		65,840
Gain on investment measured at fair value		43,307		-		110,561		-
Other income		996		11,235		1,550		12,541

Income Before Income Taxes		212,068		90,977		330,264		197,140
Income tax expense
Current		(387)		(2,672)		(759)		(7,410)
Deferred		(86,789)		(42,930)		(133,634)		(85,827)

Net Income	$	124,892	$	45,375	$	195,871	$	103,903

Earnings per Share
Basic	$	0.88	$	0.32	$	1.39	$	0.74
Diluted	$	0.87	$	0.32	$	1.37	$	0.73
Weighted Average Shares Outstanding
Basic		141,797		140,560		141,335		140,153

Diluted		143,300		141,557		143,361		141,752

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

		June		June
	Six Months Ended June 30,
	2011		2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	195,871	$	103,903
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		285,300		246,203
Impairment of oil and gas properties		-		59,475
Accretion		8,571		8,818
Deferred income tax expense		133,634		85,827
Debt extinguishment costs		-		728
Loss (gain) on mark-to-market derivative contracts		32,084		(65,840)
Gain on investment measured at fair value		(110,561)		-
Non-cash compensation		28,031		22,955
Other non-cash items		(302)		1,672
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(21,470)		27,231
Accounts payable and other liabilities		(14,103)		(31,365)
Income taxes receivable/payable		40,370		14,825

Net cash provided by operating activities		577,425		474,432

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(800,170)		(558,386)
Acquisition of oil and gas properties		(32,456)		43,923
Proceeds from sales of oil and gas properties, net of costs and expenses		11,987		7,230
Derivative settlements		(30,039)		(16,153)
Additions to other property and equipment		(6,534)		(4,394)

Net cash used in investing activities		(857,212)		(527,780)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		2,679,200		860,455
Repayments of revolving credit facilities		(2,989,200)		(1,090,455)
Proceeds from issuance of Senior Notes		600,000		300,000
Costs incurred in connection with financing arrangements		(11,320)		(5,932)
Other		4		-

Net cash provided by financing activities		278,684		64,068

Net (decrease) increase in cash and cash equivalents		(1,103)		10,720
Cash and cash equivalents, beginning of period		6,434		1,859

Cash and cash equivalents, end of period	$	5,331	$	12,579

See notes to consolidated financial statements.

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)


					Additional
	Common Stock				Paid-in		Retained		Treasury Stock
	Shares		Amount		Capital		Earnings		Shares	Amount		Total
Balance at December 31, 2010		143,924	$	1,439	$	3,427,869	$	148,620	(3,764)		$ (194,963)	$	3,382,965
Net income		-		-		-		195,871	-		-		195,871
Restricted stock awards		-		-		14,008		-	-		-		14,008
Issuance of treasury stock for restricted stock awards		-		-		(31,021)		(15,843)	875		46,864		-
Exercise of stock options and other		-		-		-		(24)	1		40		16

Balance at June 30, 2011		143,924	$	1,439	$	3,410,856	$	328,624	(2,888)	$	(148,059)	$	3,592,860

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 located in the United States.

Our consolidated financial statements include the accounts of all our wholly owned subsidiaries. All significant intercompany transactions have been eliminated. All adjustments, consisting only of normal recurring adjustments that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. The results of our operations for the six months ended June 30, 2011 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 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, 2010.

Asset Retirement Obligation . The following table reflects the changes in our asset retirement obligation during the six months ended June 30, 2011 (in thousands):


Asset retirement obligation - December 31, 2010	$	239,432
Settlements		(3,969)
Change in estimate		5,253
Accretion expense		8,571
Asset retirement additions		2,888

Asset retirement obligation - June 30, 2011 ⁽¹⁾	$	252,175

(1)	$12.8 million is included in other current liabilities.

Earnings Per Share. For the three and six months ended June 30, 2011 and 2010 the weighted average shares outstanding for computing basic and diluted earnings per share were (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010

Weighted average common shares outstanding - basic		141,797		140,560		141,335		140,153
Unvested restricted stock, restricted stock units and stock options		1,503		997		2,026		1,599

Weighted average common shares outstanding - diluted		143,300		141,557		143,361		141,752

In the three months ended June 30, 2011 and 2010, 1.0 million and 2.9 million restricted stock units, respectively, and in the six months ended June 30, 2011 and 2010, 1.0 million and 1.4 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. At June 30, 2011 and December 31, 2010, inventory consisted of the following (in thousands):

		December 31,		December 31,
	June 30, 2011		December 31, 2010
Oil	$	7,282	$	6,744
Materials and supplies		19,884		17,662

	$	27,166	$	24,406

Stock-Based Compensation. Stock-based compensation for the three and six months ended June 30, 2011 and 2010 was (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Stock-based compensation included in:
General and administrative expense	$	9,522	$	8,305	$	23,365	$	22,921
Lease operating expenses		1,703		(2,250)		4,666		34
Oil and natural gas properties		2,976		2,120		7,495		6,963

Total stock-based compensation	$	14,201	$	8,175	$	35,526	$	29,918

During the first six months of 2011, we granted 1.6 million restricted stock units at an average fair value of $37.24 per share and 904 thousand stock appreciation rights with an average exercise price of $37.21 per share.

Recent Accounting Pronouncement s. In December 2010, the Financial Accounting Standards Board, or FASB, issued authoritative guidance clarifying the acquisition date that should be used for reporting the pro forma financial information disclosures when comparative financial statements are presented. The guidance also improves the usefulness of the pro forma revenue and earnings disclosures by requiring a description of the nature and amount of material, nonrecurring pro forma adjustments that are directly attributable to the business combination. We adopted the provisions of this standard effective January 1, 2011, and it did not have a significant impact on our consolidated financial position, results of operations or cash flows.

In December 2010, the FASB issued authoritative guidance amending the criteria for performing the second step of the goodwill impairment test for companies with reporting units with zero or negative carrying amounts. The amended guidance requires performance of the second step if qualitative factors indicate that it is more likely than not that a goodwill impairment exists. We adopted the provisions of this standard effective January 1, 2011, and it did not have a significant impact on our consolidated financial position, results of operations or cash flows.

In May 2011, the FASB issued authoritative guidance amending certain accounting and disclosure requirements related to fair value measurements. The guidance clarifies (i) the requirement that the highest and best use concept is only relevant for measuring nonfinancial assets, (ii) requirements to measure the fair value of instruments classified in shareholders’ equity and (iii) the requirement to disclose quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy. The guidance also (i) permits a reporting entity to measure the fair value of certain financial assets and liabilities managed in a portfolio at the price that would be received to sell a net asset position or transfer a net liability position for a particular risk, (ii) eliminates premiums or discounts related to size as a characteristic of the reporting entity’s holding and (iii) expands disclosures for fair value measurement. The guidance is effective for interim and annual periods beginning after December 15, 2011. Early adoption is not permitted. We are currently evaluating the impact of this guidance.

In June 2011, the FASB issued authoritative guidance to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The guidance requires entities to report components of comprehensive income in either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. The requirement is effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. Prior to this guidance, we prepared a separate statement of comprehensive income. We will adopt this guidance in the fourth quarter of 2011 and these provisions will require that we position this statement consecutively to the income statement.

