UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2011

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

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

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

 

 

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

PART I. FINANCIAL INFORMATION
ITEM 1. Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets March 31, 2011 and December 31, 2010			1
Consolidated Statements of Income For the three months ended March 31, 2011 and 2010			2
Consolidated Statements of Cash Flows For the three months ended March 31, 2011 and 2010			3
Consolidated Statement of Stockholders’ Equity For the three months ended March 31, 2011			4
Notes to Consolidated Financial Statements			5
ITEM  2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			25
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			35
ITEM 4. Controls and Procedures			36
PART II. OTHER INFORMATION			37

 

(i)

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

 

		March 31,     2011				December 31,   2010
ASSETS
Current Assets
Cash and cash equivalents		$	3,644			$	6,434
Accounts receivable			253,626				269,024
Inventories			22,104				24,406
Deferred income taxes			90,953				74,086
Prepaid expenses and other current assets			22,520				28,937
			392,847				402,887
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization			10,387,694				9,975,056
Not subject to amortization			3,288,576				3,304,554
Other property and equipment			139,821				137,150
			13,816,091				13,416,760
Less allowance for depreciation, depletion, amortization and impairment			(6,327,976)				(6,196,008)
			7,488,115				7,220,752
Goodwill			535,142				535,144
Investment			731,600				664,346
Other Assets			76,329				71,808
		$	9,224,033			$	8,894,937
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable		$	313,564			$	284,628
Commodity derivative contracts			81,423				52,971
Royalties and revenues payable			70,653				70,990
Interest payable			58,793				49,127
Other current liabilities			84,123				75,973
			608,556				533,689
Long-Term Debt			3,451,131				3,344,717
Other Long-Term Liabilities
Asset retirement obligation			234,672				225,571
Commodity derivative contracts			32,431				24,740
Other			22,750				28,205
			289,853				278,516
Deferred Income Taxes			1,418,759				1,355,050
Commitments and Contingencies (Note 8)
Stockholders’ Equity
Common stock, $0.01 par value, 250.0 million shares authorized, 143.9 million shares issued at March 31, 2011 and December 31, 2010			1,439				1,439
Additional paid-in capital			3,399,696				3,427,869
Retained earnings			204,275				148,620
Treasury stock, at cost, 2.9 million shares and 3.8 million shares at March 31, 2011 and December 31, 2010, respectively			(149,676)				(194,963)
			3,455,734				3,382,965
		$	9,224,033			$	8,894,937

See notes to consolidated financial statements.

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(in thousands, except per share data)

 

		Three Months Ended       March 31,
		2011				2010
Revenues
Oil sales		$	331,843			$	276,004
Gas sales			96,802				107,739
Other operating revenues			1,669				307
			430,314				384,050
Costs and Expenses
Lease operating expenses			72,251				62,503
Steam gas costs			15,761				19,663
Electricity			9,720				10,034
Production and ad valorem taxes			11,528				8,447
Gathering and transportation expenses			12,747				9,419
General and administrative			36,023				37,390
Depreciation, depletion and amortization			134,543				122,393
Accretion			4,257				4,411
Legal recovery			-				(8,423)
Other operating income			(304)				(569)
			296,526				265,268
Income from Operations			133,788				118,782
Other (Expense) Income
Interest expense			(32,404)				(21,053)
Debt extinguishment costs			-				(728)
(Loss) gain on mark-to-market derivative contracts			(50,996)				7,856
Gain on investment measured at fair value			67,254				-
Other income			554				1,306
Income Before Income Taxes			118,196				106,163
Income tax expense
Current			(372)				(4,738)
Deferred			(46,845)				(42,897)
Net Income		$	70,979			$	58,528
Earnings per Share
Basic		$	0.50			$	0.42
Diluted		$	0.49			$	0.41
Weighted Average Shares Outstanding
Basic			140,868				139,741
Diluted			143,416				141,940

See notes to consolidated financial statements.

