Plains Exploration & Production 10-Q 2012 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2012

OR

¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-31470

PLAINS EXPLORATION & PRODUCTION COMPANY

(Exact name of registrant as specified in its charter)

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

700 Milam Street, Suite 3100

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 579-6000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    

Yes  x    No  ¨

Indicate by check mark whether the registrant 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 filerx	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

129.0 million shares of Common Stock, $0.01 par value, issued and outstanding at October 26, 2012.

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PART  I.  FINANCIAL INFORMATION
ITEM 1.  Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets September 30, 2012 and December 31, 2011	1
Consolidated Statements of Income For the three months ended and nine months ended September  30, 2012 and 2011	2
Consolidated Statements of Cash Flows For the nine months ended September 30, 2012 and 2011	3
Consolidated Statement of Equity For the nine months ended September 30, 2012	4
Notes to Consolidated Financial Statements	5
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk	54
ITEM 4. Controls and Procedures	57
PART  II. OTHER INFORMATION	58

(i)

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	September 30, 2012		December 31, 2011
ASSETS
Current Assets
Cash and cash equivalents	$	217,018	$	419,098
Accounts receivable		315,195		302,675
Commodity derivative contracts		26,302		50,964
Inventories		19,076		20,173
Investment		519,370		611,671
Deferred income taxes		166,002		20,723
Prepaid expenses and other current assets		24,644		16,073
		1,287,607		1,441,377
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		14,083,960		12,016,252
Not subject to amortization		1,718,876		2,409,449
Other property and equipment		150,031		145,959
		15,952,867		14,571,660
Less allowance for depreciation, depletion, amortization and impairment		(7,473,140)		(6,846,365)
		8,479,727		7,725,295
Goodwill		535,140		535,140
Commodity Derivative Contracts		19,459		12,678
Deposit Related to the Gulf of Mexico Acquisition		555,000		-
Other Assets		97,862		76,982
	$	10,974,795	$	9,791,472
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	470,284	$	385,231
Commodity derivative contracts		8,253		3,761
Royalties and revenues payable		130,820		97,095
Stock-based compensation		17,405		21,676
Interest payable		88,588		39,342
Other current liabilities		63,194		79,081
		778,544		626,186
Long-Term Debt		4,516,571		3,760,952
Other Long-Term Liabilities
Asset retirement obligation		242,390		230,633
Commodity derivative contracts		4,239		823
Other		17,133		15,749
		263,762		247,205
Deferred Income Taxes		1,691,473		1,461,897
Commitments and Contingencies (Note 9)
Equity
Stockholders’ equity
Common stock, $0.01 par value, 250.0 million shares authorized, 143.9 million shares issued at September 30, 2012 and December 31, 2011		1,439		1,439
Additional paid-in capital		3,426,909		3,434,928
Retained earnings		418,789		337,991
Treasury stock, at cost, 15.0 million shares and 13.3 million shares at September 30, 2012 and December 31, 2011, respectively		(560,244)		(509,722)
		3,286,893		3,264,636
Noncontrolling interest
Preferred stock of subsidiary		437,552		430,596
		3,724,445		3,695,232
	$	10,974,795	$	9,791,472

See notes to consolidated financial statements.

1

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

	Three Months Ended     September 30,				Nine Months Ended     September 30,
	2012		2011		2012		2011
Revenues
Oil sales	$	540,434	$	379,079	$	1,527,430	$	1,110,228
Gas sales		62,630		121,014		162,113		331,486
Other operating revenues		2,040		1,755		6,560		5,233
		605,104		501,848		1,696,103		1,446,947
Costs and Expenses
Lease operating expenses		98,087		79,987		268,755		234,380
Steam gas costs		12,096		17,015		32,931		49,641
Electricity		9,930		10,112		32,081		30,203
Production and ad valorem taxes		21,066		10,636		52,782		39,084
Gathering and transportation expenses		19,218		15,237		54,519		44,825
General and administrative
G&A		32,515		28,158		102,598		94,964
Acquisition related costs		6,683		-		6,683		-
Depreciation, depletion and amortization		270,598		167,894		699,025		453,194
Accretion		3,749		4,307		11,252		12,878
Other operating income		(605)		(50)		(3,142)		(657)
		473,337		333,296		1,257,484		958,512
Income from Operations		131,767		168,552		438,619		488,435
Other (Expense) Income
Interest expense		(59,174)		(43,495)		(157,404)		(113,141)
Debt extinguishment costs		-		-		(5,167)		-
(Loss) gain on mark-to-market derivative contracts		(100,160)		125,551		12,573		93,467
Loss on investment measured at fair value		(43,121)		(395,490)		(92,301)		(284,929)
Other income		11		1,399		440		2,949
(Loss) Income Before Income Taxes		(70,677)		(143,483)		196,760		186,781
Income tax benefit (expense)
Current		3,540		26,718		2,535		25,959
Deferred		23,163		28,469		(84,297)		(105,165)
Net (Loss) Income		(43,974)	$	(88,296)		114,998	$	107,575
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		(9,114)				(27,206)
Net (Loss) Income Attributable to Common Stockholders	$	(53,088)			$	87,792
(Loss) Earnings per Common Share
Basic	$	(0.41)	$	(0.62)	$	0.68	$	0.76
Diluted	$	(0.41)	$	(0.62)	$	0.67	$	0.75
Weighted Average Common Shares Outstanding
Basic		130,047		141,826		129,806		141,500
Diluted		130,047		141,826		131,774		143,351

See notes to consolidated financial statements.

2

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

	Nine Months Ended
	September 30,
	2012		2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	114,998	$	107,575
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		699,025		453,194
Accretion		11,252		12,878
Deferred income tax expense		84,297		105,165
Debt extinguishment costs		939		-
Gain on mark-to-market derivative contracts		(12,573)		(93,467)
Loss on investment measured at fair value		92,301		284,929
Non-cash compensation		37,898		27,257
Other non-cash items		10,431		(6,332)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(13,882)		(21,355)
Accounts payable and other liabilities		17,013		31,975
Income taxes receivable/payable		4,878		20,831
Net cash provided by operating activities		1,046,577		922,650
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(1,388,356)		(1,261,196)
Acquisition of oil and gas properties		(26,377)		(36,750)
Deposit related to the Gulf of Mexico Acquisition		(555,000)		-
Proceeds from sales of oil and gas properties, net of costs and expenses		60,470		11,987
Derivative settlements		37,385		(47,448)
Additions to other property and equipment		(9,271)		(9,454)
Other		-		1,552
Net cash used in investing activities		(1,881,149)		(1,341,309)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		6,756,425		4,026,900
Repayments of revolving credit facilities		(6,596,425)		(4,191,900)
Principal payments of long-term debt		(156,182)		-
Proceeds from issuance of Senior Notes		750,000		600,000
Costs incurred in connection with financing arrangements		(12,586)		(11,320)
Purchase of treasury stock		(88,490)		-
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		(20,250)		-
Other		-		9
Net cash provided by financing activities		632,492		423,689
Net (decrease) increase in cash and cash equivalents		(202,080)		5,030
Cash and cash equivalents, beginning of period		419,098		6,434
Cash and cash equivalents, end of period	$	217,018	$	11,464

See notes to consolidated financial statements.

3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF EQUITY (Unaudited)

(share and dollar amounts in thousands)

															Noncontrolling
															Interest
															in the
					Additional								Total		Form of
	Common Stock				Paid-in		Retained		Treasury Stock				Stockholders’		Preferred Stock		Total
	Shares		Amount		Capital		Earnings		Shares		Amount		Equity		of Subsidiary		Equity
Balance at December 31, 2011		143,924	$	1,439	$	3,434,928	$	337,991		(13,302)		$(509,722)	$	3,264,636	$	430,596	$	3,695,232
Net income		-		-		-		87,792		-		-		87,792		27,206		114,998
Restricted stock awards		-		-		22,941		-		-		-		22,941		-		22,941
Treasury stock purchases		-		-		-		-		(2,390)		(88,490)		(88,490)		-		(88,490)
Issuance of treasury stock for restricted stock awards		-		-		(30,960)		(6,990)		732		37,950		-		-		-
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		-		-		-		-		-		-		-		(20,250)		(20,250)
Exercise of stock options and other		-		-		-		(4)		-		18		14		-		14
Balance at September 30, 2012		143,924	$	1,439	$	3,426,909	$	418,789		(14,960)	$	(560,244)	$	3,286,893	$	437,552	$	3,724,445

See notes to consolidated financial statements.

4

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 consolidated subsidiaries. We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. 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 nine months ended September 30, 2012 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, 2011.

Asset Retirement Obligation.    The following table reflects the changes in our asset retirement obligation during the nine months ended September 30, 2012 (in thousands):

Asset retirement obligation - December 31, 2011	$	238,381
Property dispositions and other		(1,852)
Settlements		(3,280)
Accretion expense		11,252
Asset retirement additions		3,776
Asset retirement obligation - September 30, 2012 (1)	$	248,277

(1) $5.9 million is included in other current liabilities.

Earnings Per Share. For the three and nine months ended September 30, 2012 and 2011, the weighted average shares outstanding for computing basic and diluted earnings per share were (in thousands):

	Three Months Ended   September 30,				Nine Months Ended   September 30,
	2012		2011		2012		2011
Weighted average common shares outstanding - basic		130,047		141,826		129,806		141,500
Unvested restricted stock, restricted stock units and stock options		-		-		1,968		1,851
Weighted average common shares outstanding - diluted		130,047		141,826		131,774		143,351

5

Because we recognized a net loss for the three months ended September 30, 2012 and 2011, no unvested restricted stock, unvested restricted stock units, or RSUs, or stock options were included in computing earnings per share as the effect was antidilutive. In the nine months ended September 30, 2012 and 2011, 0.3 million and 1.5 million RSUs, 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 our earnings per share for the three and nine months ended September 30, 2012, we decreased our reported net income by $9.1 million and $27.2 million, respectively, for preferred stock dividends attributable to the noncontrolling interest associated with our consolidated subsidiary Plains Offshore Operations Inc., or Plains Offshore. We owned 100% of the common shares of Plains Offshore during the three and nine months ended September 30, 2012, and because Plains Offshore had a net loss for the three and nine months ended September 30, 2012, we did not allocate any undistributed earnings to the noncontrolling interest preferred stock. In the event that Plains Offshore has net income in future periods, we will be required to allocate distributed and undistributed earnings between the common and preferred shares of Plains Offshore.

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 September 30, 2012 and December 31, 2011, inventory consisted of the following (in thousands):

	September 30,   2012		December 31,   2011
Oil	$	7,439	$	7,075
Materials and supplies		11,637		13,098
	$	19,076	$	20,173

Oil and Natural Gas Properties Not Subject to Amortization.     The cost of unproved oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are assessed periodically, at least annually, to determine whether impairment has occurred. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The transfer of costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, geological and geophysical evaluations, the assignment of proved reserves, availability of capital, and other factors. The timing of these transfers into our amortization base impacts our depreciation, depletion and amortization, or DD&A, rate and full cost ceiling test.

6

During the first quarter of 2012, due to low natural gas prices, our assessment of the unproved property in the Haynesville Shale area indicated an impairment and accumulated costs of approximately $483 million were transferred to the full cost pool.

Stock-Based Compensation.    Stock-based compensation for the three and nine months ended September 30, 2012 and 2011 was (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Stock-based compensation included in:
General and administrative expense	$	10,395	$	4,847	$	32,587	$	28,212
Lease operating expenses		1,274		(5,621)		5,311		(955)
Oil and natural gas properties		3,919		(168)		11,447		7,327
Total stock-based compensation	$	15,588	$	(942)	$	49,345	$	34,584

During 2012, we granted 877 thousand RSUs at an average fair value of $42.59 per share to be settled in shares of common stock, 1.2 million RSUs at an average fair value of $43.04 per share to be settled in cash and 501 thousand stock appreciation rights with an average exercise price of $42.73 per share.

Additionally, we issued 225 thousand RSUs to be settled in cash that are subject to a market condition in which the price performance of PXP’s common stock is compared to an average of two peer indices. Based on the performance, these units may settle upon vesting at 0% to 150% of the number of awards granted as determined by linear interpolation.

We used a Monte-Carlo simulation model to estimate the fair value of the cash-settled RSUs subject to the market condition. This model involves forecasting potential future stock price paths based on the expected return on our common stock and the indices and their volatility, then calculating the fair value of RSUs to be granted based on the results of the simulations. At September 30, 2012, we estimated that these units had a weighted average fair value of $28.88 per unit, an aggregate fair value of $6.5 million and a weighted average remaining contractual life of 1.5 years.

Stock Repurchase Program.    In January 2012, we repurchased 2.4 million common shares at an average cost of $37.02 per share, totaling $88.5 million. Subsequent to these repurchases, our Board of Directors reset the authorization to $1.0 billion of PXP common stock, all of which is available for repurchase, and extended the program until January 2016.

Noncontrolling Interest in the Form of Preferred Stock of Subsidiary.    Noncontrolling interest in the form of preferred stock of subsidiary represents the ownership interest held by third parties in the net assets of our consolidated subsidiary Plains Offshore, in the form of convertible perpetual preferred stock and associated non-detachable warrants.

The preferred stock of Plains Offshore is classified as permanent equity in our consolidated balance sheet since redemption for cash of the preferred interests is within our and Plains Offshore’s control. The non-detachable warrants are considered to be embedded instruments for accounting purposes as the instrument cannot be both legally detached and separately exercised from the host preferred stock, nor can the non-detachable warrants be transferred or sold without also transferring the ownership in the preferred stock.