Note 2 — Long-Term Debt

At June 30, 2011 and December 31, 2010, long-term debt consisted of (in thousands):


	June 30, 2011		December 31, 2010

Senior revolving credit facility	$	310,000	$	620,000
7 ³ / 4 % Senior Notes due 2015		600,000		600,000
10% Senior Notes due 2016 ⁽¹⁾		533,307		530,812
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⁾		394,140		393,905
7 ⁵ / 8 % Senior Notes due 2020		300,000		300,000
6 ⁵ / 8 % Senior Notes due 2021		600,000		-

	$	3,637,447	$	3,344,717

(1) The amount is net of unamortized discount of $31.7 million and $34.2 million at June 30, 2011 and December 31, 2010, respectively.

(2) The amount is net of unamortized discount of $5.9 million and $6.1 million at June 30, 2011 and December 31, 2010, respectively.

Senior Revolving Credit Facility. In April 2011, our borrowing base increased to $1.8 billion from $1.45 billion. The commitments remained unchanged at $1.4 billion. In May 2011, we entered into an amendment to our senior revolving credit facility. The amendment adjusted our borrowing rates and the maturity date was extended to May 4, 2016. The borrowing base will be redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors. Additionally, our senior revolving credit facility contains a $250 million limit on letters of credit and a $50 million commitment for swingline loans. At June 30, 2011, we had $1.2 million in letters of credit outstanding under our senior revolving credit facility.

Amounts borrowed under our senior revolving credit facility, as amended, 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 1.50% to 2.50%; (ii) a variable amount ranging from 0.50% to 1.50% plus 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 plus 1%; or (iii) the overnight federal funds rate plus an additional variable amount ranging from 1.50% to 2.50% for swingline loans. The additional variable amount of interest payable on outstanding borrowings is based on the utilization rate as a percentage of the total amount of funds borrowed under our senior revolving credit facility to the borrowing base. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing.

Our senior revolving credit facility is secured by 100% of the shares of stock in certain of our domestic subsidiaries, 65% of the shares of stock in certain foreign subsidiaries and mortgages covering at least 75% of the total present value of our domestic proved 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 4.50 to 1.

Short-term Credit Facility. We have an uncommitted short-term unsecured credit facility, or short-term facility, under which we may make borrowings from time to time until June 1, 2012, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding 14 days and all amounts outstanding are due and payable no later than June 1, 2012. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and us.

We borrow under our short-term facility to fund our working capital needs. The funding requirements are typically generated due to the timing differences between payments and receipts associated with our oil and gas production. We generally pay off the short-term facility with receipts from the sales of our oil and gas production or borrowings under our senior revolving credit facility. No amounts were outstanding under the short-term facility at June 30, 2011. The daily average outstanding balance for the three and six months ended June 30, 2011 was $61.1 million and $57.5 million, respectively.

6 ⁵ / 8 % Senior Notes. In March 2011, we issued $600 million of 6 ⁵ / 8 % Senior Notes, or the 6 ⁵ / 8 % Senior Notes, at par. We received approximately $590 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 6 ⁵ / 8 % Senior Notes on or after May 1, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to May 1, 2014 we may, at our option, redeem up to 35% of the 6 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 6 ⁵ / 8 % Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 6 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 6 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 6 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.

Note 3 — Commodity Derivative Contracts

General

We are exposed to various market risks, including volatility in oil and gas commodity prices and interest 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 risk. The majority of our debt is at fixed interest rates, thereby reducing our floating interest rate risk exposure.

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 the instrument. If the index price is below the floor price of the put option, we receive the difference between the floor price and the index price multiplied by the contract volumes less the option premium. If the index price settles at or above the floor 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 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 are no offsetting revenues from production.

See Note 5 – Fair Value Measurements of Assets and Liabilities, for additional discussion on the fair value measurement of our derivative contracts.

As of June 30, 2011, we had the following outstanding commodity derivative contracts, all of which settle monthly:


Period	Instrument Type	Daily Volumes	Average Price ⁽¹⁾	Average Deferred Premium	Index
Sales of Crude Oil Production
2011
July - Dec	Put options ⁽²⁾	31,000 Bbls	$80.00 Floor with a $60.00 Limit	$5.023 per Bbl	WTI
July - Dec	Three-way collars ⁽³⁾	9,000 Bbls	$80.00 Floor with a $60.00 Limit	$1.00 per Bbl	WTI
			$110.00 Ceiling
2012
Jan - Dec	Put options ⁽²⁾	40,000 Bbls	$80.00 Floor with a $60.00 Limit	$6.087 per Bbl	WTI

Sales of Natural Gas Production
2011
July - Dec	Three-way collars ⁽⁴⁾	200,000 MMBtu	$4.00 Floor with a $3.00 Limit	-	Henry Hub
			$4.92 Ceiling
2012
Jan - Dec	Put options ⁽⁵⁾	160,000 MMBtu	$4.30 Floor with a $3.00 Limit	$0.294 per MMBtu	Henry Hub

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

(2)	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. If the index price is at or above $80 per barrel, we pay only the option premium.

(3)

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.

(4)

If the index price is less than the $4.00 per MMBtu floor, we receive the difference between the $4.00 per MMBtu floor and the index price up to a maximum of $1.00 per MMBtu. We pay the difference between the index price and $4.92 per MMBtu if the index price is greater than the $4.92 per MMBtu ceiling. If the index price is at or above $4.00 per MMBtu but at or below $4.92 per MMBtu, no cash settlement is required.

(5)	If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium. If the index price is at or above $4.30 per MMBtu, we pay only the option premium.

Balance Sheet

At June 30, 2011 and December 31, 2010, we had the following outstanding commodity derivative contracts recorded in our balance sheet (in thousands):


		Estimated Fair Value
Instrument Type	Balance Sheet Classification	June 30, 2011		December 31, 2010

Crude oil puts	Commodity derivative contracts - current assets	$	24,070	$	23,910
Natural gas puts	Commodity derivative contracts - current assets		6,535		-
Crude oil collars	Commodity derivative contracts - current liability		(970)		(317)
Natural gas collars	Commodity derivative contracts - current liability		(1,952)		(10,469)
Crude oil puts	Commodity derivative contracts - non-current assets		24,814		64,266
Natural gas puts	Commodity derivative contracts - non-current assets		7,454		15,254

Total derivative instruments		$	59,951	$	92,644

The following table provides supplemental information to reconcile the fair value of our derivative contracts to our balance sheet at June 30, 2011 and December 31, 2010, considering the deferred premiums, accrued interest and related settlement payable amounts which are not included in the fair value amounts disclosed in the table above (in thousands):


	June 30, 2011		December 31, 2010
Net fair value asset	$	59,951	$	92,644
Deferred premium and accrued interest on derivative contracts		(135,196)		(164,155)
Settlement payable		(4,941)		(6,200)

Net commodity derivative liability	$	(80,186)	$	(77,711)


Commodity derivative contracts - current liability	$	(59,786)	$	(52,971)
Commodity derivative contracts - non-current liability		(20,400)		(24,740)

	$	(80,186)	$	(77,711)

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 and six months ended June 30, 2011 and 2010, pre-tax amounts recognized in our income statements for derivative transactions were as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010

Gain (loss) on mark-to-market derivative contracts	$	18,912	$	57,984	$	(32,084)	$	65,840

Cash Payments and Receipts

During the six months ended June 30, 2011 and 2010, cash (payments) receipts for derivatives were as follows (in thousands):


	Six Months Ended June 30,
	2011		2010
Oil derivatives	$	(30,659)	$	(32,403)
Natural gas derivatives		620		16,250

	$	(30,039)	$	(16,153)

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 derivative 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.