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands of dollars)

 

		Three Months Ended       March 31,
		2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	70,979			$	58,528
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization			134,543				122,393
Accretion			4,257				4,411
Deferred income tax expense			46,845				42,897
Debt extinguishment costs			-				728
Loss (gain) on mark-to-market derivative contracts			50,996				(7,856)
Gain on investment measured at fair value			(67,254)				-
Non-cash compensation			16,806				16,900
Other non-cash items			918				1,371
Change in assets and liabilities from operating activities
Accounts receivable and other assets			(13,257)				263
Accounts payable and other liabilities			4,752				(31,262)
Income taxes receivable/payable			40,378				13,405
Net cash provided by operating activities			289,963				221,778
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties			(358,472)				(267,015)
Acquisition of oil and gas properties			(24,511)				51,065
Proceeds from sales of oil and gas properties, net of costs
and expenses			11,987				-
Derivative settlements			(15,021)				(9,460)
Additions to other property and equipment			(2,671)				(2,137)
Net cash used in investing activities			(388,688)				(227,547)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities			1,313,850				625,935
Repayments of revolving credit facilities			(1,808,850)				(855,935)
Proceeds from issuance of Senior Notes			600,000				300,000
Costs incurred in connection with financing arrangements			(9,069)				(5,344)
Other			4				-
Net cash provided by financing activities			95,935				64,656
Net (decrease) increase in cash and cash equivalents			(2,790)				58,887
Cash and cash equivalents, beginning of period			6,434				1,859
Cash and cash equivalents, end of period		$	3,644			$	60,746

See notes to consolidated financial statements.

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(share and dollar amounts in thousands)

 

										Additional
		Common Stock								Paid-in				Retained				Treasury Stock
		Shares				Amount				Capital				Earnings				Shares				Amount				Total
Balance at December 31, 2010			143,924			$	1,439			$	3,427,869			$	148,620				(3,764)			$	(194,963)			$	3,382,965
Net income			-				-				-				70,979				-				-				70,979
Restricted stock awards			-				-				1,782				-				-				-				1,782
Issuance of treasury stock for restricted stock awards			-				-				(29,955)				(15,304)				845				45,259				-
Exercise of stock options and other			-				-				-				(20)				1				28				8
Balance at March 31, 2011			143,924			$	1,439			$	3,399,696			$	204,275				(2,918)			$	(149,676)			$	3,455,734

See notes to consolidated financial statements.

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1 — Summary of Significant Accounting Policies

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

Our consolidated financial statements include the accounts of all our wholly owned subsidiaries and a variable interest entity for which we are the primary beneficiary. 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 period, have been reflected. The results of our operations for the three months ended March 31, 2011 are not necessarily indicative of the results to be expected for the full year.

These consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements and should be read in conjunction with the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2010.

Asset Retirement Obligation. The following table reflects the changes in our asset retirement obligation during the three months ended March 31, 2011 (in thousands):

 

Asset retirement obligation - December 31, 2010		$	239,432
Settlements			(493)
Accretion expense			4,257
Asset retirement additions			5,368
Asset retirement obligation - March 31, 2011 (1)		$	248,564

 

(1)

$13.9 million is included in other current liabilities.

Earnings Per Share. For the three months ended March 31, 2011 and 2010, the weighted average shares outstanding for computing basic and diluted earnings per share were (in thousands):

 

		Three Months Ended     March 31,
		2011				2010
Weighted average common shares outstanding - basic			140,868				139,741
Unvested restricted stock, restricted stock units and stock options			2,548				2,199
Weighted average common shares outstanding - diluted			143,416				141,940

 

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In the three months ended March 31, 2011 and 2010, 1.0 million and 12,660, respectively, restricted stock units were excluded in computing diluted earnings per share because they were antidilutive due to the impact of the unrecognized compensation cost on the calculation of assumed proceeds in the application of the treasury stock method. In computing earnings per share, no adjustments were made to reported net income.