7

During the three months ended September 30, 2012, Plains Offshore declared a quarterly dividend on the preferred stock of approximately $9.1 million, or $20.22 per share of preferred stock, $15.00 per share of which was paid in cash with the remaining deferred. During the nine months ended September 30, 2012, Plains Offshore declared quarterly dividends on the preferred stock of approximately $27.2 million, or $60.36 per share of preferred stock, $45.00 per share of which was paid in cash with the remaining deferred. Deferred dividends accumulate and compound quarterly at 8% per year until paid.

Recent Accounting Pronouncements.    In December 2011, the Financial Accounting Standards Board, or FASB, issued authoritative guidance requiring entities to disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as financial instruments and transactions subject to agreements similar to master netting arrangements. The additional disclosures will enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The guidance is effective for interim and annual periods beginning on or after January 1, 2013, and will primarily impact our disclosures associated with our commodity derivative instruments. We are currently evaluating the impact of this guidance.

Note 2 — Proposed Gulf of Mexico Acquisition

On September 10, 2012, we announced that we had entered into a purchase and sale agreement, or the BP PSA, to acquire from BP Exploration & Production Inc. and BP America Production Company, or BP, their interests in certain deepwater Gulf of Mexico oil and gas properties for $5.55 billion in cash, subject to customary purchase price adjustments. These properties include certain oil and gas interests in and near the Holstein, Diana, Hoover, Horn Mountain, Marlin, Dorado, King and Ram Powell fields. Certain of these properties are subject to preferential rights. The BP PSA contains customary representations and warranties, covenants, indemnification provisions and conditions to close. Under the terms of the BP PSA, we made a performance deposit of $555 million to BP, which BP will be permitted to retain as liquidated damages if it terminates the BP PSA under certain circumstances. The performance deposit is classified as Deposit Related to the Gulf of Mexico Acquisition on our balance sheet and was paid through borrowings under our senior revolving credit facility.

On September 10, 2012, we also announced that we had entered into a purchase and sale agreement, or the Shell PSA, to acquire from Shell Offshore, Inc., or Shell, its 50% working interest in the Holstein field for $560 million in cash, subject to customary purchase price adjustments. The Shell PSA contains customary representations and warranties, covenants, indemnification provisions and conditions to close.

We have received commitments from several financial institutions to provide financing in connection with these transactions. A portion of the cash consideration will be paid with the proceeds from our Senior Notes offering completed in October 2012. See Note 3 – Long-Term Debt – Commitment Letter and Subsequent Events.

During the three months ended September 30, 2012, transaction costs related to these acquisitions of approximately $6.7 million have been expensed. Upon closing, we expect to recognize additional estimated acquisition costs of $60 million which consist of (i) a $30 million commitment fee associated with a new senior unsecured bridge credit facility, or Bridge Credit Facility, which will be recorded as interest expense because we will not borrow under the Bridge Credit Facility, (ii) a $20 million amendment fee that we will pay in connection with an amendment to our existing stockholders agreements with the preferred investors of Plains Offshore to limit certain exclusivity provisions and (iii) certain investment, advisory, legal and other acquisition related fees.

These acquisitions, collectively referred to as the Gulf of Mexico Acquisition, are expected to close on November 30, 2012, and will be effective as of October 1, 2012. We will account for these transactions as acquisitions of businesses under purchase accounting rules.

8

Note 3 — Long-Term Debt

At September 30, 2012 and December 31, 2011, long-term debt consisted of (in thousands):

	September 30,   2012		December 31,   2011
Senior revolving credit facility	$	895,000	$	735,000
Plains Offshore senior credit facility		-		-
7  3/4% Senior Notes due 2015		-		79,281
10% Senior Notes due 2016(1)		176,798		175,385
7% Senior Notes due 2017		-		76,901
7  5/8% Senior Notes due 2018		400,000		400,000
6  1/8% Senior Notes due 2019		750,000		-
8  5/8% Senior Notes due 2019(2)		394,773		394,385
7  5/8% Senior Notes due 2020		300,000		300,000
6  5/8% Senior Notes due 2021		600,000		600,000
6  3/4% Senior Notes due 2022		1,000,000		1,000,000
	$	4,516,571	$	3,760,952

(1) The amount is net of unamortized discount of $8.1 million and $9.5 million at September 30, 2012 and December 31, 2011, respectively.

(2) The amount is net of unamortized discount of $5.2 million and $5.6 million at September 30, 2012 and December 31, 2011, respectively.

Senior Revolving Credit Facility.    In February 2012, our borrowing base was increased from $1.8 billion to approximately $2.3 billion until the next scheduled redetermination date on or before May 1, 2013. The commitments remained unchanged at $1.4 billion. 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 factors. We are required, among other things, to make a mandatory prepayment if the combined total borrowings under both our senior revolving credit facility and the Plains Offshore senior credit facility exceed the borrowing base. Additionally, our senior revolving credit facility contains a $250 million limit on letters of credit, a $50 million commitment for swingline loans and matures on May 4, 2016. At September 30, 2012, we had $1.2 million in letters of credit outstanding under our senior revolving credit facility.

Amounts borrowed under our senior revolving credit facility bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 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 is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. 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.

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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.

Plains Offshore Senior Credit Facility.    The aggregate commitments of the lenders under the Plains Offshore senior credit facility are $300 million. The Plains Offshore senior credit facility contains a $50 million limit on letters of credit and matures on November 18, 2016. At September 30, 2012, Plains Offshore had no letters of credit outstanding under its senior credit facility.

Amounts borrowed under the Plains Offshore senior credit facility bear an interest rate, at Plains Offshore’s 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%; or (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%. The additional variable amount of interest payable is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. Letter of credit fees under the Plains Offshore senior 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.

The borrowings under the Plains Offshore senior credit facility are guaranteed on a senior basis by PXP and certain of our subsidiaries, and are secured on apari passu basis by liens on the same collateral that secures PXP’s senior revolving credit facility. The Plains Offshore senior credit facility contains certain affirmative and negative covenants, including limiting Plains Offshore’s ability, among other things, to create liens, incur other indebtedness, make dividends (excluding dividends on preferred stock) or other distributions, make investments, change the nature of Plains Offshore’s business and merge or consolidate, sell assets, enter into certain types of swap agreements and enter into certain transactions with affiliates, as well as other customary events of default, including a cross-default to PXP’s senior revolving credit facility. If an event of default (as defined in our senior revolving credit facility) has occurred and is continuing under our senior revolving credit facility that has not been cured or waived by the lenders thereunder then the Plains Offshore lenders could accelerate and demand repayment of the Plains Offshore senior credit facility.

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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, 2013, 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, 2013. 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 September 30, 2012. The daily average outstanding balance for the three and nine months ended September 30, 2012 was $51.5 million and $47.8 million, respectively.

6  ¹/₈% Senior Notes.    In April 2012, we issued $750 million of 6 ¹/₈% Senior Notes due 2019, or the 6 ¹/₈% Senior Notes, at par. We received approximately $737.5 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, including the redemption of $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes due 2015, or the 7 ³/₄% Senior Notes, and $76.9 million aggregate principal amount of our 7% Senior Notes due 2017, or the 7% Senior Notes. We may redeem all or part of the 6 ¹/₈% Senior Notes on or after June 15, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to June 15, 2015 we may at our option, redeem up to 35% of the 6 ¹/₈% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control triggering event, as defined in the indenture, we will be required to make an offer to repurchase the 6 ¹/₈% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 6 ¹/₈% Senior Notes are general unsecured senior obligations. They are jointly and severally guaranteed by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection with any sale or other disposition of all the capital stock of a subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of such subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as such subsidiary guarantor does not have outstanding any guarantee of any of our or any of our subsidiary guarantor’s indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. The 6 ¹/₈% 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 ¹/₈% Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility and the Plains Offshore senior 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, including indebtedness under the Plains Offshore senior credit facility, which we guarantee, and the shares of preferred stock issued by Plains Offshore.

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Redemption of 7 ³/₄% Senior Notes and 7% Senior Notes.    During the second quarter of 2012, we redeemed the remaining $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes at 101.938% of the principal amount and the remaining $76.9 million aggregate principal amount of our 7% Senior Notes at 103.500% of the principal amount. We made payments totaling $80.8 million and $79.6 million to retire the 7 ³/₄% Senior Notes and the 7% Senior Notes, respectively. During the nine months ended September 30, 2012, we recognized $5.2 million of debt extinguishment costs, including $0.9 million of unamortized debt issue costs in connection with the retirement of these Senior Notes.

Commitment Letter.    In September 2012, we entered into a commitment letter, or the Commitment Letter, to underwrite a new credit facility that will amend and restate our existing senior revolving credit facility and provide for term loan credit facilities, collectively the Amended Credit Facility, increase our borrowing base and provide financing in connection with the Gulf of Mexico Acquisition. The Commitment Letter is subject to certain conditions, including the absence of a material adverse effect under the BP PSA, the execution of satisfactory definitive documentation and other customary closing conditions. Upon satisfaction of these conditions, the aggregate commitments of the lenders under the Amended Credit Facility will be $5.0 billion with an initial borrowing base of $5.3 billion, which includes $300 million related to the Plains Offshore senior credit facility. The Amended Credit Facility will be comprised of a $3.0 billion senior secured five-year revolving credit facility, a $750.0 million senior secured five-year term loan, and a $1.25 billion senior secured seven-year term loan. Under the terms of the Commitment Letter, the lenders may also provide senior unsecured loans in an aggregate principal amount of up to $2.0 billion pursuant to the Bridge Credit Facility. Subsequently in September 2012, we successfully syndicated the Amended Credit Facility and Bridge Credit Facility to a group of banks and institutional lenders.

In connection with the closing of the Gulf of Mexico Acquisition, we expect to enter into our Amended Credit Facility on November 30, 2012. We will use the proceeds provided by the facilities to refinance certain existing indebtedness, to pay the cash consideration for the Gulf of Mexico Acquisition, to pay fees and expenses incurred in connection with the Gulf of Mexico Acquisition and related financing transactions and for general corporate purposes.

Subsequent Events.    In October 2012, we issued (i) $1.5 billion of 6 ¹/₂% Senior Notes due 2020, or the 6 ¹/₂% Senior Notes, and (ii) $1.5 billion of 6 ⁷/₈% Senior Notes due 2023, or the 6 ⁷/₈% Senior Notes, both at par. We received approximately $2.95 billion of net proceeds, after deducting the underwriting discount and offering expenses. We will use the net proceeds to pay a portion of the cash consideration for the Gulf of Mexico Acquisition. Pending the closing of the Gulf of Mexico Acquisition, we intend to use a portion of the net proceeds to repay borrowings outstanding under our senior revolving credit facility. Both the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes contain a mandatory redemption feature that requires us to redeem at par plus accrued but unpaid interest the aggregate principal amount of the 6 ¹/₂% Senior Notes and the 6 ⁷/₈% Senior Notes in cash if either (i) the BP PSA is terminated or (ii) the transaction contemplated by the BP PSA has not been consummated by March 15, 2013, which we refer to as a Mandatory Redemption Event. The terms of both the 6 ¹/₂% Senior Notes and the 6 ⁷/₈% Senior Notes also provide that if, at any time, we determine that a Mandatory Redemption Event is reasonably likely to occur, then we may, at our option, redeem all and not less than all of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes then outstanding, at par plus accrued but unpaid interest. We may redeem all or part of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes on or after November 15, 2015 and February 15, 2018, respectively, at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to November 15, 2015 we may at our option, redeem up to 35% of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control triggering event, as defined in the indenture, we will be required to make an offer to repurchase the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

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The 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes are general unsecured senior obligations. They are jointly and severally guaranteed by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection with any sale or other disposition of all the capital stock of a subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of such subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as such subsidiary guarantor does not have outstanding any guarantee of any of our or any of our subsidiary guarantor’s indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. The 6 ¹/₂% Senior Notes and 6 ⁷/₈% 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 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes and; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility and the Plains Offshore senior 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, including indebtedness under the Plains Offshore senior credit facility, which we guarantee, and the shares of preferred stock issued by Plains Offshore.

In connection with the issuance of the 6 ¹/₂% Senior Notes and the 6 ⁷/₈% Senior Notes, the borrowing base under our Amended Credit Facility will be reduced to $5.175 billion, which will reduce the maximum amount available to borrow under the senior secured five-year revolving credit facility to $2.875 billion from $3.0 billion. Our borrowing base for the Plains Offshore senior credit facility will remain at $300 million. In addition, as a result of the issuance of the 6 ¹/₂% Senior Notes and the 6 ⁷/₈% Senior Notes, we will not enter into the Bridge Credit Facility.

We also obtained a consent from the majority of the lenders under our senior revolving credit facility in connection with the issuance of the 6 ¹/₂% Senior Notes and the 6 ⁷/₈% Senior Notes, which allows the redemption feature in connection with a Mandatory Redemption Event and allows us to include such pro forma adjustments as if the transactions contemplated under the BP PSA had been consummated when calculating the ratio of debt to EBITDAX. In addition, the lenders also agreed that there would be no reduction to the borrowing base of our existing senior revolving credit facility in connection with the Senior Notes offering.

Note 4 — 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, put options, 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 interest rate on our senior revolving credit facility and Plains Offshore’s senior credit facility is variable, while our senior notes are at fixed rates.

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.

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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. Cash settlements with respect to derivatives that contain a significant financing element are reflected as financing activities in the statement of cash flows.

For put options, we typically 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 and 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.

Under a swap contract, the counterparty is required to make a payment to us if the index price for any settlement period is less than the fixed price, and we are required to make a payment to the counterparty if the index price for any settlement period is greater than the fixed price. The amount we receive or pay is the difference between the index price and the fixed price multiplied by the contract volumes. If we have less production than the volumes specified under the swap transaction when the index price exceeds the fixed price, we must make payments against which there are no offsetting revenues from production.