Contingent Features

As of June 30, 2011, the counterparties to our commodity derivative contracts consisted of nine 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 cross default and acceleration provisions relative to our material debt agreements. If we were to default on any of our material debt agreements, it would be a violation of these provisions, and the counterparties to our derivative agreements could request immediate payment on derivative instruments that are in a net liability position at that time. As of June 30, 2011, we were in a net liability position with all nine of the counterparties to our derivative instruments, totaling $80.2 million.

Note 4 — Investment

At June 30, 2011, we owned 51.0 million shares of McMoRan Exploration Co. common stock, approximately 32.2% of their common shares outstanding. In December 2010, we acquired the McMoRan common stock and other consideration in exchange for all of our interests in our U.S. Gulf of Mexico leasehold located in less than 500 feet of water. We entered into a stockholder agreement with McMoRan requiring us to refrain from certain activities that could be undertaken to acquire control of McMoRan and from transferring any McMoRan shares for one year after closing (subject to certain exceptions). After one year from the acquisition date, we may sell shares of McMoRan common stock pursuant to underwritten offerings, in periodic sales under a shelf registration statement filed by McMoRan (subject to certain volume limitations), pursuant to the exercise of piggyback registration rights or as otherwise permitted by applicable law.

We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as a gain or loss on investment measured at fair value in our income statement. We believe that using fair value as a measurement basis for our investment is useful to our investors because our earnings on the investment will be dependent on the fair value on the date we divest the shares. At June 30, 2011, the McMoRan shares were valued at approximately $774.9 million, based on McMoRan’s closing stock price of $18.48 on June 30, 2011, discounted to reflect certain restrictions on the marketability of the McMoRan shares. During the three and six months ended June 30, 2011, we recorded unrealized gains of $43.3 million and $110.6 million, respectively, on our investment.

McMoRan follows the successful efforts method of accounting for its oil and natural gas activities. Under this method of accounting, all costs associated with oil and gas lease acquisition, successful exploratory wells and all development wells are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves on a field basis. Unproved leasehold costs are capitalized pending the results of exploration efforts. Exploration costs, including geological and geophysical expenses, exploratory dry holes and delay rentals, are charged to expense when incurred. Below is summarized financial information of our proportionate share of McMoRan’s results of operations (in thousands):


	Six Months Ended June 30, 2011 ⁽¹⁾
Results of Operations
Revenues	$	95,090
Operating loss		(14,380)
Loss from continuing operations		(16,873)
Net loss applicable to common stock		(25,035)



(1) Amounts represent our 32.2% equity ownership in McMoRan.

Note 5 — 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 and investment are recorded at fair value on a recurring basis in our balance sheet with the changes in fair value recorded in our income statement. The following table presents, for each fair value hierarchy level, our commodity derivative assets and liabilities and our investment measured at fair value on a recurring basis as of June 30, 2011 and December 31, 2010 (in thousands):

		Identical Assets		Identical Assets		Identical Assets		Identical Assets
			Fair Value Measurements at Reporting Date Using
	Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
June 30, 2011
Commodity derivative contracts ⁽¹⁾
Crude oil puts	$	48,884	$	-	$	48,884	$	-
Crude oil collars		(970)		-		(970)		-
Natural gas collars		(1,952)		-		-		(1,952)
Natural gas puts		13,989		-		-		13,989
Investment ⁽²⁾		774,907		-		-		774,907

	$	834,858	$	-	$	47,914	$	786,944

December 31, 2010
Commodity derivative contracts ⁽¹⁾
Crude oil puts	$	88,176	$	-	$	88,176	$	-
Crude oil collars		(317)		-		(317)		-
Natural gas collars		(10,469)		-		-		(10,469)
Natural gas puts		15,254		-		-		15,254
Investment ⁽²⁾		664,346		-		-		664,346

	$	756,990	$	-	$	87,859	$	669,131

(1)	Option premium and accrued interest of $135.2 million and $164.2 million at June 30, 2011 and December 31, 2010, respectively, and settlement payable of $4.9 million and $6.2 million at June 30, 2011 and December 31, 2010, respectively, are not included in the fair value of derivatives.

(2)	Represents our equity investment in McMoRan which would otherwise be reported under the equity method of accounting.

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 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 June 30, 2011, our crude oil put options and crude oil collars are classified as Level 2, and our natural gas put options and natural gas collars are classified as Level 3 instruments.

We determine the fair value of our investment by applying a discount for lack of marketability at the reporting date. The discount factor for lack of marketability is determined by utilizing both Protective put and Asian put option models. Both of these options are valued using a Black-Scholes option-pricing model which utilizes various inputs including the closing price of the McMoRan common stock, term of the restrictions, historical and implied volatility of the instrument, number of shares being valued, length of time that would be necessary to dispose of our investment, expected dividend and risk-free interest rates. As of June 30, 2011, we have classified our investment as Level 3 since the fair value is determined by utilizing significant inputs that are unobservable.

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 six months ended June 30, 2011 and 2010 (in thousands):


	Six Months Ended June 30,
	2011				2010
	Commodity Derivatives ⁽¹⁾		Investment		Commodity Derivatives ⁽¹⁾
Fair value at beginning of period	$	4,785	$	664,346	$	14,312
Realized and unrealized gains and losses included in earnings ⁽²⁾		7,872		110,561		19,072
Settlements		(620)		-		(16,765)

Fair value at end of period ⁽³⁾	$	12,037	$	774,907	$	16,619

Change in unrealized gains and losses relating to assets and liabilities held as of the end of the period ⁽²⁾	$	6,563	$	110,561	$	11,124

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

(2)	Realized and unrealized gains and losses included in earnings for the period are reported as gain (loss) on mark-to-market derivative contracts and gain on investment measured at fair value in our income statement for our commodity derivative contracts and our investment, respectively.

(3)	There were no transfers or purchases during the reported periods.

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 balance sheet.

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 balance sheet are stated at fair value; however, certain of our derivative financial instruments have a deferred premium, including our crude oil put options, crude oil collars and natural gas put options. 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 June 30, 2011 and December 31, 2010 (in thousands):


	June 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Current Liability
Deferred premium and accrued interest on derivative contracts	$	82,528	$	82,528	$	59,895	$	59,895
Non-Current Liability
Deferred premium and accrued interest on derivative contracts		52,668		52,668		104,260		104,260
Long-Term Debt
Senior revolving credit facility		310,000		310,000		620,000		620,000
7 ³ / 4 % Senior Notes		600,000		621,750		600,000		625,500
10% Senior Notes		533,307		635,625		530,812		631,388
7% Senior Notes		500,000		515,000		500,000		513,750
7 ⁵ / 8 % Senior Notes		400,000		420,000		400,000		421,000
8 ⁵ / 8 % Senior Notes		394,140		436,000		393,905		438,000
7 ⁵ / 8 % Senior Notes		300,000		315,000		300,000		316,125
6 ⁵ / 8 % Senior Notes		600,000		600,000		-		-

The carrying value of our senior revolving credit facility approximates its 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 6 — 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 and six months ended June 30, 2011, income tax expense was approximately 41% 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 (i) expenses that are not deductible because of IRS limitations and (ii) state income taxes.