Inventories. Oil inventories are carried at the lower of the cost to produce or market value, and materials and supplies inventories are stated at the lower of cost or market with cost determined on an average cost method. At March 31, 2011 and December 31, 2010, inventory consisted of the following (in thousands):

 

		March 31,   2011				December 31,   2010
Oil		$	7,332			$	6,744
Materials and supplies			14,772				17,662
		$	22,104			$	24,406

Stock-Based Compensation. Stock-based compensation for the three months ended March 31, 2011 was $21.3 million, of which $13.8 million is included in general and administrative expense, or G&A, $3.0 million is included in lease operating expense and $4.5 million is included in oil and natural gas properties. Stock-based compensation for the three months ended March 31, 2010 was $21.7 million, of which $14.6 million is included in G&A, $2.3 million is included in lease operating expense and $4.8 million is included in oil and natural gas properties.

During the first three months of 2011, we granted 1.5 million restricted stock units, or RSUs, at an average fair value of $37.33 per share and 872 thousand stock appreciation rights with an average exercise price of $37.28 per share.

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

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

 

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Note 2 — Long-Term Debt

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

 

		March 31, 2011				December 31,   2010
Senior revolving credit facility		$	125,000			$	620,000
7 3/4% Senior Notes due 2015			600,000				600,000
10% Senior Notes due 2016 (1)			532,110				530,812
7% Senior Notes due 2017			500,000				500,000
7 5/8% Senior Notes due 2018			400,000				400,000
8 5/8% Senior Notes due 2019 (2)			394,021				393,905
7 5/8% Senior Notes due 2020			300,000				300,000
6 5/8% Senior Notes due 2021			600,000				-
		$	3,451,131			$	3,344,717

 

(1)      The amount is net of unamortized discount of $32.9 million and $34.2 million at March 31, 2011 and December 31, 2010, respectively.

(2)      The amount is net of unamortized discount of $6.0 million and $6.1 million at March 31, 2011 and December 31, 2010, respectively.

Senior Revolving Credit Facility. The aggregate commitments of the lenders under our senior revolving credit facility are $1.4 billion with a borrowing base of $1.45 billion. Our borrowing base was adjusted from $1.6 billion to $1.45 billion in recognition of our issuance of the 6⁵/₈% Senior Notes due 2021, or 6⁵/₈% Senior Notes, in March 2011. The borrowing base will be redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors. Additionally, our senior revolving credit facility contains a $250 million limit on letters of credit, a $50 million commitment for swingline loans and matures on August 3, 2015. At March 31, 2011, we had $1.2 million in letters of credit outstanding under our senior revolving credit facility.

Amounts borrowed under our senior revolving credit facility 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 1.75% to 2.75%; (ii) a variable amount ranging from 0.75% to 1.75% 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 1.75% to 2.75% for swingline loans. The additional variable amount of interest payable on outstanding borrowings is based on the utilization rate as a percentage of the total amount of funds borrowed under our senior revolving credit facility to the borrowing base. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and range from 1.75% to 2.75%. Commitment fees are 0.50% of the amount available for borrowing.

Our senior revolving credit facility is secured by 100% of the shares of stock in certain of our domestic 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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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, 2011, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding fourteen days and all amounts outstanding are due and payable no later than June 1, 2011. 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 March 31, 2011. The daily average outstanding balance for the quarter ended March 31, 2011 was $53.9 million.

In March 2011, we issued $600 million of 6⁵/₈% Senior Notes at par. We received approximately $590 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes. We may redeem all or part of the 6⁵/₈% Senior Notes on or after May 1, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to May 1, 2014 we may, at our option, redeem up to 35% of the 6⁵/₈% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 6⁵/₈% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 6⁵/₈% Senior Notes are general unsecured senior obligations. They are jointly and severally guaranteed on a full and unconditional basis by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. These 6⁵/₈% 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 6⁵/₈% Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility, to the extent of our assets constituting collateral securing that indebtedness; and effectively subordinate to all existing and future indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our non-guarantor subsidiaries.

Subsequent Event

In April 2011, our borrowing base was increased to $1.8 billion from $1.45 billion. The commitments remained unchanged at $1.4 billion. In addition, we entered into an amendment to our senior revolving credit facility. The amendment adjusted our borrowing rates and the maturity date was extended to May 4, 2016.