During the three months ended September 30, 2012, we entered into the following Brent crude oil derivative contracts:

• Brent crude oil swap contracts on 40,000 BOPD for 2013 with an average price of $109.23 per barrel.

• Brent crude oil put option spread contracts on 5,000 BOPD for 2014 with a floor price of $100 per barrel, a limit of $80 per barrel and weighted average deferred premium and interest of $7.110 per barrel.

• Brent crude oil put option spread contracts on 30,000 BOPD for 2014 with a floor price of $95 per barrel, a limit of $75 per barrel and weighted average deferred premium and interest of $6.091 per barrel.

• Brent crude oil put option spread contracts on 25,000 BOPD for 2014 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $5.260 per barrel.

• Brent crude oil put option spread contracts on 25,000 BOPD for 2015 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $6.720 per barrel.

See Note 6 – Fair Value Measurements of Assets and Liabilities, for additional discussion on the fair value measurement of our derivative contracts.

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As of September 30, 2012, 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
2012
Oct - Dec	Three-way collars (2)	40,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$120.00 Ceiling
2013
Jan - Dec	Swap contracts(3)	40,000 Bbls	$109.23	-	Brent
Jan - Dec	Put options(4)	13,000 Bbls	$100.00 Floor with an $80.00 Limit	$6.800 per Bbl	Brent
Jan - Dec	Three-way collars (2)	25,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$124.29 Ceiling
Jan - Dec	Three-way collars (2)	5,000 Bbls	$90.00 Floor with a $70.00 Limit	-	Brent
			$126.08 Ceiling
Jan - Dec	Put options(4)	17,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.253 per Bbl	Brent
2014
Jan - Dec	Put options(4)	5,000 Bbls	$100.00 Floor with an $80.00 Limit	$7.110 per Bbl	Brent
Jan - Dec	Put options(4)	30,000 Bbls	$95.00 Floor with a $75.00 Limit	$6.091 per Bbl	Brent
Jan - Dec	Put options(4)	75,000 Bbls	$90.00 Floor with a $70.00 Limit	$5.739 per Bbl	Brent
2015
Jan - Dec	Put options(4)	25,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.720 per Bbl	Brent
Sales of Natural Gas Production
2012
Oct - Dec	Put options(5)	120,000 MMBtu	$4.30 Floor with a $3.00 Limit	$0.298 per MMBtu	Henry Hub
Oct - Dec	Three-way collars(6)	40,000 MMBtu	$4.30 Floor with a $3.00 Limit	-	Henry Hub
			$4.86 Ceiling
Oct - Dec	Swap contracts(3)	80,000 MMBtu	$2.72	-	Henry Hub
2013
Jan - Dec	Swap contracts(3)	110,000 MMBtu	$4.27	-	Henry Hub
2014
Jan - Dec	Swap contracts(3)	100,000 MMBtu	$4.09	-	Henry Hub

(1) The average strike prices do not reflect any premiums to purchase the put options.

(2) If the index price is less than the per barrel floor, we receive the difference between the per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and the per barrel ceiling if the index price is greater than the per barrel ceiling. If the index price is at or above the per barrel floor but at or below the per barrel ceiling, no cash settlement is required.

(3) If the index price is less than the fixed price, we receive the difference between the fixed price and the index price. We pay the difference between the index price and the fixed price if the index price is greater than the fixed price.

(4) If the index price is less than the per barrel floor, we receive the difference between the 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 the per barrel floor, we pay only the option premium.

(5) If the index price is less than the per MMBtu floor, we receive the difference between the 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 the per MMBtu floor, we pay only the option premium.

(6) If the index price is less than the per MMBtu floor, we receive the difference between the per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu. We pay the difference between the index price and the per MMBtu ceiling if the index price is greater than the per MMBtu ceiling. If the index price is at or above the per MMBtu floor but at or below the per MMBtu ceiling, no cash settlement is required.

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Balance Sheet

At September 30, 2012 and December 31, 2011, we had the following outstanding commodity derivative contracts recorded in our balance sheet (in thousands):

		Estimated Fair Value
Instrument Type	Balance Sheet Classification	September 30, 2012		December 31, 2011
Crude oil puts	Commodity derivative contracts - current assets	$	29,409	$	-
Crude oil collars	Commodity derivative contracts - current assets		4,653		10,623
Crude oil swaps	Commodity derivative contracts - current assets		15,439		-
Natural gas puts	Commodity derivative contracts - current assets		10,815		41,335
Natural gas collars	Commodity derivative contracts - current assets		3,598		13,163
Natural gas swaps	Commodity derivative contracts - current assets		10,263		-
Crude oil puts	Commodity derivative contracts - non-current assets		308,236		48,306
Crude oil collars	Commodity derivative contracts - non-current assets		2,549		-
Crude oil swaps	Commodity derivative contracts - non-current assets		15,851		-
Natural gas swaps	Commodity derivative contracts - non-current (liabilities) assets		(656)		12,951
Total derivative instruments		$	400,157	$	126,378

The following table provides supplemental information to reconcile the fair value of our derivative contracts to our balance sheet at September 30, 2012 and December 31, 2011, considering the deferred premiums, accrued interest and related settlement payable/receivable amounts which are not included in the fair value amounts disclosed in the table above (in thousands):

	September 30,     2012		December 31,      2011
Net fair value asset	$	400,157	$	126,378
Deferred premium and accrued interest on derivative contracts		(366,960)		(62,430)
Settlement payable		-		(5,106)
Settlement receivable		72		216
Net commodity derivative asset	$	33,269	$	59,058
Commodity derivative contracts - current asset	$	26,302	$	50,964
Commodity derivative contracts - non-current asset		19,459		12,678
Commodity derivative contracts - current liability		(8,253)		(3,761)
Commodity derivative contracts - non-current liability		(4,239)		(823)
	$	33,269	$	59,058

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 nine months ended September 30, 2012 and 2011, pre-tax amounts recognized in our income statements for derivative transactions were as follows (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
(Loss) gain on mark-to-market derivative contracts	$	(100,160	)	$	125,551	$	12,573	$	93,467

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Cash Payments and Receipts

During the nine months ended September 30, 2012 and 2011, cash (payments) receipts for derivatives were as follows (in thousands):

	Nine Months Ended September 30,
	2012		2011
Oil derivatives	$	(8,114)	$	(48,482)
Natural gas derivatives		45,499		1,034
	$	37,385	$	(47,448)

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 from the counterparties under the derivative contracts. The maximum amount of loss due to credit risk that we would have incurred if all the counterparties to our derivative contracts failed to perform according to the terms of the derivative contracts at September 30, 2012 was $46.1 million.

Contingent Features

As of September 30, 2012, the counterparties to our commodity derivative contracts consisted of ten financial institutions. Certain of our counterparties or their affiliates are 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 September 30, 2012, we were in a net liability position with four of the counterparties to our derivative instruments, totaling $12.5 million.

Subsequent Event

In October 2012, we entered into Brent crude oil put option spread contracts on 40,000 BOPD for 2015 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $7.019 per barrel.

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Note 5 — Investment

At September 30, 2012 and 2011, we owned 51.0 million shares of McMoRan Exploration Co. common stock, approximately 31.5% and 31.6%, respectively, of its 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. We may sell shares of McMoRan common stock pursuant to underwritten offerings, in periodic sales under the 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 September 30, 2012, the McMoRan shares were valued at approximately $519.4 million, based on McMoRan’s closing stock price of $11.75 on September 30, 2012, discounted to reflect certain limitations on the marketability of the McMoRan shares. During the three months ended September 30, 2012 and 2011, we recorded unrealized losses of $43.1 million and $395.5 million, respectively, on our investment. During the nine months ended September 30, 2012 and 2011, we recorded unrealized losses of $92.3 million and $284.9 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):

	Nine Months Ended
	September 30,
	2012(1)			2011
Results of Operations(2)
Revenues		$    92,206		$	136,984
Operating loss		(32,247	)		(13,215	)
Loss from continuing operations		(33,957	)		(15,797	)
Net loss applicable to common stock		(45,474	)		(27,545	)

(1) Amounts are based on McMoRan’s Form 8-K dated October 19, 2012.

(2) Amounts represent our 31.5% and 31.6% equity ownership in McMoRan as of September 30, 2012 and 2011, respectively.

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Note 6 — 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 September 30, 2012 and December 31, 2011 (in thousands):

			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)
September 30, 2012
Commodity derivative contracts(1)
Crude oil puts	$	337,645	$	-	$	262,959	$	74,686
Crude oil collars		7,201		-		(976)		8,177
Crude oil swaps		31,291		-		31,291		-
Natural gas puts		10,815		-		-		10,815
Natural gas collars		3,598		-		-		3,598
Natural gas swaps		9,607		-		9,607		-
Investment(2)		519,370		-		-		519,370
	$	919,527	$	-	$	302,881	$	616,646
December 31, 2011
Commodity derivative contracts(1)
Crude oil puts	$	48,306	$	-	$	-	$	48,306
Crude oil collars		10,623		-		(669)		11,292
Natural gas puts		41,335		-		-		41,335
Natural gas collars		13,163		-		-		13,163
Natural gas swaps		12,951		-		12,951		-
Investment(2)		611,671		-		-		611,671
	$	738,049	$	-	$	12,282	$	725,767

(1) Option premium and accrued interest of $367.0 million and $62.4 million at September 30, 2012 and December 31, 2011, respectively, settlement payable of $5.1 million at December 31, 2011 and settlement receivable of $0.1 million and $0.2 million at September 30, 2012 and December 31, 2011, 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.

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The fair value amounts of our put and collar derivative instruments are estimated using an option-pricing model, which uses various inputs including NYMEX and ICE price quotations, volatilities, interest rates and contract terms. The fair value of our swap derivative instruments are estimated using a pricing model which has various inputs including NYMEX and ICE price quotations, interest rates and contract terms. We adjust the valuations 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 and/or interpolate data between data points for thinly traded instruments.

As of September 30, 2012, our commodity derivative contracts are classified as follows:

• Our 2012, 2013 and 2014 natural gas swaps, certain of our 2012 crude oil collars, our 2013 crude oil swaps and puts and certain of our 2014 crude oil puts are classified as Level 2 instruments.

• Our 2012 natural gas puts and collars, certain of our 2012 crude oil collars, our 2013 crude oil collars, certain of our 2014 crude oil puts and our 2015 crude oil puts are classified as Level 3 instruments.

We determine the fair value of our investment by discounting 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, 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 September 30, 2012, 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.

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We adopted the guidance amending certain accounting and disclosure requirements related to fair value measurements on January 1, 2012. 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 provisions of this standard did not have an impact on our consolidated financial position, results of operations or cash flows.

The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts and our investment measured at fair value as of September 30, 2012 (in thousands):

	Quantitative Information About Level 3 Fair Value Measurements
	Fair Value		Valuation Technique		Unobservable Input	Range (Weighted Average)
September 30, 2012
Commodity derivative contracts(1)
Crude oil puts	$	74,686		Option pricing model	Implied volatility		23% - 33% (26%)
Crude oil collars		8,177		Option pricing model	Implied volatility		22% - 65% (33%)
Natural gas puts		10,815		Option pricing model	Implied volatility		37% - 42% (39%)
Natural gas collars		3,598		Option pricing model	Implied volatility		37% - 42% (39%)
Investment(2)		519,370		Option pricing model	Discount for lack of marketability		10% - 16% (13%)

(1) Represents the range of implied volatility associated with the forward commodity prices used in the valuation of our derivative contracts. We have determined that a market participant would use a similar volatility curve when pricing similar commodity derivative contracts.

(2) Represents the range of discount for lack of marketability associated with our investment in the common stock of McMoRan. The discount for lack of marketability is derived by an analysis of publicly traded option contracts of McMoRan common stock as of the valuation date. We have determined that a market participant would use a similar valuation methodology when pricing an investment with similar terms.

The significant unobservable inputs used in the fair value measurement of our commodity derivative contracts are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement.

Implied volatility associated with the common stock of McMoRan is a significant unobservable input used in the determination of the discount for lack of marketability of our investment measured at fair value. Significant increases (decreases) in volatility in isolation would result in a significantly higher (lower) discount factor for lack of marketability. Additionally, another significant unobservable input, the expected term of our investment, impacts the discount factor for lack of marketability. Significant increases (decreases) in the expected term in isolation would result in a significantly higher (lower) discount factor for lack of marketability. A higher discount factor would result in a lower fair value measurement of our investment.

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The following table presents a reconciliation of changes in fair value of our financial assets and liabilities classified as Level 3 for the nine months ended September 30, 2012 and 2011 (in thousands):

	Nine Months Ended September 30,
	2012				2011
	Commodity Derivatives (1)		Investment		Commodity Derivatives (1)		Investment
Fair value at beginning of period	$	114,096	$	611,671	$	4,785	$	664,346
Transfers into Level 3(2)		149		-		-		-
Transfers out of Level 3(3)		(52,540)		-		6,962		-
Realized and unrealized gains and losses included in earnings(4)		18,068		(92,301)		65,266		(284,929)
Purchases		72,949		-		47,948		-
Settlements		(55,446)		-		(310)		-
Fair value at end of period	$	97,276	$	519,370	$	124,651	$	379,417
Change in unrealized gains and losses relating to assets and liabilities held as of         the end of the period(4)	$	12,674	$	(92,301)	$	63,706	$	(284,929)

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

(2) During the nine months ended September 30, 2012, the inputs used to value certain of our 2012 crude oil collars were significantly unobservable and those contracts were transferred from Level 2 to Level 3.