Note 7 — 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, $72.3 million ($144.1 million undiscounted), is included in our asset retirement obligation as reflected on our 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 $75.0 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At June 30, 2011, the escrow account had a balance of $17.8 million. The fair value of our guarantee at June 30, 2011, $0.4 million, considers the payment/performance risk of the purchaser and is included in other long-term liabilities in our 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. 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. 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 are self-insured for named windstorms in the U.S. Gulf of Mexico. 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. 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.

Through our ownership in Lucius, located in the deepwater U.S. Gulf of Mexico, we joined the Lucius and Hadrian working interest partners and executed a unit participation and unit operating agreement effective June 1, 2011. As part of the agreements, we have agreed to share in our portion of certain long lead equipment orders and detailed engineering work.

At our Arroyo Grande field in San Luis Obispo County, California, we have committed for the design and build of a produced water reclamation facility. Additionally, we have signed a ten-year operations agreement which will commence upon commercial operations.

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 8 — 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 due 2018, $400 million of 8 ⁵ / 8 % Senior Notes, $300 million of 7 ⁵ / 8 % Senior Notes due 2020 and $600 million of 6 ⁵ / 8 % Senior Notes as of June 30, 2011, 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”).

PXP Operations LLC. During the first half of 2011, the reverse like-kind exchange arrangements pursuant to Internal Revenue Code Section 1031 were concluded prior to the completion of a like-kind exchange involving any disposition of PXP properties. As a result, the related Eagle Ford Shale properties were transferred from PXP Operations LLC, which was reported as a Non-Guarantor Subsidiary, to PXP and the outstanding notes between PXP Operations LLC and PXP were settled. We have retrospectively adjusted the Issuer and Non-Guarantor Subsidiaries columns of the condensed consolidating balance sheet at December 31, 2010 to reflect the unwind of the reverse like-kind exchange arrangement involving PXP Operations LLC.

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)

JUNE 30, 2011

(in thousands of dollars)


	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	4,799	$	7	$	525	$	-	$	5,331
Accounts receivable and other current assets		206,271		164,693		29		-		370,993

		211,070		164,700		554		-		376,324

Property and Equipment, at cost
Oil and natural gas properties - full cost method		4,908,895		9,185,787		59,475		-		14,154,157
Other property and equipment		53,131		42,179		48,374		-		143,684

		4,962,026		9,227,966		107,849		-		14,297,841
Less allowance for depreciation, depletion, amortization and impairment		(2,507,360)		(6,206,016)		(59,479)		2,296,904		(6,475,951)

		2,454,666		3,021,950		48,370		2,296,904		7,821,890

Investment in and Advances to Affiliates		4,616,163		(1,796,808)		(69,615)		(2,749,740)		-

Other Assets		838,622		547,606		-		-		1,386,228

	$	8,120,521	$	1,937,448	$	(20,691)	$	(452,836)	$	9,584,442

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$	389,960	$	198,490	$	2,180	$	-	$	590,630
Long-Term Debt		3,637,447		-		-		-		3,637,447
Other Long-Term Liabilities		215,832		67,075		-		-		282,907
Deferred Income Taxes		284,422		279,042		(1,257)		918,391		1,480,598
Stockholders’ Equity		3,592,860		1,392,841		(21,614)		(1,371,227)		3,592,860

	$	8,120,521	$	1,937,448	$	(20,691)	$	(452,836)	$	9,584,442

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2010

(in thousands of dollars)


	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	6,020	$	8	$	406	$	-	$	6,434
Accounts receivable and other current assets		262,193		133,761		499		-		396,453

		268,213		133,769		905		-		402,887

Property and Equipment, at cost
Oil and natural gas properties - full cost method		4,498,652		8,721,483		59,475		-		13,279,610
Other property and equipment		49,110		41,736		46,304		-		137,150

		4,547,762		8,763,219		105,779		-		13,416,760
Less allowance for depreciation, depletion, amortization and impairment		(2,421,870)		(5,769,846)		(59,478)		2,055,186		(6,196,008)

		2,125,892		2,993,373		46,301		2,055,186		7,220,752

Investment in and Advances to Affiliates		4,485,838		(1,562,441)		(66,116)		(2,857,281)		-

Other Assets		726,277		545,021		-		-		1,271,298

	$	7,606,220	$	2,109,722	$	(18,910)	$	(802,095)	$	8,894,937

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	$	384,170	$	147,246	$	2,273	$	-	$	533,689
Long-Term Debt		3,344,717		-		-		-		3,344,717
Other Long-Term Liabilities		216,755		61,761		-		-		278,516
Deferred Income Taxes		277,613		323,829		(710)		754,318		1,355,050
Stockholders’ Equity		3,382,965		1,576,886		(20,473)		(1,556,413)		3,382,965

	$	7,606,220	$	2,109,722	$	(18,910)	$	(802,095)	$	8,894,937

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2011

(in thousands of dollars)


	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	328,423	$	70,883	$	-	$	-	$	399,306
Gas sales		2,621		111,049		-		-		113,670
Other operating revenues		269		1,540		-		-		1,809

		331,313		183,472		-		-		514,785

Costs and Expenses
Production costs		90,391		52,748		-		-		143,139
General and administrative		19,047		11,663		73		-		30,783
Depreciation, depletion, amortization and accretion		50,397		66,911		-		37,763		155,071
Impairment of oil and gas properties		-		143,173		-		(143,173)		-
Other operating income		-		(303)		-		-		(303)

		159,835		274,192		73		(105,410)		328,690

Income (Loss) from Operations		171,478		(90,720)		(73)		105,410		186,095
Other (Expense) Income
Equity in earnings of subsidiaries		(17,627)		4		-		17,623		-
Interest expense		(393)		(36,159)		(690)		-		(37,242)
Gain on mark-to-market derivative contracts		18,912		-		-		-		18,912
Gain on investment measured at fair value		43,307		-		-		-		43,307
Other income		225		760		11		-		996

Income (Loss) Before Income Taxes		215,902		(126,115)		(752)		123,033		212,068
Income tax (expense) benefit		(91,010)		46,438		395		(42,999)		(87,176)

Net Income (Loss)	$	124,892	$	(79,677)	$	(357)	$	80,034	$	124,892

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED JUNE 30, 2010

(in thousands of dollars)


	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	229,592	$	46,671	$	-	$	-	$	276,263
Gas sales		15,476		72,202		-		-		87,678
Other operating revenues		410		242		-		-		652

		245,478		119,115		-		-		364,593

Costs and Expenses
Production costs		70,399		30,349		-		-		100,748
General and administrative		21,504		8,707		90		-		30,301
Depreciation, depletion, amortization and accretion		56,184		32,895		-		39,138		128,217
Impairment of oil and gas properties		-		-		59,475		-		59,475
Other operating income		-		(3,945)		-		-		(3,945)

		148,087		68,006		59,565		39,138		314,796

Income (Loss) from Operations		97,391		51,109		(59,565)		(39,138)		49,797
Other (Expense) Income
Equity in earnings of subsidiaries		(43,497)		(139)		-		43,636		-
Interest expense		(17)		(27,510)		(512)		-		(28,039)
Gain on mark-to-market derivative contracts		57,984		-		-		-		57,984
Other income (expense)		8		11,469		(242)		-		11,235