Amounts borrowed under our senior revolving credit facility, as amended, bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; (ii) a variable amount ranging from 0.50% to 1.50% plus the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus  ¹/2 of 1%, and (3) the adjusted LIBOR plus 1%; or (iii) the overnight federal funds rate plus an additional variable amount ranging from 1.50% to 2.50% for swingline loans. The additional variable amount of interest payable on outstanding borrowings is based on the utilization rate as a percentage of the total amount of funds borrowed under our senior revolving credit facility to the borrowing base. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% for amounts available for borrowing.

The other terms and conditions of our senior revolving credit facility remained the same.

 

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Note 3 — Commodity Derivative Contracts

General

We are exposed to various market risks, including volatility in oil and gas commodity prices and interest rates. The level of derivative activity we engage in depends on our view of market conditions, available derivative prices and operating strategy. A variety of derivative instruments, such as swaps, collars, puts, calls and various combinations of these instruments, may be utilized to manage our exposure to the volatility of oil and gas commodity prices. Currently, we do not use derivatives to manage our interest rate risk. The interest rate on our senior revolving credit facility is variable, while our senior notes are at fixed interest rates, thereby mitigating our interest rate risk exposure.

All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized in our income statement as a gain or loss on mark-to-market derivative contracts. Cash flows are only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. The derivative instruments we have in place are not classified as hedges for accounting purposes.

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

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

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

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

 

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As of March 31, 2011, we had the following outstanding commodity derivative contracts, all of which settle monthly:

 

Period		Instrument Type		Daily Volumes		Average Price (1)		Average Deferred Premium		Index
Sales of Crude Oil Production
2011
Apr - Dec		Put options (2)		31,000 Bbls		$80.00 Floor with a $60.00 Limit		$5.023 per Bbl		WTI
Apr - Dec		Three-way collars (3)		9,000 Bbls		$80.00 Floor with a $60.00 Limit		$1.00 per Bbl		WTI
						$110.00 Ceiling
2012
Jan - Dec		Put options (2)		40,000 Bbls		$80.00 Floor with a $60.00 Limit		$6.087 per Bbl		WTI
Sales of Natural Gas Production
2011
Apr - Dec		Three-way collars (4)		200,000 MMBtu		$4.00 Floor with a $3.00 Limit		-		Henry Hub
						$4.92 Ceiling
2012
Jan - Dec		Put options (5)		160,000 MMBtu		$4.30 Floor with a $3.00 Limit		$0.294 per MMBtu		Henry Hub

 

(1)

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

(2)

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

(3)

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

(4)

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

(5)

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

Balance Sheet

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

 

				Estimated Fair Value
Instrument Type		Balance Sheet Classification		March 31,       2011				December 31,   2010
Crude oil puts		Commodity derivative contracts - current asset		$	14,236			$	23,910
Natural gas puts		Commodity derivative contracts - current asset			2,809				-
Crude oil collars		Commodity derivative contracts - current liability			(14,707)				(317)
Natural gas collars		Commodity derivative contracts - current liability			(7,415)				(10,469)
Crude oil puts		Commodity derivative contracts - non-current asset			35,833				64,266
Natural gas puts		Commodity derivative contracts - non-current asset			10,273				15,254
Total derivative instruments				$	41,029			$	92,644

 

10

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

 

		March 31, 2011				December 31,  2010
Net fair value asset		$	41,029			$	92,644
Deferred premium and accrued interest on derivative contracts			(149,777)				(164,155)
Settlement payable			(5,106)				(6,200)
Net commodity derivative liability		$	(113,854)			$	(77,711)
Commodity derivative contracts - current liability		$	(81,423)			$	(52,971)
Commodity derivative contracts - non-current liability			(32,431)				(24,740)
		$	(113,854)			$	(77,711)

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

Income Statement

During the three months ended March 31, 2011 and 2010, pre-tax amounts recognized in our income statement for derivative transactions were as follows (in thousands):

 

		Three Months Ended   March 31,
		2011				2010
(Loss) gain on mark-to-market derivative contracts		$	(50,996)			$	7,856

Cash Payments and Receipts

During the three months ended March 31, 2011 and 2010, cash (payments) receipts for derivatives were as follows (in thousands):

 

		Three Months Ended March 31,
		2011				2010
Oil derivatives		$	(15,641)			$	(14,549)
Natural gas derivatives			620				5,089
		$	(15,021)			$	(9,460)

Credit Risk

We generally do not require collateral or other security to support derivative instruments subject to credit risk. However, the agreements with each of the counterparties to our derivative instruments contain netting provisions within the agreements. If a default occurs under the agreements, the non-defaulting party can offset the amount payable to the defaulting party under the derivative contracts with the amount due from the defaulting party under the derivative contracts. As a result of the netting provisions under the agreements, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts.