(3) During the nine months ended September 30, 2012, the inputs used to value certain of our 2012 crude oil collars and certain of our 2013 crude oil puts were directly or indirectly observable and those contracts were transferred from Level 3 to Level 2. During the nine months ended September 30, 2011, the inputs used to value certain of our 2011 natural gas collars were directly or indirectly observable and those contracts were transferred from Level 3 to Level 2.

(4) 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 (loss) on investment measured at fair value in our income statement for our commodity derivative contracts and our investment, respectively.

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 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.

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The following table presents the carrying amounts and fair values of our other financial instruments as of September 30, 2012 and December 31, 2011 (in thousands):

	September 30, 2012				December 31, 2011
	Carrying   Amount		Fair Value		Carrying   Amount		Fair Value
Current Asset(1)
Cash and cash equivalents	$	217,018	$	217,018	$	419,098	$	419,098
Non-Current Asset(2)
Deposit related to the Gulf of Mexico Acquisition		555,000		555,000		-		-
Current Liability(3)
Deferred premium and accrued interest on derivative contracts		56,200		56,200		13,029		13,029
Non-Current Liability(3)
Deferred premium and accrued interest on derivative contracts		310,760		310,760		49,401		49,401
Long-Term Debt(4)
Senior revolving credit facility		895,000		895,000		735,000		735,000
Plains Offshore senior credit facility		-		-		-		-
7 3/4% Senior Notes		-		-		79,281		81,858
10% Senior Notes		176,798		190,058		175,385		194,239
7% Senior Notes		-		-		76,901		79,593
7 5/8% Senior Notes		400,000		426,000		400,000		424,000
6 1/8% Senior Notes		750,000		755,625		-		-
8 5/8% Senior Notes		394,773		440,172		394,385		433,331
7 5/8% Senior Notes		300,000		320,250		300,000		324,750
6 5/8% Senior Notes		600,000		609,000		600,000		630,000
6 3/4% Senior Notes		1,000,000		1,015,000		1,000,000		1,047,500

(1) Our cash and cash equivalents consist primarily of money market mutual funds and would have been classified as Level 1 under the fair value hierarchy.

(2) Our deposit related to the Gulf of Mexico Acquisition is a performance deposit to BP in connection with the Gulf of Mexico Acquisition and would have been classified as Level 1 under the fair value hierarchy.

(3) If our deferred premium and accrued interest payable on our commodity derivative contracts had been measured at fair value, it would have been classified as Level 3 under the fair value hierarchy.

(4) The carrying value of our senior revolving credit facility approximates its fair value, as interest rates are variable, based on prevailing market rates. Our senior revolving credit facility would have been classified as Level 1 under the fair value hierarchy. If our senior notes had been measured at fair value, we would have classified them as Level 1 under the fair value hierarchy as the inputs utilized for the measurement would be quoted, unadjusted prices from over-the-counter markets for debt instruments.

Note 7 — Divestment

During the first quarter of 2012, we completed the divestment of our interests in approximately 2,000 gross leasehold acres in our Texas Panhandle properties. After the exercise of third party preferential rights and closing adjustments, we received approximately $43.4 million in cash. The transactions were effective November 1, 2011. The proceeds were recorded as a reduction to capitalized costs pursuant to full cost accounting rules.

At September 30, 2012, we continue to have interests in approximately 40,000 gross leasehold acres in the Texas Panhandle. We expect to receive additional proceeds from future closings, as may be further modified for additional post-closing adjustments.

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Note 8 — Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate plus any significant unusual or infrequently occurring items which are recorded in the period that the specific item occurs. For the three months ended September 30, 2012, our income tax benefit was approximately 38% of the pre-tax loss. For the nine months ended September 30, 2012, our income tax expense was approximately 42% of the pre-tax income.

The variance in our estimated annual effective tax rate from the 35% federal statutory rate for both periods include 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 9 — Commitments, Contingencies and Industry Concentration

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, $86.4 million ($145.2 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 $84.3 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At September 30, 2012, the escrow account had a balance of $20.9 million. The fair value of our guarantee at September 30, 2012, $0.3 million, considers the payment/performance risk of the purchaser and is included in other long-term liabilities in our balance sheet.

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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.

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.

Industry Concentration

Effective May 1, 2012, Phillips 66 was spun off from ConocoPhillips at which time we consented to the assignment of our Crude Oil Purchase Agreement from ConocoPhillips to Phillips 66. During 2011, sales to ConocoPhillips accounted for 41% of our total revenues.

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Note 10 — Consolidating Financial Statements

We are the issuer of $565 million 10% Senior Notes, of which $184.9 million aggregate principal amount remains outstanding, $400 million 7 ⁵/₈% Senior Notes due 2018, $750 million 6 ¹/₈% Senior Notes, $400 million 8 ⁵/₈% Senior Notes, $300 million 7 ⁵/₈% Senior Notes due 2020, $600 million 6 ⁵/₈% Senior Notes and $1 billion 6 ³/₄% Senior Notes as of September 30, 2012, which are jointly and severally guaranteed by certain of our existing domestic subsidiaries (referred to as “Guarantor Subsidiaries”). In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection with any sale or other disposition of all the capital stock of a subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of such subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as such subsidiary guarantor does not have outstanding any guarantee of any of our or any of our subsidiary guarantor’s indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. Certain of our subsidiaries do not guarantee the Senior Notes (referred to as “Non-Guarantor Subsidiaries”).

Plains Offshore.    In October 2011, we entered into a securities purchase agreement with EIG Global Energy Partners for a 20% equity interest in Plains Offshore. As a result, the associated properties were transferred from PXP, which is reported as Issuer, to Plains Offshore, which is reported as a Non-Guarantor Subsidiary. We have retrospectively adjusted the Issuer, Non-Guarantor Subsidiaries and Intercompany Eliminations columns of the consolidating statements of income for the three and nine months ended September 30, 2011 and cash flows for the nine months ended September 30, 2011 to reflect the transfer of these deepwater assets.

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

• PXP (the “Issuer”);

• the Guarantor Subsidiaries on a combined basis;

• the Non-Guarantor Subsidiaries on a combined basis;

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

• PXP on a consolidated basis.

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited)

SEPTEMBER 30, 2012

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	4,307	$	-	$	212,711	$	-	$	217,018
Accounts receivable and other current assets		975,523		81,063		14,003		-		1,070,589
		979,830		81,063		226,714		-		1,287,607
Property and Equipment, at cost
Oil and natural gas properties - full cost method		5,518,291		8,899,882		1,384,663		-		15,802,836
Other property and equipment		54,391		42,160		53,480		-		150,031
		5,572,682		8,942,042		1,438,143		-		15,952,867
Less allowance for depreciation, depletion, amortization and impairment		(2,598,955)		(7,689,562)		(999,711)		3,815,088		(7,473,140)
		2,973,727		1,252,480		438,432		3,815,088		8,479,727
Investment in and Advances to Affiliates		4,329,124		(1,334,902)		(78,790)		(2,915,432)		-
Other Assets		651,092		552,063		4,306		-		1,207,461
	$	8,933,773	$	550,704	$	590,662	$	899,656	$	10,974,795
LIABILITIES AND EQUITY
Current Liabilities	$	678,653	$	50,452	$	49,439	$	-	$	778,544
Long-Term Debt		4,516,571		-		-		-		4,516,571
Other Long-Term Liabilities		228,269		34,655		838		-		263,762
Deferred Income Taxes		223,387		21,114		28,977		1,417,995		1,691,473
Equity
Stockholders’ equity		3,286,893		444,483		73,856		(518,339)		3,286,893
Noncontrolling interest Preferred stock of subsidiary		-		-		437,552		-		437,552
		3,286,893		444,483		511,408		(518,339)		3,724,445
	$	8,933,773	$	550,704	$	590,662	$	899,656	$	10,974,795

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2011

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	3,189	$	6	$	415,903	$	-	$	419,098
Accounts receivable and other current assets		885,860		136,642		444		(667)		1,022,279
		889,049		136,648		416,347		(667)		1,441,377
Property and Equipment, at cost
Oil and natural gas properties - full cost method		4,301,524		8,841,469		1,282,708		-		14,425,701
Other property and equipment		52,906		42,747		50,306		-		145,959
		4,354,430		8,884,216		1,333,014		-		14,571,660
Less allowance for depreciation, depletion, amortization and impairment		(2,327,063)		(6,392,068)		(1,059,186)		2,931,952		(6,846,365)
		2,027,367		2,492,148		273,828		2,931,952		7,725,295
Investment in and Advances to Affiliates		4,583,550		(1,282,085)		(73,079)		(3,228,386)		-
Other Assets		73,832		548,615		2,353		-		624,800
	$	7,573,798	$	1,895,326	$	619,449	$	(297,101)	$	9,791,472
LIABILITIES AND EQUITY
Current Liabilities	$	443,098	$	135,681	$	48,074	$	(667)	$	626,186
Long-Term Debt		3,760,952		-		-		-		3,760,952
Other Long-Term Liabilities		211,106		35,296		803		-		247,205
Deferred Income Taxes		(105,994)		437,367		31,757		1,098,767		1,461,897
Equity
Stockholders’ equity		3,264,636		1,286,982		108,219		(1,395,201)		3,264,636
Noncontrolling interest Preferred stock of subsidiary		-		-		430,596		-		430,596
		3,264,636		1,286,982		538,815		(1,395,201)		3,695,232
	$	7,573,798	$	1,895,326	$	619,449	$	(297,101)	$	9,791,472

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED SEPTEMBER 30, 2012

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	512,146	$	28,288	$	-	$	-	$	540,434
Gas sales		9,227		53,403		-		-		62,630
Other operating revenues		480		1,560		-		-		2,040
		521,853		83,251		-		-		605,104
Costs and Expenses
Production costs		117,755		42,172		470		-		160,397
General and administrative		28,986		8,338		1,874		-		39,198
Depreciation, depletion, amortization and accretion		112,078		29,368		132		132,769		274,347
Impairment of oil and gas properties		-		108,093		-		(108,093)		-
Other operating income		(605)		-		-		-		(605)
		258,214		187,971		2,476		24,676		473,337
Income (Loss) from Operations		263,639		(104,720)		(2,476)		(24,676)		131,767
Other (Expense) Income
Equity in earnings of subsidiaries		(123,091)		-		-		123,091		-
Interest expense		(4,853)		(52,899)		(1,422)		-		(59,174)
Loss on mark-to-market derivative contracts		(100,160)		-		-		-		(100,160)
Loss on investment measured at fair value		(43,121)		-		-		-		(43,121)
Other (expense) income		(53)		65		(1)		-		11
Loss Before Income Taxes		(7,639)		(157,554)		(3,899)		98,415		(70,677)
Income tax (expense) benefit		(45,449)		59,251		1,361		11,540		26,703
Net Loss		(53,088)		(98,303)		(2,538)		109,955		(43,974)
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		-		-		(9,114)		-		(9,114)
Net Loss Attributable to Common Stockholders	$	(53,088)	$	(98,303)	$	(11,652)	$	109,955	$	(53,088)

29

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED SEPTEMBER 30, 2011

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	311,706	$	67,373	$	-	$	-	$	379,079
Gas sales		4,254		116,760		-		-		121,014
Other operating revenues		266		1,489		-		-		1,755
		316,226		185,622		-		-		501,848
Costs and Expenses
Production costs		82,556		50,431		-		-		132,987
General and administrative		16,744		11,138		276		-		28,158
Depreciation, depletion, amortization and accretion		51,646		72,050		122		48,383		172,201
Impairment of oil and gas properties		-		1,091		12,674		(13,765)		-
Other operating expense (income)		184		(234)		-		-		(50)
		151,130		134,476		13,072		34,618		333,296
Income (Loss) from Operations		165,096		51,146		(13,072)		(34,618)		168,552
Other (Expense) Income
Equity in earnings of subsidiaries		(25,114)		4		-		25,110		-
Interest expense		(320)		(42,312)		(863)		-		(43,495)
Gain on mark-to-market derivative contracts		125,551		-		-		-		125,551
Loss on investment measured at fair value		(395,490)		-		-		-		(395,490)
Other income		358		1,003		38		-		1,399
(Loss) Income Before Income Taxes		(129,919)		9,841		(13,897)		(9,508)		(143,483)
Income tax benefit		41,623		919		4,885		7,760		55,187
Net (Loss) Income	$	(88,296)	$	10,760	$	(9,012)	$	(1,748)	$	(88,296)

30

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2012

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	1,440,103	$	87,327	$	-	$	-	$	1,527,430
Gas sales		21,581		140,532		-		-		162,113
Other operating revenues		1,170		5,390		-		-		6,560
		1,462,854		233,249		-		-		1,696,103
Costs and Expenses
Production costs		326,538		113,627		903		-		441,068
General and administrative		78,088		25,401		5,792		-		109,281
Depreciation, depletion, amortization and accretion		294,027		109,119		400		306,731		710,277
Impairment of oil and gas properties		-		1,189,867		-		(1,189,867)		-
Other operating expense (income)		396		(3,538)		-		-		(3,142)
		699,049		1,434,476		7,095		(883,136)		1,257,484
Income (Loss) from Operations		763,805		(1,201,227)		(7,095)		883,136		438,619
Other (Expense) Income
Equity in earnings of subsidiaries		(324,191)		-		-		324,191		-
Interest expense		(4,886)		(148,517)		(4,001)		-		(157,404)
Debt extinguishment costs		(5,167)		-		-		-		(5,167)
Gain on mark-to-market derivative contracts		12,573		-		-		-		12,573
Loss on investment measured at fair value		(92,301)		-		-		-		(92,301)
Other income		54		361		25		-		440
Income (Loss) Before Income Taxes		349,887		(1,349,383)		(11,071)		1,207,327		196,760
Income tax (expense) benefit		(262,095)		506,884		3,915		(330,466)		(81,762)
Net Income (Loss)		87,792		(842,499)		(7,156)		876,861		114,998
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		-		-		(27,206)		-		(27,206)
Net Income (Loss) Attributable to Common Stockholders	$	87,792	$	(842,499)	$	(34,362)	$	876,861	$	87,792