Income (Loss) Before Income Taxes		111,869		34,929		(60,319)		4,498		90,977
Income tax (expense) benefit		(66,494)		(13,462)		2,740		31,614		(45,602)

Net Income (Loss)	$	45,375	$	21,467	$	(57,579)	$	36,112	$	45,375

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2011

(in thousands of dollars)


	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	605,817	$	125,332	$	-	$	-	$	731,149
Gas sales		5,990		204,482		-		-		210,472
Other operating revenues		505		2,973		-		-		3,478

		612,312		332,787		-		-		945,099

Costs and Expenses
Production costs		168,736		96,410		-		-		265,146
General and administrative		41,751		24,790		265		-		66,806
Depreciation, depletion, amortization and accretion		97,193		125,229		-		71,449		293,871
Impairment of oil and gas properties		-		313,167		-		(313,167)		-
Other operating income		-		(607)		-		-		(607)

		307,680		558,989		265		(241,718)		625,216

Income (Loss) from Operations		304,632		(226,202)		(265)		241,718		319,883
Other (Expense) Income
Equity in earnings of subsidiaries		(35,915)		(4)		-		35,919		-
Interest expense		(957)		(67,229)		(1,460)		-		(69,646)
Loss on mark-to-market derivative contracts		(32,084)		-		-		-		(32,084)
Gain on investment measured at fair value		110,561		-		-		-		110,561
Other income (expense)		695		956		(101)		-		1,550

Income (Loss) Before Income Taxes		346,932		(292,479)		(1,826)		277,637		330,264
Income tax (expense) benefit		(151,061)		108,434		684		(92,450)		(134,393)

Net Income (Loss)	$	195,871	$	(184,045)	$	(1,142)	$	185,187	$	195,871

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

SIX MONTHS ENDED JUNE 30, 2010

(in thousands of dollars)


	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	463,767	$	88,500	$	-	$	-	$	552,267
Gas sales		40,990		154,427		-		-		195,417
Other operating revenues		516		443		-		-		959

		505,273		243,370		-		-		748,643

Costs and Expenses
Production costs		145,859		64,955		-		-		210,814
General and administrative		46,362		21,234		95		-		67,691
Depreciation, depletion, amortization and accretion		115,318		62,962		-		76,741		255,021
Impairment of oil and gas properties		-		-		59,475		-		59,475
Legal recovery		-		(8,423)		-		-		(8,423)
Other operating income		-		(4,514)		-		-		(4,514)

		307,539		136,214		59,570		76,741		580,064

Income (Loss) from Operations		197,734		107,156		(59,570)		(76,741)		168,579
Other (Expense) Income
Equity in earnings of subsidiaries		(43,883)		(10)		-		43,893		-
Interest expense		(30)		(48,019)		(1,043)		-		(49,092)
Debt extinguishment costs		(728)		-		-		-		(728)
Gain on mark-to-market derivative contracts		65,840		-		-		-		65,840
Other income (expense)		623		12,063		(145)		-		12,541

Income (Loss) Before Income Taxes		219,556		71,190		(60,758)		(32,848)		197,140
Income tax (expense) benefit		(115,653)		(27,956)		2,938		47,434		(93,237)

Net Income (Loss)	$	103,903	$	43,234	$	(57,820)	$	14,586	$	103,903

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2011

(in thousands of dollars)


	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	195,871	$	(184,045)	$	(1,142)	$	185,187	$	195,871
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		97,193		438,396		-		(241,718)		293,871
Equity in earnings of subsidiaries		35,915		4		-		(35,919)		-
Deferred income tax expense (benefit)		14,895		(44,787)		(547)		164,073		133,634
Loss on mark-to-market derivative contracts		32,084		-		-		-		32,084
Gain on investment measured at fair value		(110,561)		-		-		-		(110,561)
Non-cash compensation		20,771		7,260		-		-		28,031
Other non-cash items		608		(977)		67		-		(302)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		11,694		(33,567)		403		-		(21,470)
Accounts payable and other liabilities		(26,391)		12,265		23		-		(14,103)
Income taxes receivable/payable		40,370		-		-		-		40,370

Net cash provided by (used in) operating activities		312,449		194,549		(1,196)		71,623		577,425


CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(396,404)		(403,651)		(115)		-		(800,170)
Acquisition of oil and gas properties		(7,086)		(25,370)		-		-		(32,456)
Proceeds from sales of oil and gas properties, net of costs and expenses		11,987		-		-		-		11,987
Derivative settlements		(30,039)		-		-		-		(30,039)
Additions to other property and equipment		(4,021)		(443)		(2,070)		-		(6,534)

Net cash used in investing activities		(425,563)		(429,464)		(2,185)		-		(857,212)


CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		2,679,200		-		-		-		2,679,200
Repayments of revolving credit facilities		(2,989,200)		-		-		-		(2,989,200)
Proceeds from issuance of Senior Notes		600,000		-		-		-		600,000
Costs incurred in connection with financing arrangements		(11,320)		-		-		-		(11,320)
Investment in and advances to affiliates		(166,791)		234,914		3,500		(71,623)		-
Other		4		-		-		-		4

Net cash provided by financing activities		111,893		234,914		3,500		(71,623)		278,684

Net (decrease) increase in cash and cash equivalents		(1,221)		(1)		119		-		(1,103)
Cash and cash equivalents, beginning of period		6,020		8		406		-		6,434

Cash and cash equivalents, end of period	$	4,799	$	7	$	525	$	-	$	5,331

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

SIX MONTHS ENDED JUNE 30, 2010

(in thousands of dollars)


	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	103,903	$	43,234	$	(57,820)	$	14,586	$	103,903
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		115,318		62,962		59,475		76,741		314,496
Equity in earnings of subsidiaries		43,883		10		-		(43,893)		-
Deferred income tax (benefit) expense		(263,821)		76,251		(2,992)		276,389		85,827
Debt extinguishment costs		728		-		-		-		728
Gain on mark-to-market derivative contracts		(65,840)		-		-		-		(65,840)
Non-cash compensation		17,722		5,233		-		-		22,955
Other non-cash items		2,659		(1,185)		198		-		1,672
Change in assets and liabilities from operating activities
Accounts receivable and other assets		28,972		(2,870)		1,129		-		27,231
Accounts payable and other liabilities		(16,092)		(15,290)		17		-		(31,365)
Income taxes receivable/payable		14,825		-		-		-		14,825

Net cash (used in) provided by operating activities		(17,743)		168,345		7		323,823		474,432


CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(255,650)		(299,751)		(2,985)		-		(558,386)
Acquisition of oil and gas properties		(59)		43,982		-		-		43,923
Proceeds from sales of oil and gas properties		7,230		-		-		-		7,230
Derivative settlements		(16,153)		-		-		-		(16,153)
Additions to other property and equipment		(1,447)		(1)		(2,946)		-		(4,394)

Net cash used in investing activities		(266,079)		(255,770)		(5,931)		-		(527,780)


CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		860,455		-		-		-		860,455
Repayments of revolving credit facilities		(1,090,455)		-		-		-		(1,090,455)
Proceeds from issuance of Senior Notes		300,000		-		-		-		300,000
Costs incurred in connection with financing arrangements		(5,932)		-		-		-		(5,932)
Investment in and advances to affiliates		229,851		87,422		6,550		(323,823)		-

Net cash provided by financing activities		293,919		87,422		6,550		(323,823)		64,068

Net increase (decrease) in cash and cash equivalents		10,097		(3)		626		-		10,720
Cash and cash equivalents, beginning of period		1,304		11		544		-		1,859

Cash and cash equivalents, end of period	$	11,401	$	8	$	1,170	$	-	$	12,579

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, 2010.