 

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Contingent Features

As of March 31, 2011, the counterparties to our commodity derivative contracts consisted of nine financial institutions. Our counterparties or their affiliates are generally also lenders under our senior revolving credit facility. As a result, the counterparties to our derivative agreements share in the collateral supporting our senior revolving credit facility. Therefore, we are not generally required to post additional collateral under our derivative agreements.

Certain of our derivative agreements contain cross default and acceleration provisions relative to our material debt agreements. If we were to default on any of our material debt agreements, it would be a violation of these provisions, and the counterparties to our derivative agreements could request immediate payment on derivative instruments that are in a net liability position at that time. As of March 31, 2011, we were in a net liability position with all nine of the counterparties to our derivative instruments, totaling $113.9 million.

Note 4 — Investment

At March 31, 2011, we owned 51.0 million shares of McMoRan Exploration Co. common stock, approximately 32.2% of their common shares outstanding. In December 2010, we acquired the McMoRan common stock and other consideration in exchange for all of our interests in our Gulf of Mexico leasehold located in less than 500 feet of water. We entered into a stockholder agreement with McMoRan requiring us to refrain from certain activities that could be undertaken to acquire control of McMoRan and from transferring any McMoRan shares for one year after closing (subject to certain exceptions). After one year from the acquisition date, we may sell shares of McMoRan common stock pursuant to underwritten offerings, in periodic sales under a shelf registration statement filed by McMoRan (subject to certain volume limitations), pursuant to the exercise of piggyback registration rights or as otherwise permitted by applicable law.

We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as gain 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 March 31, 2011, the McMoRan shares were valued at approximately $731.6 million, based on McMoRan’s closing stock price of $17.71 on March 31, 2011, discounted to reflect certain restrictions on the marketability of the McMoRan shares. During the three months ended March 31, 2011, we recorded a $67.3 million gain 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):

 

		Three Months Ended   March 31, 2011 (1)
Results of Operations
Revenues		$	44,115
Operating loss			(2,983)
Loss from continuing operations			(4,680)
Net loss applicable to common stock			(8,871)
(1)    Amounts represent our 32.2% equity ownership in McMoRan.

 

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Note 5 — Fair Value Measurements of Assets and Liabilities

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

 

			Identical Assets				Identical Assets				Identical Assets				Identical Assets
						Fair Value Measurements at Reporting Date Using
		Fair Value (1)				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
March 31, 2011
Commodity derivative contracts
Crude oil puts		$	50,069			$	-			$	50,069			$	-
Crude oil collars			(14,707)				-				(14,707)				-
Natural gas collars			(7,415)				-				-				(7,415)
Natural gas puts			13,082				-				-				13,082
Investment (2)			731,600				-				-				731,600
		$	772,629			$	-			$	35,362			$	737,267
December 31, 2010
Commodity derivative contracts
Crude oil puts		$	88,176			$	-			$	88,176			$	-
Crude oil collars			(317)				-				(317)				-
Natural gas collars			(10,469)				-				-				(10,469)
Natural gas puts			15,254				-				-				15,254
Investment (2)			664,346				-				-				664,346
		$	756,990			$	-			$	87,859			$	669,131

 

(1)	Option premium and accrued interest of $149.8 million and $164.2 million at March 31, 2011 and December 31, 2010, respectively, and settlement payable of $5.1 million and $6.2 million at March 31, 2011 and December 31, 2010, respectively, are not included in the fair value of derivatives.