31

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2011

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
Revenues
Oil sales	$	916,601	$	192,705	$	922	$	-	$	1,110,228
Gas sales		10,244		321,242		-		-		331,486
Other operating revenues		771		4,462		-		-		5,233
		927,616		518,409		922		-		1,446,947
Costs and Expenses
Production costs		251,292		146,841		-		-		398,133
General and administrative		58,121		35,928		915		-		94,964
Depreciation, depletion, amortization and accretion		141,277		197,279		268		127,248		466,072
Impairment of oil and gas properties		-		314,258		488,664		(802,922)		-
Other operating expense (income)		184		(841)		-		-		(657)
		450,874		693,465		489,847		(675,674)		958,512
Income (Loss) from Operations		476,742		(175,056)		(488,925)		675,674		488,435
Other (Expense) Income
Equity in earnings of subsidiaries		(65,404)		-		-		65,404		-
Interest expense		(1,277)		(109,541)		(2,323)		-		(113,141)
Gain on mark-to-market derivative contracts		93,467		-		-		-		93,467
Loss on investment measured at fair value		(284,929)		-		-		-		(284,929)
Other income (expense)		1,053		1,959		(63)		-		2,949
Income (Loss) Before Income Taxes		219,652		(282,638)		(491,311)		741,078		186,781
Income tax (expense) benefit		(112,077)		109,353		172,025		(248,507)		(79,206)
Net Income (Loss)	$	107,575	$	(173,285)	$	(319,286)	$	492,571	$	107,575

32

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2012

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	87,792		$	(842,499	)	$	(7,156	)	$	876,861		$	114,998
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		294,027			1,298,986			400			(883,136	)		710,277
Equity in earnings of subsidiaries		324,191			-			-			(324,191	)		-
Deferred income tax expense (benefit)		184,108			(416,259	)		(2,780	)		319,228			84,297
Debt extinguishment costs		939			-			-			-			939
Gain on mark-to-market derivative contracts		(12,573	)		-			-			-			(12,573	)
Loss on investment measured at fair value		92,301			-			-			-			92,301
Non-cash compensation		31,292			6,606			-			-			37,898
Other non-cash items		9,895			536			-			-			10,431
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(60,150	)		52,477			(6,209	)		-			(13,882	)
Accounts payable and other liabilities		41,965			(18,518	)		(6,434	)		-			17,013
Income taxes receivable/payable		4,878			-			-			-			4,878
Net cash provided by (used in) operating activities		998,665			81,329			(22,179	)		(11,238	)		1,046,577
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(1,053,219	)		(184,618	)		(150,519	)		-			(1,388,356	)
Acquisition of oil and gas properties		(13,597	)		-			(12,780	)		-			(26,377	)
Deposit related to the Gulf of Mexico Acquisition		(555,000	)		-			-			-			(555,000	)
Proceeds from sales of oil and gas properties, net of costs and expenses		60,470			-			-			-			60,470
Derivative settlements		37,385			-			-			-			37,385
Additions to other property and equipment		(6,095	)		(1	)		(3,175	)		-			(9,271	)
Net cash used in investing activities		(1,530,056	)		(184,619	)		(166,474	)		-			(1,881,149	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		6,756,425			-			-			-			6,756,425
Repayments of revolving credit facilities		(6,596,425	)		-			-			-			(6,596,425	)
Principal payments of long-term debt		(156,182	)		-			-			-			(156,182	)
Proceeds from issuance of Senior Notes		750,000			-			-			-			750,000
Costs incurred in connection with financing arrangements		(12,586	)		-			-			-			(12,586	)
Purchase of treasury stock		(88,490	)		-			-			-			(88,490	)
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		-			-			(20,250	)		-			(20,250	)
Investment in and advances to affiliates		(120,233	)		103,284			5,711			11,238			-
Net cash provided by (used in) financing activities		532,509			103,284			(14,539	)		11,238			632,492
Net increase (decrease) in cash and cash equivalents		1,118			(6	)		(203,192	)		-			(202,080	)
Cash and cash equivalents, beginning of period		3,189			6			415,903			-			419,098
Cash and cash equivalents, end of period	$	4,307		$	-		$	212,711		$	-		$	217,018

33

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2011

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	107,575		$	(173,285	)	$	(319,286	)	$	492,571		$	107,575
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		141,277			511,537			488,932			(675,674	)		466,072
Equity in earnings of subsidiaries		65,404			-			-			(65,404	)		-
Deferred income tax (benefit) expense		(124,396	)		(29,488	)		(136,648	)		395,697			105,165
Gain on mark-to-market derivative contracts		(93,467	)		-			-			-			(93,467	)
Loss on investment measured at fair value		284,929			-			-			-			284,929
Non-cash compensation		19,838			7,419			-			-			27,257
Other non-cash items		499			(6,898	)		67			-			(6,332	)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		15,180			(37,748	)		1,213			-			(21,355	)
Accounts payable and other liabilities		23,287			8,543			145			-			31,975
Income taxes receivable/payable		20,831			-			-			-			20,831
Net cash provided by operating activities		460,957			280,080			34,423			147,190			922,650
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(544,142	)		(638,869	)		(78,185	)		-			(1,261,196	)
Acquisition of oil and gas properties		(10,475	)		(26,275	)		-			-			(36,750	)
Proceeds from sales of oil and gas properties, net of costs and expenses		11,987			-			-			-			11,987
Derivative settlements		(47,448	)		-			-			-			(47,448	)
Other		(5,583	)		509			(2,828	)		-			(7,902	)
Net cash used in investing activities		(595,661	)		(664,635	)		(81,013	)		-			(1,341,309	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		4,026,900			-			-			-			4,026,900
Repayments of revolving credit facilities		(4,191,900	)		-			-			-			(4,191,900	)
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		(284,041	)		384,553			46,678			(147,190	)		-
Other		9			-			-			-			9
Net cash provided by financing activities		139,648			384,553			46,678			(147,190	)		423,689
Net increase (decrease) in cash and cash equivalents		4,944			(2	)		88			-			5,030
Cash and cash equivalents, beginning of period		6,020			8			406			-			6,434
Cash and cash equivalents, end of period	$	10,964		$	6		$	494		$	-		$	11,464

34

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, 2011.

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 Gulf of Mexico; 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 risk management 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, Eagle Ford Shale, Haynesville Shale and Gulf of Mexico 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 31.5% of its 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 and ICE 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.

35

Recent Developments

Proposed Gulf of Mexico Acquisition

On September 10, 2012, we announced that we had entered into the BP PSA to acquire from BP their interests in certain deepwater Gulf of Mexico oil and gas properties for $5.55 billion in cash, subject to customary purchase price adjustments. These properties include certain oil and gas interests in and near the Holstein, Diana, Hoover, Horn Mountain, Marlin, Dorado, King and Ram Powell fields. Certain of these properties are subject to preferential rights. The BP PSA contains customary representations and warranties, covenants, indemnification provisions and conditions to close. Under the terms of the BP PSA, we made a performance deposit of $555 million to BP, which BP will be permitted to retain as liquidated damages if it terminates the BP PSA under certain circumstances.

On September 10, 2012, we also announced that we had entered into the Shell PSA, to acquire from Shell its 50% working interest in the Holstein field for $560 million in cash, subject to customary purchase price adjustments. The Shell PSA contains customary representations and warranties, covenants, indemnification provisions and conditions to close.

We have received commitments from several financial institutions to provide financing in connection with these transactions. See Commitment Letter.

The Gulf of Mexico Acquisition is expected to close on November 30, 2012, and will be effective as of October 1, 2012. We will account for these transactions as acquisitions of businesses under purchase accounting rules.

Commitment Letter

In September 2012, we entered into the Commitment Letter to underwrite a new credit facility that will amend and restate our existing senior revolving credit facility and provide for term loan credit facilities, increase our borrowing base and provide financing and additional liquidity in connection with the Gulf of Mexico Acquisition. The Commitment Letter is subject to certain conditions, including the absence of a material adverse effect under the BP PSA, the execution of satisfactory definitive documentation and other customary closing conditions. Upon satisfaction of these conditions, the aggregate commitments of the lenders under the Amended Credit Facility will be $5.0 billion with an initial borrowing base of $5.3 billion, which includes $300 million related to the Plains Offshore Senior Credit Facility. The Amended Credit Facility will be comprised of a $3.0 billion senior secured five-year revolving credit facility, a $750.0 million senior secured five-year term loan, and a $1.25 billion senior secured seven-year term loan. Under the terms of the Commitment Letter, the lenders may also provide senior unsecured loans in an aggregate principal amount of up to $2.0 billion pursuant to the Bridge Credit Facility. Subsequently in September 2012, we successfully syndicated the Amended Credit Facility and Bridge Credit Facility to a group of banks and institutional lenders.

36

In connection with the closing of the Gulf of Mexico Acquisition, we expect to enter into our Amended Credit Facility on November 30, 2012. We will use the proceeds provided by the facilities to refinance certain existing indebtedness, to pay the cash consideration for the Gulf of Mexico Acquisition, to pay fees and expenses incurred in connection with the Gulf of Mexico Acquisition and related financing transactions and for general corporate purposes.

6  ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes

In October 2012, we issued (i) $1.5 billion of 6 ¹/₂% Senior Notes and (ii) $1.5 billion of 6 ⁷/₈% Senior Notes, both at par. We received approximately $2.95 billion of net proceeds, after deducting the underwriting discount and offering expenses. We will use the net proceeds to pay a portion of the cash consideration for the Gulf of Mexico Acquisition. Pending the closing of the Gulf of Mexico Acquisition, we intend to use a portion of the net proceeds to repay borrowings outstanding under our senior revolving credit facility. We may redeem all or part of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes on or after November 15, 2015 and February 15, 2018, respectively, at specified redemption prices and prior to such date at a “make-whole” redemption price.

In connection with the issuance of the 6 ¹/₂% Senior Notes and the 6 ⁷/₈% Senior Notes, the borrowing base under our Amended Credit Facility will be reduced to $5.175 billion, which will reduce the maximum amount available to borrow under the senior secured five-year revolving credit facility to $2.875 billion from $3.0 billion. Our borrowing base for the Plains Offshore senior credit facility will remain at $300 million. In addition, as a result of the issuance of the 6 ¹/₂% Senior Notes and the 6 ⁷/₈% Senior Notes, we will not enter into the Bridge Credit Facility.

We also obtained a consent from the majority of the lenders under our senior revolving credit facility in connection with the issuance of the 6 ¹/₂% Senior Notes and the 6 ⁷/₈% Senior Notes, which allows the redemption feature in connection with a Mandatory Redemption Event and allows us to include such pro forma adjustments as if the transactions contemplated under the BP PSA had been consummated when calculating the ratio of debt to EBITDAX. In addition, the lenders also agreed that there would be no reduction to the borrowing base of our existing senior revolving credit facility in connection with the Senior Notes offering.

Derivatives

During the third quarter of 2012, we entered into the following Brent crude oil derivative contracts:

• Brent crude oil swap contracts on 40,000 BOPD for 2013 with an average price of $109.23 per barrel.

• Brent crude oil put option spread contracts on 5,000 BOPD for 2014 with a floor price of $100 per barrel, a limit of $80 per barrel and weighted average deferred premium and interest of $7.110 per barrel.

• Brent crude oil put option spread contracts on 30,000 BOPD for 2014 with a floor price of $95 per barrel, a limit of $75 per barrel and weighted average deferred premium and interest of $6.091 per barrel.

• Brent crude oil put option spread contracts on 25,000 BOPD for 2014 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $5.260 per barrel.

• Brent crude oil put option spread contracts on 25,000 BOPD for 2015 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $6.720 per barrel.

In October 2012, we entered into Brent crude oil put option spread contracts on 40,000 BOPD for 2015 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $7.019 per barrel.

37

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 September 30, 2012, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 23%.

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. 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.

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 nine months ended September 30, 2012, we reported net income attributable to common stockholders of $87.8 million, or $0.67 per diluted share, compared to net income of $107.6 million, or $0.75 per diluted share, for the nine months ended September 30, 2011. The decrease primarily reflects increased DD&A, lower gas revenues and a smaller gain on our mark-to-market derivative contracts offset by higher oil revenues and a smaller loss on our investment in McMoRan measured at fair value. Significant transactions that affect comparisons between the periods include the divestment of our Panhandle and South Texas properties in the fourth quarter of 2011.