Company Overview

We are an independent energy company engaged in the upstream oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are located in the United States. We own oil and gas properties with principal operations in:

• Onshore California;

• Offshore California;

• the Gulf Coast Region;

• the Mid-Continent Region; and

• the Rocky Mountains.

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 California, Haynesville Shale, Eagle Ford Shale and Granite/Atoka Wash resource plays. 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 assets include 51.0 million shares of McMoRan common stock, approximately 32.2% of their common shares outstanding. We measure our equity investment at fair value. Unrealized gains and losses on the investment are reported in our income statement and could result in volatility in our earnings. See Item 3 – Quantitative and Qualitative Disclosures About Market Risk – Equity Price Risk.

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 various derivative instruments to manage our exposure to 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 agreements 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 mark-to-market derivative contracts in 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 – Commodity Price 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. The markets for oil and gas have historically 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. 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 June 30, 2011, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 30%.

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, gathering and transportation costs and other costs necessary to operate our producing properties. Depreciation, depletion and amortization, or DD&A, for 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 expense, or G&A, consists primarily of salaries and related benefits of administrative personnel (including stock-based compensation), office rent, systems costs and other administrative costs.

Results Overview

For the six months ended June 30, 2011, we reported net income of $195.9 million, or $1.37 per diluted share, compared to net income of $103.9 million, or $0.73 per diluted share, for the six months ended June 30, 2010. The increase primarily reflects higher oil prices and a gain on our investment in McMoRan partially offset by a loss on mark-to-market derivative contracts. Additionally in 2010, an impairment of oil and gas properties was recorded. Significant transactions which affect comparisons between the periods include the divestment of our U.S. Gulf of Mexico shallow water shelf properties to McMoRan and the acquisition of Eagle Ford Shale properties during the fourth quarter 2010.

Results of Operations

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Sales Volumes
Oil and liquids sales (MBbls)		4,416		4,131		8,382		8,201
Gas (MMcf)
Production		27,405		22,110		51,635		44,123
Used as fuel		534		480		1,055		958
Sales		26,871		21,630		50,580		43,165
MBOE
Production		8,984		7,816		16,988		15,554
Sales		8,894		7,736		16,812		15,395
Daily Average Volumes
Oil and liquids sales (Bbls)		48,524		45,395		46,308		45,307
Gas (Mcf)
Production		301,162		242,961		285,280		243,773
Used as fuel		5,874		5,272		5,831		5,292
Sales		295,288		237,689		279,449		238,481
BOE
Production		98,718		85,889		93,855		85,935
Sales		97,739		85,010		92,883		85,053
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	102.34	$	78.05	$	98.50	$	78.46
Gas		4.32		4.09		4.20		4.67
Average Realized Sales Price
Before Derivative Transactions
Oil (per Bbl)	$	90.42	$	66.87	$	87.23	$	67.34
Gas (per Mcf)		4.23		4.05		4.16		4.52
Per BOE		57.68		47.05		56.01		48.57
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	9.23	$	7.44	$	9.19	$	7.80
Steam gas costs		1.90		1.99		1.94		2.27
Electricity		1.17		1.44		1.20		1.37
Production and ad valorem taxes		1.90		0.49		1.69		0.80
Gathering and transportation		1.89		1.67		1.76		1.45
DD&A (oil and gas properties)		16.28		15.33		16.28		15.33

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Oil derivatives	$	(15,018)	$	(17,854)	$	(30,659)	$	(32,403)
Natural gas derivatives		-		11,161		620		16,250

	$	(15,018)	$	(6,693)	$	(30,039)	$	(16,153)

Comparison of Three Months Ended June 30, 2011 to Three Months Ended June 30, 2010

Oil and gas revenues. Oil and gas revenues increased $149.1 million, to $513.0 million for 2011 from $363.9 million for 2010 due to higher average realized prices and higher sales volumes.

Oil revenues increased $123.0 million to $399.3 million for 2011 from $276.3 million for 2010 reflecting higher average realized prices ($97.3 million) and higher sales volumes ($25.7 million). Our average realized price for oil increased $23.55 per Bbl to $90.42 per Bbl for 2011 from $66.87 per Bbl for 2010. Oil sales volumes increased 3.1 MBbls per day to 48.5 MBbls per day in 2011 from 45.4 MBbls per day in 2010, primarily reflecting increased production from our Panhandle properties and our Eagle Ford Shale acquisition, partially offset by a production decrease due to the December 2010 divestment of our Gulf of Mexico shallow water properties. Excluding the impact of our divestment in 2010, production increased 5.4 MBbls per day in 2011.

We have entered into a new marketing contract with ConocoPhillips effective January 1, 2012 for our California crude oil production that extends the dedication from January 1, 2015 to January 1, 2023 and replaces the percent of NYMEX index pricing with a market-based pricing approach. Due to this and other new marketing contracts, we expect oil price realizations on a significant portion of our crude oil production to increase beginning in 2012.

Gas revenues increased $26.0 million to $113.7 million in 2011 from $87.7 million in 2010 reflecting higher sales volumes ($22.2 million) and higher average realized prices ($3.8 million). Gas sales volumes increased 57.6 MMcf per day to 295.3 MMcf per day in 2011 from 237.7 MMcf per day in 2010, primarily reflecting increased production from our Haynesville Shale and Panhandle properties partially offset by a production decrease due to the December 2010 divestment of our Gulf of Mexico shallow water properties. Excluding the impact of our divestment in 2010, sales increased 93.9 MMcf per day in 2011. Our average realized price for gas was $4.23 per Mcf in 2011 compared to $4.05 per Mcf in 2010.

Lease operating expenses . Lease operating expenses increased $24.6 million, to $82.1 million in 2011 from $57.5 million in 2010, reflecting an increased number of producing wells at our Eagle Ford Shale and Panhandle properties and higher scheduled repair and maintenance and well workovers primarily at our California properties.

Production and ad valorem taxes. Production and ad valorem taxes increased $13.1 million, to $16.9 million in 2011 from $3.8 million in 2010, reflecting higher ad valorem taxes at our California and Haynesville Shale properties. The increase in production taxes in 2011 compared to 2010 results from production tax abatements recorded in 2010 and increased production primarily from our Panhandle properties in 2011.

Gathering and transportation expense. Gathering and transportation expenses increased $3.9 million, to $16.8 million in 2011 from $12.9 million in 2010, primarily reflecting an increase in production from our Haynesville Shale properties.

Depreciation, depletion and amortization. DD&A expense increased $27.0 million, to $150.8 million in 2011 from $123.8 million in 2010. The increase is attributable to our oil and gas depletion, primarily due to increased production ($19.0 million) and a higher per unit rate ($7.4 million). Our oil and gas unit of production rate increased to $16.28 per BOE in 2011 compared to $15.33 per BOE in 2010.

Impairment of oil and gas properties . During the three months ended June 30, 2010, we completed our interpretation of seismic and drilling data from our two offshore Vietnam exploratory wells and decided not to pursue additional exploratory activities in this area. The costs related to Vietnam oil and gas properties not subject to amortization were transferred to our Vietnam full cost pool where they were subject to the ceiling test limitation. Because our Vietnam full cost pool had no associated proved oil and gas reserves, we recorded a non-cash pre-tax impairment charge of $59.5 million.

Interest expense. Interest expense increased $9.2 million, to $37.2 million in 2011 from $28.0 million in 2010, primarily due to greater average debt outstanding partially offset by lower average interest rates and higher capitalized interest. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization but in the process of development. We capitalized $33.5 million and $32.1 million of interest in 2011 and 2010, respectively.

Gain (loss) 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 in our 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 an $18.9 million gain related to mark-to-market derivative contracts in the second quarter of 2011, which was primarily associated with an increase in the fair value of our 2011 crude oil and natural gas collars due to lower forward prices. In the second quarter of 2010, we recognized a $58.0 million gain related to mark-to-market derivative contracts.

Gain on investment measured at fair value. At June 30, 2011, we owned 51.0 million shares of McMoRan common stock. We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as gain on investment measured at fair value in our income statement.

We recognized a $43.3 million gain in the second quarter of 2011 related to our McMoRan investment, which was primarily associated with (i) an increase in McMoRan’s stock price and (ii) a lower discount on the marketability of the shares due to a reduced term on the restrictions and lower volatility of the instrument.

Income taxes. For the second quarter of 2011, income tax expense was approximately 41% of pre-tax income. The variance between this effective tax rate and the 35% federal statutory rate results primarily from the tax effects of estimated annual permanent differences including (i) expenses that are not deductible because of IRS limitations and (ii) state income taxes.

For the second quarter of 2010, income tax expense was approximately 50% of pre-tax income. The effective tax rate of 50% resulted primarily from expenses that are not deductible because of IRS limitations and state income taxes partially offset by a tax benefit related to the impairment of our Vietnam oil and gas properties.

Comparison of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2010

Oil and gas revenues. Oil and gas revenues increased $193.9 million, to $941.6 million for 2011 from $747.7 million for 2010 primarily due to higher average realized oil prices and higher sales volumes partially offset by lower average realized gas prices.

Oil revenues increased $178.8 million to $731.1 million for 2011 from $552.3 million for 2010 reflecting higher average realized prices ($163.1 million) and higher sales volumes ($15.7 million). Our average realized price for oil increased $19.89 per Bbl to $87.23 per Bbl for 2011 from $67.34 per Bbl for 2010.

Gas revenues increased $15.1 million to $210.5 million in 2011 from $195.4 million in 2010 reflecting higher sales volumes ($30.9 million), partially offset by lower average realized prices ($15.8 million). Gas sales volumes increased 40.9 MMcf per day to 279.4 MMcf per day in 2011 from 238.5 MMcf per day in 2010, primarily reflecting increased production from our Haynesville Shale and Panhandle properties partially offset by a production decrease due to the December 2010 divestment of our Gulf of Mexico shallow water properties. Excluding the impact of our divestment in 2010, sales increased 83.8 MMcf per day in 2011. Our average realized price for gas was $4.16 per Mcf in 2011 compared to $4.52 per Mcf in 2010.

Lease operating expenses . Lease operating expenses increased $34.4 million, to $154.4 million in 2011 from $120.0 million in 2010, reflecting an increased number of producing wells at our Eagle Ford Shale and Panhandle properties and higher scheduled repair and maintenance primarily at our California properties.

Production and ad valorem taxes. Production and ad valorem taxes increased $16.1 million, to $28.4 million in 2011 from $12.3 million in 2010, reflecting higher ad valorem taxes at our California and Haynesville Shale properties. The increase in production taxes in 2011 compared to 2010 results from production tax abatements recorded in 2010 and increased production primarily from our Panhandle properties in 2011.

Gathering and transportation expense. Gathering and transportation expenses increased $7.3 million, to $29.6 million in 2011 from $22.3 million in 2010, primarily reflecting an increase in production from our Haynesville Shale properties.

Depreciation, depletion and amortization. DD&A expense increased $39.1 million, to $285.3 million in 2011 from $246.2 million in 2010. The increase is attributable to our oil and gas depletion, primarily due to increased production ($23.3 million) and a higher per unit rate ($14.8 million). Our oil and gas unit of production rate increased to $16.28 per BOE in 2011 compared to $15.33 per BOE in 2010.

Impairment of oil and gas properties . During the six months ended June 30, 2010, we completed our interpretation of seismic and drilling data from our two offshore Vietnam exploratory wells and decided not to pursue additional exploratory activities in this area. The costs related to Vietnam oil and gas properties not subject to amortization were transferred to our Vietnam full cost pool where they were subject to the ceiling test limitation. Because our Vietnam full cost pool had no associated proved oil and gas reserves, we recorded a non-cash pre-tax impairment charge of $59.5 million.

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 increased $20.5 million, to $69.6 million in 2011 from $49.1 million in 2010, primarily due to greater average debt outstanding and lower capitalized interest partially offset by lower average interest rates. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization but in the process of development. We capitalized $64.6 million and $66.4 million of interest in 2011 and 2010, respectively.

We recognized a $32.1 million loss related to mark-to-market derivative contracts in the six months ended June 30, 2011, which was primarily associated with a decrease in fair value of our 2011 and 2012 crude oil puts due to higher crude oil forward prices partially offset by an increase in fair value of our 2011 natural gas collars due to lower natural gas forward prices. In the six months ended June 30, 2010, we recognized a $65.8 million gain related to mark-to-market derivative contracts.

We recognized a $110.6 million gain in the six months ended June 30, 2011 related to our McMoRan investment, which was primarily associated with (i) a lower discount on the marketability of the shares due to a reduced term on the restrictions and lower volatility of the instrument and (ii) an increase in McMoRan’s stock price.

Income taxes. For the six months ended June 30, 2011, our income tax expense was approximately 41% of pre-tax income. The variance between this effective tax rate and the 35% federal statutory rate results primarily from the tax effects of estimated annual permanent differences including (i) expenses that are not deductible because of IRS limitations and (ii) state income taxes.

For the six months ended June 30, 2010, our income tax expense was approximately 47% of pre-tax income. The effective tax rate of 47% resulted primarily from expenses that are not deductible because of IRS limitations, state income taxes and adjustments to deferred taxes for differences in the reporting of stock-based compensation expense for financial statement and income tax reporting purposes partially offset by a tax benefit related to the impairment of our Vietnam oil and gas properties.

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 these agreements. These situations 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. Volatility and disruption in the financial and credit markets 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 June 30, 2011, we had approximately $1.1 billion available for future secured borrowings under our senior revolving credit facility, which had aggregate commitments and a borrowing base of $1.4 billion and $1.8 billion, respectively. Declines in oil and gas prices may adversely affect our liquidity by lowering the amount of the borrowing base that lenders are willing to extend.

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. At June 30, 2011, the commitments are from a diverse syndicate of 21 lenders and no single lender’s commitment represented more than 7% 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 various derivative instruments to manage our exposure to 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 agreements and subjects us to the credit risk of the counterparties to such agreements. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. See Item 3 – Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.