38

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				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Sales Volumes
Oil and liquids sales (MBbls)		5,846		4,682		15,805		13,064
Gas (MMcf)
Production		23,494		30,108		66,186		81,743
Used as fuel		309		549		1,083		1,604
Sales		23,185		29,559		65,103		80,139
MBOE
Production		9,762		9,700		26,836		26,688
Sales		9,711		9,608		26,656		26,420
Daily Average Volumes
Oil and liquids sales (Bbls)		63,548		50,891		57,683		47,853
Gas (Mcf)
Production		255,363		327,248		241,553		299,423
Used as fuel		3,353		5,962		3,952		5,875
Sales		252,010		321,286		237,601		293,548
BOE
Production		106,109		105,432		97,942		97,756
Sales		105,550		104,438		97,283		96,777
Unit Economics (in dollars)
Average Index Prices
ICE Brent Price per Bbl	$	109.37	$	112.01	$	112.16	$	111.47
NYMEX Price per Bbl		92.20		89.54		96.16		95.47
NYMEX Price per Mcf		2.82		4.20		2.59		4.20
Average Realized Sales Price
Before Derivative Transactions
Oil (per Bbl)	$	92.44	$	80.96	$	96.64	$	84.98
Gas (per Mcf)		2.70		4.10		2.49		4.14
Per BOE		62.10		52.05		63.38		54.57
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	10.10	$	8.32	$	10.08	$	8.87
Steam gas costs		1.25		1.77		1.24		1.88
Electricity		1.02		1.05		1.20		1.14
Production and ad valorem taxes		2.17		1.11		1.98		1.48
Gathering and transportation		1.98		1.59		2.05		1.70
DD&A (oil and gas properties)		27.21		16.86		25.54		16.49

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Oil derivatives	$	4,934	$	(17,823)	$	(8,114)	$	(48,482)
Natural gas derivatives		14,590		414		45,499		1,034
	$	19,524	$	(17,409)	$	37,385	$	(47,448)

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Comparison of Three Months Ended September 30, 2012 to Three Months Ended September 30, 2011

Oil and gas revenues.     Oil and gas revenues increased $103.0 million, to $603.1 million for 2012 from $500.1 million for 2011, primarily due to higher oil sales volumes and average realized oil prices partially offset by lower average realized gas prices and gas sales volumes.

Oil revenues increased $161.3 million, to $540.4 million for 2012 from $379.1 million for 2011, reflecting greater sales volumes ($107.6 million) and average realized prices ($53.7 million). Oil sales volumes increased 12.6 MBbls per day to 63.5 MBbls per day in 2012 from 50.9 MBbls per day in 2011, primarily reflecting increased production from our Eagle Ford Shale properties, partially offset by a production decrease due to the divestment of our Panhandle properties in December 2011. Excluding the impact of our divestments, sales increased 19.4 MBbls per day in 2012. Our average realized price for oil increased $11.48 per Bbl to $92.44 per Bbl for 2012 from $80.96 per Bbl for 2011. The increase was primarily attributable to our new marketing contract effective January 1, 2012 for our California crude oil production that replaces the percent of NYMEX index pricing with a market based pricing approach. The average ICE Brent index price for 2012 was $109.37 per Bbl compared to the average NYMEX index price of $89.54 per Bbl for 2011.

Gas revenues decreased $58.4 million, to $62.6 million in 2012 from $121.0 million in 2011, primarily reflecting lower average realized prices ($41.2 million) and sales volumes ($17.2 million). Our average realized price for gas was $2.70 per Mcf in 2012 compared to $4.10 per Mcf in 2011. Gas sales volumes decreased 69.3 MMcf per day to 252.0 MMcf per day in 2012 from 321.3 MMcf per day in 2011, primarily reflecting our Panhandle and South Texas properties divested in December 2011, partially offset by increased production from our Eagle Ford Shale properties. Excluding the impact of our divestments, sales increased 9.5 MMcf per day in 2012.

Lease operating expenses.     Lease operating expenses increased $18.1 million, to $98.1 million in 2012 from $80.0 million in 2011, reflecting increased production primarily at our Eagle Ford Shale properties, greater stock-based compensation expense resulting from an increase in the price of our common stock, increased diesel fuel cost at our Point Arguello platforms and increased well workover expense primarily at our Inglewood property, partially offset by our Panhandle and South Texas properties divested in December 2011.

Steam gas costs.     Steam gas costs decreased $4.9 million, to $12.1 million in 2012 from $17.0 million in 2011, primarily reflecting lower cost of gas used in steam generation. In 2012, we burned approximately 4.2 Bcf of natural gas at a cost of approximately $2.88 per MMBtu compared to 4.1 Bcf at a cost of approximately $4.18 per MMBtu in 2011.

Production and ad valorem taxes.    Production and ad valorem taxes increased $10.5 million, to $21.1 million in 2012 from $10.6 million in 2011, primarily reflecting increased production taxes due to increased production from our Eagle Ford Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Gathering and transportation expense.     Gathering and transportation expenses increased $4.0 million, to $19.2 million in 2012 from $15.2 million in 2011, primarily reflecting an increase in production from our Eagle Ford Shale properties and increased rates at our Haynesville Shale properties, partially offset by our Panhandle properties divested in December 2011.

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General and administrative expense.    G&A expense increased $11.0 million, to $39.2 million in 2012 from $28.2 million in 2011, primarily due to costs associated with the Gulf of Mexico Acquisition and greater stock-based compensation expense resulting from an increase in the price of our common stock.

Depreciation, depletion and amortization.     DD&A expense increased $102.7 million, to $270.6 million in 2012 from $167.9 million in 2011. The increase is attributable to our oil and gas depletion, primarily due to an increased per unit rate ($100.3 million). Our oil and gas unit of production rate increased to $27.21 per BOE in 2012 compared to $16.86 per BOE in 2011.

The increased DD&A rate is primarily due to the prolonged decrease in natural gas prices as some of our proved undeveloped reserves are no longer expected to be developed in the next five years. Additionally, the increase is due to impairment and transfer of certain unproved properties to cost subject to amortization.

Interest expense.     Interest expense increased $15.7 million, to $59.2 million in 2012 from $43.5 million in 2011, primarily due to a decrease in interest capitalized and greater average debt outstanding 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 $10.7 million and $27.9 million of interest in 2012 and 2011, respectively. The decreased capitalized interest is primarily attributable to a lower unevaluated oil and gas property balance in 2012.

(Loss) gain on mark-to-market derivative contracts.     The derivative instruments we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts 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 a $100.2 million loss related to mark-to-market derivative contracts in the third quarter of 2012, which was primarily associated with a decrease in the fair value of our crude oil and natural gas derivative contracts due to increased forward prices. In the third quarter of 2011, we recognized a $125.6 million gain related to mark-to-market derivative contracts.

Loss on investment measured at fair value.     At September 30, 2012, 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 loss on investment measured at fair value in our income statement.

We recognized a $43.1 million loss in the third quarter of 2012 related to our McMoRan investment, which was primarily associated with a decrease in McMoRan’s stock price. In the third quarter of 2011, we recognized a $395.5 million loss related to our McMoRan investment.

Income taxes.     For the three months ended September 30, 2012 and 2011, our income tax benefit was approximately 38% of pre-tax loss. The variance between these effective tax rates and the 35% federal statutory rate 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. In addition, specific items affecting our income tax benefit for the three months ended September 30, 2011 included a reduction to our balance of unrecognized tax benefits as a result of the expiration of the statute of limitations for a portion of our uncertain tax positions.

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Comparison of Nine Months Ended September 30, 2012 to Nine Months Ended September 30, 2011

Oil and gas revenues.    Oil and gas revenues increased $0.3 billion, to $1.7 billion for 2012 from $1.4 billion for 2011, primarily due to higher oil sales volumes and average realized oil prices partially offset by lower average realized gas prices and gas sales volumes.

Oil revenues increased $0.4 billion, to $1.5 billion for 2012 from $1.1 billion for 2011, reflecting greater sales volumes ($264.9 million) and average realized prices ($152.3 million). Oil sales volumes increased 9.8 MBbls per day to 57.7 MBbls per day in 2012 from 47.9 MBbls per day in 2011, primarily reflecting increased production from our Eagle Ford Shale properties, partially offset by a production decrease due to the divestment of our Panhandle properties in December 2011. Excluding the impact of our divestments, sales increased 15.4 MBbls per day in 2012. Our average realized price for oil increased $11.66 per Bbl to $96.64 per Bbl for 2012 from $84.98 per Bbl for 2011. The increase was primarily attributable to our new marketing contract effective January 1, 2012 for our California crude oil production that replaces the percent of NYMEX index pricing with a market based pricing approach. The average ICE Brent index price for 2012 was $112.16 per Bbl compared to the average NYMEX index price of $95.47 per Bbl for 2011.

Gas revenues decreased $169.4 million, to $162.1 million in 2012 from $331.5 million in 2011, primarily reflecting lower average realized prices ($131.9 million) and sales volumes ($37.5 million). Our average realized price for gas was $2.49 per Mcf in 2012 compared to $4.14 per Mcf in 2011. Gas sales volumes decreased 55.9 MMcf per day to 237.6 MMcf per day in 2012 from 293.5 MMcf per day in 2011, primarily reflecting our Panhandle and South Texas properties divested in December 2011, partially offset by increased production from our Eagle Ford Shale properties. Excluding the impact of our divestments, sales increased 18.5 MMcf per day in 2012.

Lease operating expenses.    Lease operating expenses increased $34.4 million, to $268.8 million in 2012 from $234.4 million in 2011, reflecting increased production primarily at our Eagle Ford Shale properties, increased well workover and repairs and maintenance expense primarily at our California properties and greater stock-based compensation expense resulting from an increase in the price of our common stock, partially offset by our Panhandle and South Texas properties divested in December 2011.

Steam gas costs.    Steam gas costs decreased $16.7 million, to $32.9 million in 2012 from $49.6 million in 2011, primarily reflecting lower cost of gas used in steam generation. In 2012 and 2011, we burned approximately 12.2 Bcf of natural gas at a cost of approximately $2.69 per MMBtu in 2012 compared to approximately $4.07 per MMBtu in 2011.

Production and ad valorem taxes.    Production and ad valorem taxes increased $13.7 million, to $52.8 million in 2012 from $39.1 million in 2011, primarily reflecting increased production taxes due to increased production from our Eagle Ford Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Gathering and transportation expenses.    Gathering and transportation expenses increased $9.7 million, to $54.5 million in 2012 from $44.8 million in 2011, primarily reflecting an increase in production from our Eagle Ford Shale properties and increased rates at our Haynesville Shale properties, partially offset by our Panhandle properties divested in December 2011.

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General and administrative expense.    G&A expense increased $14.3 million, to $109.3 million in 2012 from $95.0 million in 2011, primarily due to costs associated with the Gulf of Mexico Acquisition, increased headcount and related personnel costs supporting increased operations in the Eagle Ford Shale and greater stock-based compensation expense resulting from an increase in the price of our common stock.

Depreciation, depletion and amortization.    DD&A expense increased $245.8 million, to $699.0 million in 2012 from $453.2 million in 2011. The increase is attributable to our oil and gas depletion, primarily due to an increased per unit rate ($241.3 million). Our oil and gas unit of production rate was $25.54 per BOE in 2012 compared to $16.49 per BOE in 2011.

The increased DD&A rate is primarily due to the prolonged decrease in natural gas prices as some of our proved undeveloped reserves are no longer expected to be developed in the next five years. Additionally, the increase is due to impairment and transfer of certain unproved properties to cost subject to amortization.

Interest expense.    Interest expense increased $44.3 million, to $157.4 million in 2012 from $113.1 million in 2011, primarily due to a decrease in interest capitalized and greater average debt outstanding 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 $43.0 million and $92.5 million of interest in 2012 and 2011, respectively. The decreased capitalized interest is primarily attributable to a lower unevaluated oil and gas property balance in 2012.

(Loss) gain on mark-to-market derivative contracts.    The derivative instruments we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts 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 a $12.6 million gain related to mark-to-market derivative contracts in the nine months ended September 30, 2012, which was primarily associated with an increase in the fair value of our new crude oil derivative contracts entered into during 2012 due to decreased forward prices and settlements received on our natural gas derivative contracts. In the nine months ended September 30, 2011, we recognized a $93.5 million gain related to mark-to-market derivative contracts.

Loss on investment measured at fair value.    At September 30, 2012, 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 a gain or loss on investment measured at fair value in our income statement.

We recognized a $92.3 million loss in the nine months ended September 30, 2012 related to our McMoRan investment, which was primarily associated with a decrease in McMoRan’s stock price. In the nine months ended September 30, 2011, we recognized a $284.9 million loss related to our McMoRan investment.

Income taxes.    For the nine months ended September 30, 2012 and 2011, our income tax expense was approximately 42% of pre-tax income. The variance between these effective tax rates and the 35% federal statutory rate 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. In addition, specific items affecting our income tax expense for the nine months ended September 30, 2011 included a reduction to our balance of unrecognized tax benefits as a result of the expiration of the statute of limitations for a portion of our uncertain tax positions.

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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, including those counterparties who may have exposure to certain European sovereign debt. 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 September 30, 2012, and after making the $555 million performance deposit for the Gulf of Mexico Acquisition, we had approximately $503.8 million available for future secured borrowings under our senior revolving credit facility, which had commitments and a borrowing base of $1.4 billion and approximately $2.3 billion, respectively. At September 30, 2012, Plains Offshore had $300 million available for future secured borrowings under its senior credit facility.

Under the terms of our senior revolving credit facility, 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 factors. Our next scheduled redetermination will be on or before May 1, 2013. 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.

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. 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.

Proposed Gulf of Mexico Acquisition.    On September 10, 2012, we announced our Gulf of Mexico Acquisition of certain deepwater Gulf of Mexico oil and gas properties from BP and Shell for total cash consideration of $6.11 billion. See Recent Developments. In September 2012, to finance the Gulf of Mexico Acquisition, we successfully syndicated $7.0 billion of committed financing to a group of banks and institutional lenders. The $7.0 billion of committed financing will be comprised of a $3.0 billion senior secured five-year revolving credit facility, a $750.0 million senior secured five-year term loan, a $1.25 billion senior secured seven-year term loan and a $2.0 billion senior unsecured bridge credit facility. The initial borrowing base of the Amended Credit Facility will be set at $5.3 billion. The Amended Credit Facility will be effective upon the expected closing of the Gulf of Mexico Acquisition on November 30, 2012. The Amended Credit Facility will amend and restate our existing senior revolving credit facility. See Financing Activities.