We have made and will continue to make substantial capital expenditures for the acquisition, development, exploration and production of oil and gas. In August 2011, we revised our 2011 capital budget to $1.5 billion from $1.2 billion. The increase reflects our accelerated drilling activity in the Eagle Ford Shale and a higher than originally planned rig count in the Haynesville Shale. We intend to fund our 2011 capital budget from internally generated funds and borrowings under our senior revolving credit facility. In addition, we could curtail the portion of our capital expenditures that is discretionary if our cash flows decline from expected levels.

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. Our senior revolving credit facility matures on May 4, 2016 and the next maturity of our senior notes will occur on June 15, 2015.

Working Capital

At June 30, 2011, we had a working capital deficit of approximately $214.3 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

Senior Revolving Credit Facility. In April 2011, our borrowing base increased to $1.8 billion from $1.45 billion. The commitments remained unchanged at $1.4 billion. In May 2011, we entered into an amendment to our senior revolving credit facility. The amendment adjusted our borrowing rates and the maturity date was extended to May 4, 2016. The borrowing base will be redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors. Additionally, our senior revolving credit facility contains a $250 million limit on letters of credit and a $50 million commitment for swingline loans. At June 30, 2011, our availability for future secured borrowings under our senior revolving credit facility was approximately $1.1 billion and we had $310 million in outstanding borrowings and $1.2 million in letters of credit outstanding under our senior revolving credit facility. The daily average outstanding balance for the three and six months ended June 30, 2011 was $216.0 million and $424.2 million, respectively.

Short-term Credit Facility. We have an uncommitted short-term unsecured credit facility under which we may make borrowings from time to time, until June 1, 2012, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding 14 days and all amounts outstanding are due and payable no later than June 1, 2012. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and us.

6 ⁵ / 8 % Senior Notes. In March 2011, we issued $600 million of 6 ⁵ / 8 % Senior Notes at par. We received approximately $590 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 6 ⁵ / 8 % Senior Notes on or after May 1, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to May 1, 2014 we may, at our option, redeem up to 35% of the 6 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 6 ⁵ / 8 % Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

Cash Flows


	Six Months Ended June 30,
	2011		2010
	(in millions)
Cash provided by (used in):
Operating activities	$	577.4	$	474.4
Investing activities		(857.2)		(527.8)
Financing activities		278.7		64.1

Net cash provided by operating activities was $577.4 million for the six months ended June 30, 2011 compared to $474.4 million for the six months ended June 30, 2010. The increase primarily reflects higher operating income in 2011 as a result of higher average realized oil prices and a $40.4 million refund of income tax paid in prior years.

Net cash used in investing activities of $857.2 million for the six months ended June 30, 2011 primarily reflects additions to oil and gas properties of $800.2 million. Net cash used in investing activities of $527.8 million for the six months ended June 30, 2010 primarily reflects additions to oil and gas properties of $558.4 million, offset by a $43.9 million cash inflow primarily 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 financing activities of $278.7 million for the six months ended June 30, 2011 primarily reflects proceeds from the $600 million offering of 6 ⁵ / 8 % Senior Notes partially offset by the net reduction in borrowings under our senior revolving credit facility of $310.0 million. Net cash provided by financing activities of $64.1 million for the six months ended June 30, 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.

Stock Repurchase Program

Our board of directors has authorized the repurchase of shares 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 such information over different reporting periods. All such 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, goodwill and income taxes are discussed in our Annual Report on Form 10-K for the year ended December 31, 2010.

Recent Accounting Pronouncements

In December 2010, the FASB issued authoritative guidance clarifying the acquisition date that should be used for reporting the pro forma financial information disclosures when comparative financial statements are presented. The guidance also improves the usefulness of the pro forma revenue and earnings disclosures by requiring a description of the nature and amount of material, nonrecurring pro forma adjustments that are directly attributable to the business combination. We adopted the provisions of this standard effective January 1, 2011, 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;

•

the effects of future laws and governmental regulation that result from the Macondo accident and oil spill in the U.S. Gulf of Mexico;

•

the value of the common stock of McMoRan and our ability to dispose of those shares;

•

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, 2010.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our primary market risk is oil and gas commodity prices. The markets for oil and gas have historically been volatile and are likely to continue to be volatile in the future. We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized currently in our income statement as a gain or loss on mark-to-market derivative contracts. Cash flows are only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. The derivative instruments we have in place are not classified as hedges for accounting purposes.

See Note 3 – Commodity Derivative Contracts and Note 5 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our derivative activities and fair value measurements.

As of June 30, 2011, we had the following outstanding commodity derivative contracts, all of which settle monthly:


Period	Instrument Type	Daily Volumes	Average Price ⁽¹⁾	Average Deferred Premium	Index
Sales of Crude Oil Production
2011
July - Dec	Put options ⁽²⁾	31,000 Bbls	$80.00 Floor with a $60.00 Limit	$5.023 per Bbl	WTI
July - Dec	Three-way collars ⁽³⁾	9,000 Bbls	$80.00 Floor with a $60.00 Limit	$1.00 per Bbl	WTI
			$110.00 Ceiling
2012
Jan - Dec	Put options ⁽²⁾	40,000 Bbls	$80.00 Floor with a $60.00 Limit	$6.087 per Bbl	WTI

Sales of Natural Gas Production
2011
July - Dec	Three-way collars ⁽⁴⁾	200,000 MMBtu	$4.00 Floor with a $3.00 Limit	-	Henry Hub
			$4.92 Ceiling
2012
Jan - Dec	Put options ⁽⁵⁾	160,000 MMBtu	$4.30 Floor with a $3.00 Limit	$0.294 per MMBtu	Henry Hub

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

(2)	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. If the index price is at or above $80 per barrel, we pay only the option premium.

(3)

(4)

(5)	If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium. If the index price is at or above $4.30 per MMBtu, we pay only the option premium.

The fair value of outstanding crude oil and natural gas commodity derivative instruments at June 30, 2011 and the change in fair value that would be expected from a 10% price increase or decrease is shown below (in millions):


			Effect of 10%
	Fair Value Asset		Price Increase		Price Decrease

Crude oil put options	$	49	$	(19)	$	32
Crude oil collars		(1)		(5)		4
Natural gas collars		(2)		(8)		7
Natural gas put options		14		(6)		9

	$	60	$	(38)	$	52

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.

Equity Price Risk

We are exposed to market risk because we own an equity investment in McMoRan common stock. See Note 4 – Investment and Note 5 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our equity investment. At June 30, 2011, the investment, comprised of 51.0 million shares of McMoRan common stock, was valued at approximately $774.9 million. A 10% change in the underlying equity market price per share would result in a $77.5 million increase or decrease in the fair value of our investment, recognized in the income statement.

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) of 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 June 30, 2011 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 June 30, 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 5. Other Information

ITEM 6. Exhibits


Exhibit No.		Description

4.1		Amendment No. 2 to Amended and Restated Credit Agreement, dated as of May 4, 2011, 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 May 5, 2011, File No. 1-31470).

10.1*		Crude Oil Purchase Agreement dated January 1, 2012, between Plains Exploration & Production Company and ConocoPhillips Company.

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 Extension Presentation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

*	Filed herewith

Items 1, 1A, 2 and 3 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: August 4, 2011
	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		Amendment No. 2 to Amended and Restated Credit Agreement, dated as of May 4, 2011, 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 May 5, 2011, File No. 1-31470).

10.1*		Crude Oil Purchase Agreement dated January 1, 2012, between Plains Exploration & Production Company and ConocoPhillips Company.

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 Extension Presentation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document