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During the three months ended September 30, 2012, transaction costs related to the Gulf of Mexico Acquisition of approximately $6.7 million have been expensed. Upon closing, we expect to recognize additional estimated acquisition costs of $60 million which consist of:

• a $30 million commitment fee associated with the Bridge Credit Facility, which will be recorded as interest expense because we will not borrow under the Bridge Credit Facility;

• a $20 million amendment fee that we will pay in connection with an amendment to our existing stockholders agreements with the preferred investors of Plains Offshore to limit certain exclusivity provisions; and

• certain investment, advisory, legal and other acquisition related fees.

In October 2012, we issued (i) $1.5 billion of 6 ¹/₂% Senior Notes and (ii) $1.5 billion of 6 ⁷/₈% Senior Notes, both at par. See Financing Activities. The 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes effectively replace the $2.0 billion Bridge Credit Facility.

The proceeds from the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes offering along with the Amended Credit Facility will be used to refinance certain existing indebtedness, pay the cash consideration for the Gulf of Mexico Acquisition, pay fees and expenses incurred in connection with the Gulf of Mexico Acquisition and related financing transactions and for general corporate purposes.

As a result of our increased borrowings in connection with the Gulf of Mexico Acquisition, our interest expense will increase beginning in the fourth quarter of 2012.

Upon completion of our Gulf of Mexico Acquisition, we anticipate reducing our debt and strengthening our balance sheet. We anticipate entering into derivative instruments for up to 90% of our crude oil production through 2015 to lock in cash flows and to provide downside commodity price protection through the use of swap contracts, three-way collars and put and call option spread contracts. As of October 19, 2012, we had entered into Brent crude oil swap contracts for 2013 and Brent crude oil put option spread contracts for 2014 and 2015, achieving our goal for 2013 and 2014 and making significant progress for 2015. See Item 3 – Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk for a listing of our commodity derivative contracts. We anticipate divesting non-operated gas assets in 2013 and using the net proceeds to reduce debt. In addition, production from the deepwater Gulf of Mexico properties to be acquired, continued growth from our onshore oil assets and volumes from the Lucius oilfield in the deepwater Gulf of Mexico forecasted to come online in 2014 are expected to generate cash flow in excess of our capital expenditures and such excess cash flow may be applied to further reduce debt over the next several years.

We have made and will continue to make substantial capital expenditures for the acquisition, development and exploration of oil and gas. Our 2012 capital spending is expected to be approximately $2.0 billion of which approximately $180 million is funded by Plains Offshore. The increase in our capital spending is attributed to oil and gas capital and seismic data acquisition capital for development and drilling activities associated with the Gulf of Mexico Acquisition and to accelerated development activity in the Eagle Ford Shale. Higher spending in the Eagle Ford Shale is leading to an approximate 78% increase in wells drilled and a 25% increase in average daily sales volumes over the 2012 base budget. Our 2013 capital budget is expected to be approximately $2.0 billion, including capitalized interest and general and administrative expenses. We intend to fund our capital budgets from internally generated funds and borrowings under our senior revolving credit facility, with the portion of our budgets related to Plains Offshore being funded with cash on hand. In addition, we could curtail the portion of our capital expenditures that is discretionary if our cash flows decline from expected levels.

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We believe that we have sufficient liquidity through our forecasted cash flow from operations, our Amended Credit Facility, cash on hand and the Plains Offshore senior credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies, anticipated capital expenditures and preferred stock dividends of Plains Offshore. We have no near-term debt maturities. The earliest maturity of our senior notes will occur on March 1, 2016. Upon the closing of the Gulf of Mexico Acquisition, our senior revolving credit facility will mature on November 30, 2017.

Working Capital

At September 30, 2012, we had working capital of approximately $509.1 million, primarily due to the current asset classification of our investment in the McMoRan common shares and cash on hand from the Plains Offshore preferred stock transaction in November 2011. Our working capital fluctuates for various reasons, including the fair value of our investment, commodity derivative instruments, deferred taxes and stock-based compensation.

Financing Activities

Senior Revolving Credit Facility.    In February 2012, our borrowing base was increased from $1.8 billion to approximately $2.3 billion until the next scheduled redetermination date on or before May 1, 2013. The commitments remained unchanged at $1.4 billion. 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 factors. We are required, among other things, to make a mandatory prepayment if the combined total borrowings under both our senior revolving credit facility and the Plains Offshore senior credit facility exceed the borrowing base. Additionally, our senior revolving credit facility contains a $250 million limit on letters of credit and a $50 million commitment for swingline loans. At September 30, 2012, we had $895.0 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 nine months ended September 30, 2012 was $492.0 million and $573.0 million, respectively.

Amounts borrowed under our senior revolving credit facility bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 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 is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. 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.

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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 September 30, 2012, the commitments are from a diverse syndicate of 21 lenders and no single lender’s commitment represents more than 9% of the total commitments.

Plains Offshore Senior Credit Facility.    The aggregate commitments of the lenders under the Plains Offshore senior credit facility are $300 million. The Plains Offshore senior credit facility contains a $50 million limit on letters of credit and matures on November 18, 2016. At September 30, 2012, Plains Offshore had no borrowings or letters of credit outstanding under its senior credit facility.

Amounts borrowed under the Plains Offshore senior credit facility bear an interest rate, at Plains Offshore’s 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%; or (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%. The additional variable amount of interest payable is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. Letter of credit fees under the Plains Offshore senior 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.

The borrowings under the Plains Offshore senior credit facility are guaranteed on a senior basis by PXP and certain of our subsidiaries, and are secured on apari passu basis by liens on the same collateral that secures PXP’s senior revolving credit facility. The Plains Offshore senior credit facility contains certain affirmative and negative covenants, including limiting Plains Offshore’s ability, among other things, to create liens, incur other indebtedness, make dividends (excluding dividends on preferred stock) or other distributions, make investments, change the nature of Plains Offshore’s business and merge or consolidate, sell assets, enter into certain types of swap agreements and enter into certain transactions with affiliates, as well as other customary events of default, including a cross-default to PXP’s senior revolving credit facility. If an event of default (as defined in our senior revolving credit facility) has occurred and is continuing under our senior revolving credit facility that has not been cured or waived by the lenders thereunder then the Plains Offshore lenders could accelerate and demand repayment of the Plains Offshore senior credit facility.

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, 2013, 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, 2013. 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 September 30, 2012. The daily average outstanding balance for the three and nine months ended September 30, 2012 was $51.5 million and $47.8 million, respectively.

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6 ¹/₈% Senior Notes.    In April 2012, we issued $750 million of 6 ¹/₈% Senior Notes at par. We received approximately $737.5 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, including the redemption of $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes and $76.9 million aggregate principal amount of our 7% Senior Notes. We may redeem all or part of the 6 ¹/₈% Senior Notes on or after June 15, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to June 15, 2015 we may at our option, redeem up to 35% of the 6 ¹/₈% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control triggering event, as defined in the indenture, we will be required to make an offer to repurchase the 6 ¹/₈% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

6  ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes.    In October 2012, we issued (i) $1.5 billion of 6 ¹/₂% Senior Notes, and (ii) $1.5 billion of 6 ⁷/₈% Senior Notes, both at par. We received approximately $2.95 billion of net proceeds, after deducting the underwriting discount and offering expenses. We will use the net proceeds to pay a portion of the cash consideration for the Gulf of Mexico Acquisition. Pending the closing of the Gulf of Mexico Acquisition, we intend to use a portion of the net proceeds to repay borrowings outstanding under our senior revolving credit facility. Both the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes contain a mandatory redemption feature that requires us to redeem at par plus accrued but unpaid interest the aggregate principal amount of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes in cash if either (i) the BP PSA is terminated or (ii) the transaction contemplated by the BP PSA has not been consummated by March 15, 2013, which we refer to as a Mandatory Redemption Event. The terms of both the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes also provide that if, at any time, we determine that a Mandatory Redemption Event is reasonably likely to occur, then we may, at our option, redeem all and not less than all of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes then outstanding, at par plus accrued but unpaid interest. We may redeem all or part of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes on or after November 15, 2015 and February 15, 2018, respectively, at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to November 15, 2015 we may at our option, redeem up to 35% of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control triggering event, as defined in the indenture, we will be required to make an offer to repurchase the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 6 ¹/₈% Senior Notes, 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes are general unsecured senior obligations.    They are jointly and severally guaranteed by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection with any sale or other disposition of all the capital stock of a subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of such subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as such subsidiary guarantor does not have outstanding any guarantee of any of our or any of our subsidiary guarantor’s indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. The 6 ¹/₈% Senior Notes, 6 ¹/₂% Senior Notes and 6 ⁷/₈% 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 ¹/₈% Senior Notes, 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility and the Plains Offshore senior 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, including indebtedness under the Plains Offshore senior credit facility, which we guarantee, and the shares of preferred stock issued by Plains Offshore.

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Redemption of 7 ³/₄% Senior Notes and 7% Senior Notes.    During the second quarter of 2012, we redeemed the remaining $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes at 101.938% of the principal amount and the remaining $76.9 million aggregate principal amount of our 7% Senior Notes at 103.500% of the principal amount. We made payments totaling $80.8 million and $79.6 million to retire the 7 ³/₄% Senior Notes and the 7% Senior Notes, respectively. During the nine months ended September 30, 2012, we recognized $5.2 million of debt extinguishment costs, including $0.9 million of unamortized debt issue costs in connection with the retirement of these Senior Notes.

Commitment Letter.    In September 2012, we entered into the Commitment Letter to underwrite a new credit facility that will amend and restate our existing senior revolving credit facility and provide for term loan credit facilities, increase our borrowing base and provide financing in connection with the Gulf of Mexico Acquisition. The Commitment Letter is subject to certain conditions, including the absence of a material adverse effect under the BP PSA, the execution of satisfactory definitive documentation and other customary closing conditions. Upon satisfaction of these conditions, the aggregate commitments of the lenders under the Amended Credit Facility will be $5.0 billion with an initial borrowing base of $5.3 billion, which includes $300 million related to the Plains Offshore senior credit facility. The Amended Credit Facility will be comprised of a $3.0 billion senior secured five-year revolving credit facility, a $750.0 million senior secured five-year term loan, and a $1.25 billion senior secured seven-year term loan. Under the terms of the Commitment Letter, the lenders may also provide senior unsecured loans in an aggregate principal amount of up to $2.0 billion pursuant to the Bridge Credit Facility. Subsequently in September 2012, we successfully syndicated the Amended Credit Facility and Bridge Credit Facility to a group of banks and institutional lenders.

In connection with the closing of the Gulf of Mexico Acquisition, we expect to enter into our Amended Credit Facility on November 30, 2012. We will use the proceeds provided by the facilities to refinance certain existing indebtedness, to pay the cash consideration for the Gulf of Mexico Acquisition, to pay fees and expenses incurred in connection with the Gulf of Mexico Acquisition and related financing transactions and for general corporate purposes.

In connection with the issuance of the 6 ¹/₂% Senior Notes and the 6 ⁷/₈% Senior Notes, the borrowing base under our Amended Credit Facility will be reduced to $5.175 billion, which will reduce the maximum amount available to borrow under the senior secured five-year revolving credit facility to $2.875 billion from $3.0 billion. Our borrowing base for the Plains Offshore senior credit facility will remain at $300 million. In addition, as a result of the issuance of the 6 ¹/₂% Senior Notes and the 6 ⁷/₈% Senior Notes, we will not enter into the Bridge Credit Facility.

We also obtained a consent from the majority of the lenders under our senior revolving credit facility in connection with the issuance of the 6 ¹/₂% Senior Notes and the 6 ⁷/₈% Senior Notes, which allows the redemption feature in connection with a Mandatory Redemption Event and allows us to include such pro forma adjustments as if the transactions contemplated under the BP PSA had been consummated when calculating the ratio of debt to EBITDAX. In addition, the lenders also agreed that there would be no reduction to the borrowing base of our existing senior revolving credit facility in connection with the Senior Notes offering.

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Cash Flows

	Nine Months Ended September 30,
	2012		2011
	(in millions)
Cash provided by (used in):
Operating activities	$	1,046.6	$	922.7
Investing activities		(1,881.1)		(1,341.3)
Financing activities		632.5		423.7

Net cash provided by operating activities was $1.0 billion for the nine months ended September 30, 2012 compared to $922.7 million for the nine months ended September 30, 2011. The increase primarily reflects higher oil sales volumes and average realized oil prices.

Net cash used in investing activities of $1.9 billion for the nine months ended September 30, 2012 primarily reflects additions to oil and gas properties of approximately $1.4 billion and a payment of the $555 million performance deposit to BP in connection with the Gulf of Mexico Acquisition. Net cash used in investing activities of $1.3 billion for the nine months ended September 30, 2011 primarily reflects additions to oil and gas properties of $1.3 billion.

Net cash provided by financing activities of $632.5 million for the nine months ended September 30, 2012 primarily reflects proceeds from the $750 million offering of 6 ¹/₈% Senior Notes and the net increase in borrowings under our senior revolving credit facility of $160.0 million, partially offset by the redemption of our 7 ³/₄% Senior Notes and our 7% Senior Notes and $88.5 million of stock repurchases. Net cash provided by financing activities of $423.7 million for the nine months ended September 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 $165.0 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. In January 2012, we repurchased 2.4 million common shares at an average cost of $37.02 per share, totaling $88.5 million. Subsequent to these repurchases, our Board of Directors reset the authorization to $1.0 billion of PXP common stock, all of which is available for repurchase, and extended the program until January 2016.

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Critical Accounting Policies and Estimates

Oil and Natural Gas Properties Not Subject to Amortization.    The cost of unproved oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are assessed periodically, at least annually, to determine whether impairment has occurred. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The transfer of costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, geological and geophysical evaluations, the assignment of proved reserves, availability of capital, and other factors. The timing of these transfers into our amortization base impacts our DD&A rate and full cost ceiling test.

During the first quarter of 2012, due to low natural gas prices, our assessment of the unproved property in the Haynesville Shale area indicated an impairment and accumulated costs of approximately $483 million were transferred to the full cost pool.

Business Combinations.    Accounting for business combinations requires that the various assets acquired and liabilities assumed in a business combination be recorded at their respective fair values. The most significant estimates to us typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. Deferred taxes are recorded for any differences between fair value and tax basis of assets acquired and liabilities assumed. To the extent the consideration paid exceeds the fair value of the net assets acquired, we are required to record the excess as goodwill. As the fair value of assets acquired and liabilities assumed is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The value assigned to recoverable oil and gas reserves is subject to the full cost ceiling limitation, and the value assigned to unproved properties is assessed at least annually to ascertain whether impairment has occurred.

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, DD&A, commodity pricing and risk management activities, investment, stock-based compensation, goodwill and income taxes are discussed in our Annual Report on Form 10-K for the year ended December 31, 2011.

Recent Accounting Pronouncements

In December 2011, the FASB issued authoritative guidance requiring entities to disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as financial instruments and transactions subject to agreements similar to master netting arrangements. The additional disclosures will enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The guidance is effective for interim and annual periods beginning on or after January 1, 2013, and will primarily impact our disclosures associated with our commodity derivative instruments. We are currently evaluating the impact of this guidance.

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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;

• our ability to consummate the Gulf of Mexico Acquisition and related financing and to realize the expected benefits therefrom;

• unexpected difficulties in integrating our operations as a result of any significant acquisitions, including the proposed Gulf of Mexico Acquisition;

• the impact of hurricanes and other weather conditions on our offshore operations;

• the impact of the lack of physical and oilfield service infrastructure in deeper waters on our ability to bring production online;

• our ability to borrow under our new amended and restated senior revolving credit facilities;

• 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 and hydraulic fracturing;

• 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;

• our ability to divest our non-operated gas assets; and

• general economic, market, industry or business conditions.

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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, 2011.

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our primary market risk is oil and gas commodity prices. 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.

The fair value amounts of our put and collar derivative instruments are estimated using an option-pricing model, which uses various inputs including NYMEX and ICE 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. Our Level 3 commodity derivative contracts represent 24% of the total commodity derivative contracts assets and liabilities’ fair value.

The significant unobservable inputs used in the fair value measurement of our commodity derivative contracts are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement.

See Note 4 – Commodity Derivative Contracts and Note 6 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our derivative activities and fair value measurements.

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As of October 19, 2012, 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
2012
Oct - Dec	Three-way collars (2)	40,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$120.00 Ceiling
2013
Jan - Dec	Swap contracts(3)	40,000 Bbls	$109.23	-	Brent
Jan - Dec	Put options(4)	13,000 Bbls	$100.00 Floor with an $80.00 Limit	$6.800 per Bbl	Brent
Jan - Dec	Three-way collars (2)	25,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$124.29 Ceiling
Jan - Dec	Three-way collars(2)	5,000 Bbls	$90.00 Floor with a $70.00 Limit	-	Brent
			$126.08 Ceiling
Jan - Dec	Put options(4)	17,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.253 per Bbl	Brent
2014
Jan - Dec	Put options(4)	5,000 Bbls	$100.00 Floor with an $80.00 Limit	$7.110 per Bbl	Brent
Jan - Dec	Put options(4)	30,000 Bbls	$95.00 Floor with a $75.00 Limit	$6.091 per Bbl	Brent
Jan - Dec	Put options(4)	75,000 Bbls	$90.00 Floor with a $70.00 Limit	$5.739 per Bbl	Brent
2015
Jan - Dec	Put options(4)	65,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.904 per Bbl	Brent
Sales of Natural Gas Production
2012
Oct - Dec	Put options(5)	120,000 MMBtu	$4.30 Floor with a $3.00 Limit	$0.298 per MMBtu	Henry Hub
Oct - Dec	Three-way collars(6)	40,000 MMBtu	$4.30 Floor with a $3.00 Limit	-	Henry Hub
			$4.86 Ceiling
Oct - Dec	Swap contracts(3)	80,000 MMBtu	$2.72	-	Henry Hub
2013
Jan - Dec	Swap contracts(3)	110,000 MMBtu	$4.27	-	Henry Hub
2014
Jan - Dec	Swap contracts(3)	100,000 MMBtu	$4.09	-	Henry Hub

(1) The average strike prices do not reflect any premiums to purchase the put options.

(2) If the index price is less than the per barrel floor, we receive the difference between the per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and the per barrel ceiling if the index price is greater than the per barrel ceiling. If the index price is at or above the per barrel floor but at or below the per barrel ceiling, no cash settlement is required.

(3) If the index price is less than the fixed price, we receive the difference between the fixed price and the index price. We pay the difference between the index price and the fixed price if the index price is greater than the fixed price.

(4) If the index price is less than the per barrel floor, we receive the difference between the 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 the per barrel floor, we pay only the option premium.

(5) If the index price is less than the per MMBtu floor, we receive the difference between the 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 the per MMBtu floor, we pay only the option premium.

(6) If the index price is less than the per MMBtu floor, we receive the difference between the per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu. We pay the difference between the index price and the per MMBtu ceiling if the index price is greater than the per MMBtu ceiling. If the index price is at or above the per MMBtu floor but at or below the per MMBtu ceiling, no cash settlement is required.

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The fair value of outstanding crude oil and natural gas commodity derivative instruments at September 30, 2012 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 puts	$	338	$	(96)	$	123
Crude oil collars		7		(81)		66
Crude oil swaps		31		(156)		155
Natural gas puts		11		(2)		2
Natural gas collars		3		(1)		1
Natural gas swaps		10		(32)		32
	$	400	$	(368)	$	379

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 5 – Investment and Note 6 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our equity investment. At September 30, 2012, the investment, comprised of 51.0 million shares of McMoRan common stock, was valued at approximately $519.4 million. A 10% change in the underlying equity market price per share would result in a $51.9 million increase or decrease in the fair value of our investment, recognized in the income statement.

We determine the fair value of our investment by discounting 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, 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 September 30, 2012, we classified our investment as Level 3 since the fair value is determined by utilizing significant inputs that are unobservable.

Implied volatility associated with the common stock of McMoRan is a significant unobservable input used in the determination of the discount for lack of marketability of our investment measured at fair value. Significant increases (decreases) in volatility in isolation would result in a significantly higher (lower) discount factor for lack of marketability. Additionally, another significant unobservable input, the expected term of our investment, impacts the discount factor for lack of marketability. Significant increases (decreases) in the expected term in isolation would result in a significantly higher (lower) discount factor for lack of marketability. A higher discount factor would result in a lower fair value measurement of our investment.

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ITEM 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rules 13a-15(e) and 15d-15(e) 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 September 30, 2012 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 September 30, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1A. Risk Factors

There has been no material change to our risk factors set forth in Part 1, Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2011, except as set forth below.

Legislation and regulatory initiatives relating to hydraulic fracturing could increase our cost of doing business and adversely affect our operations.

Our operations utilize the practice of hydraulic fracturing for new oil and natural gas wells and is also occasionally used to recomplete or restimulate an existing well that has declined in production performance. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formation to stimulate oil and natural gas production. The use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many reservoirs, especially shale formations such as the Haynesville Shale and the Eagle Ford Shale. The process is typically regulated by state oil and natural gas commissions, and continues to receive significant regulatory and legislative attention at the federal, state, and local level. The U.S. Environmental Protection Agency, or EPA, recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act, or SDWA, and is in the process of drafting guidance documents on regulatory requirements for companies that plan to conduct hydraulic fracturing using diesel. In addition, on May 11, 2012, the Bureau of Land Management proposed regulations that would require public disclosure of the chemicals used in hydraulic fracturing and impose certain permitting and testing requirements on such operations on federal lands. Various federal agencies in addition to the EPA (including the Department of Energy) continue to study hydraulic fracturing and may propose additional regulations. From time to time, legislation has been introduced in Congress to amend the federal SDWA to eliminate exemptions for most hydraulic fracturing activities. In addition to the SDWA, the EPA recently approved final rules that establish new air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with production and processing activities, which rules were published in the Federal Register on August 16, 2012. Similar efforts to review the practice and impose new regulatory conditions are taking place at the state and local level in states where we operate, several of which have adopted or are considering new regulations and statutes, including California, Texas and Wyoming. These new requirements will (and future regulatory and legislative changes, if enacted, could) create new permitting and financial assurance requirements, require us to adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. The imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business and adversely affect our operations, and depending on the specifics of any particular proposal that is enacted, could be material.

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We may be subject to risks in connection with acquisitions, including the Gulf of Mexico Acquisition, and other strategic transactions and the integration of significant acquisitions and other strategic transactions may be difficult.

In addition to the Gulf of Mexico Acquisition, we periodically evaluate other potential acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties, including the pending acquisitions, requires an assessment of several factors, including:

• recoverable reserves;

• future oil and gas prices and their appropriate differentials;

• development and operating costs and potential environmental and other liabilities; and

• our ability to obtain external financing to fund the purchase price.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis, and, as is the case with certain liabilities associated with the Gulf of Mexico properties, we are entitled to only limited indemnification for environmental liabilities.

Significant acquisitions, including the Gulf of Mexico Acquisition, and other strategic transactions may involve other risks, including:

• diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

• the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

• difficulty associated with coordinating geographically separate assets;

• the challenge of attracting and retaining personnel associated with acquired operations; and

• the failure to realize the full benefit that we expect in estimated proved reserves and resource potential, production volume or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame and costs.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

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As a result of the Gulf of Mexico Acquisition, we will have greater exposure to the substantial regulations and risks that affect our offshore operations, which could adversely affect our ability to operate and our financial results.

We currently conduct operations offshore California and in the U.S. Gulf of Mexico, and as a result of the Gulf of Mexico Acquisition, a substantially greater portion of our assets will be located in the U.S. Gulf of Mexico. Offshore oil and gas operations are subject to more extensive governmental regulation than our other oil and gas activities.

In addition, properties offshore Gulf of Mexico, including the Gulf of Mexico properties, are vulnerable to risks relating to:

• hurricanes and other adverse weather conditions;

• oilfield service costs and availability;

• compliance with environmental and other laws and regulations;

• remediation and other costs resulting from oil spill releases of hazardous materials and other environmental damages; and

• failure of equipment or facilities.

We conduct all of our exploration in, and the Gulf of Mexico properties are located in, the deeper waters of the U.S. Gulf of Mexico, where operations are more difficult and costly than in shallower waters. The deeper waters in the Gulf of Mexico lack the physical and oilfield service infrastructure present in its shallower waters and could result in significant delays in obtaining or maintaining production from the assets. As a result, deepwater operations may require a significant amount of time between a discovery and the time that we can market our production, thereby increasing the risk involved with these operations.

The extent to which our business is subject to the risks described above will increase as a result of the Gulf of Mexico Acquisition, and therefore our costs, ability to operate and financial results could be adversely affected.

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ITEM 6. Exhibits

Exhibit No.	Description
2.1*	Purchase and Sale Agreement dated as of September 4, 2012, and effective as of October 1, 2012, by and among BP Exploration & Production, Inc., BP America Production Company and Plains Exploration & Production Company.
2.2*	Purchase and Sale Agreement dated as of September 7, 2012, and effective as of October 1, 2012, by and among Shell Offshore Inc. and Plains Exploration & Production Company.
2.3*	Commitment Letter dated September 4, 2012, among JPMorgan Chase Bank, N.A., J.P. Morgan Securities LLC and Plains Exploration & Production Company.
31.1*	Rule 13(a)-14(a)/15d-14(a) Certificate of the Chief Executive Officer.
31.2*	Rule 13(a)-14(a)/15d-14(a) Certificate of the Chief Financial Officer.
32.1**	Section 1350 Certificate of the Chief Executive Officer.
32.2**	Section 1350 Certificate of the Chief Financial Officer.
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

      ** Furnished herewith

Items 1, 2, 3, 4 and 5 are not applicable and have been omitted.

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SIGNATURES

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

	PLAINS EXPLORATION & PRODUCTION COMPANY
Date: November 1, 2012	By:	/s/ Winston M. Talbert
		Winston M. Talbert
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

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EXHIBIT INDEX

Exhibit No.	Description
2.1*	Purchase and Sale Agreement dated as of September 4, 2012, and effective as of October 1, 2012, by and among BP Exploration & Production, Inc., BP America Production Company and Plains Exploration & Production Company.
2.2*	Purchase and Sale Agreement dated as of September 7, 2012, and effective as of October 1, 2012, by and among Shell Offshore Inc. and Plains Exploration & Production Company.
2.3*	Commitment Letter dated September 4, 2012, among JPMorgan Chase Bank, N.A., J.P. Morgan Securities LLC and Plains Exploration & Production Company.
31.1*	Rule 13(a)-14(a)/15d-14(a) Certificate of the Chief Executive Officer.
31.2*	Rule 13(a)-14(a)/15d-14(a) Certificate of the Chief Financial Officer.
32.1**	Section 1350 Certificate of the Chief Executive Officer.
32.2**	Section 1350 Certificate of the Chief Financial Officer.
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
**	Furnished herewith

63