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

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

 

13

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We classify derivatives that have identical assets or liabilities with quoted, unadjusted prices in active markets as Level 1. We classify derivatives as Level 2 if the inputs used in the valuation model are directly or indirectly observable for substantially the full term of the instrument; however, if the significant inputs are not observable for substantially the full term of the instrument, we classify those derivatives as Level 3. We determine whether the market for our derivative instruments is active or inactive based on transaction volume for such instruments and classify as Level 3 those instruments that are not actively traded. For these inputs, we utilize pricing and volatility information from other instruments with similar characteristics and extrapolate data between data points for thinly traded instruments. As of March 31, 2011, our crude oil put options and crude oil collars are classified as Level 2, and our natural gas put options and natural gas collars are classified as Level 3 instruments.

We determine the fair value of our investment by applying a discount for lack of marketability at the reporting date. The discount factor for lack of marketability is determined by utilizing both Protective put and Asian put option models. Both of these options are valued using a Black-Scholes option-pricing model which utilizes various inputs including the closing price of the McMoRan common stock, term of the restrictions, historical and implied volatility of the instrument, number of shares being valued, length of time that would be necessary to dispose of our investment, expected dividend and risk-free interest rates. As of March 31, 2011, we have classified our investment as Level 3 since the fair value is determined by utilizing significant inputs that are unobservable.

We determine the appropriate level for each financial asset and liability on a quarterly basis and recognize any transfers at the beginning of the reporting period.

The following table presents a reconciliation of changes in fair value of financial assets and liabilities classified as Level 3 for the three months ended March 31, 2011 and 2010 (in thousands):

 

		Three Months Ended March 31,
		2011												2010
		Commodity Derivatives (1)				Investment								Commodity Derivatives (1)
Fair value at beginning of period		$	4,785			$	664,346							$	14,312
Transfers			-				-								-
Realized and unrealized gains and losses included in earnings (2)			1,502				67,254								19,757
Purchases			-				-								-
Settlements			(620)				-								(5,345)
Fair value at end of period		$	5,667			$	731,600							$	28,724
Change in unrealized gains and losses relating to assets and liabilities held as of the end of the period (2)		$	795			$	67,254							$	18,100

 

(1)

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

(2)

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

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.

 

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Fair Value of Other Financial Instruments

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

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

The following table presents the carrying amounts and fair values of our other financial instruments as of March 31, 2011 and December 31, 2010 (in thousands):

 

		March 31, 2011								December 31, 2010
		Carrying   Amount				Fair Value				Carrying   Amount				Fair Value
Current Liability
Deferred premium and accrued interest on derivative contracts		$	71,240			$	71,240			$	59,895			$	59,895
Non-Current Liability
Deferred premium and accrued interest on derivative contracts			78,537				78,537				104,260				104,260
Long-Term Debt
Senior revolving credit facility			125,000				125,000				620,000				620,000
7 3/4% Senior Notes			600,000				626,250				600,000				625,500
10% Senior Notes			532,110				637,038				530,812				631,388
7% Senior Notes			500,000				516,250				500,000				513,750
7 5/8% Senior Notes			400,000				428,000				400,000				421,000
8 5/8% Senior Notes			394,021				445,000				393,905				438,000
7 5/8% Senior Notes			300,000				321,000				300,000				316,125
6 5/8% Senior Notes			600,000				600,000				-				-

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

Note 6 — Variable Interest Entity — PXP Operations LLC

In conjunction with the acquisition of our Eagle Ford Shale properties during the fourth quarter of 2010, and in anticipation of divesting our deepwater Gulf of Mexico properties, we entered into a series of reverse like-kind exchange agreements pursuant to Section 1031 of the Internal Revenue Code, or IRC. The purchase consideration related to the Eagle Ford Shale properties was loaned by PXP to the qualified intermediary, PXP Operations LLC, to facilitate the potential tax deferred reverse like-kind exchange treatment under IRC 1031.

 

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Since PXP Operations’ equity at risk is insufficient to permit PXP Operations to carry on its activities without additional subordinated financial support, PXP Operations meets the criteria for a variable interest entity. PXP is the primary beneficiary for accounting purposes because we have the power to direct the most significant activities that impact PXP Operations’ economic performance through a management agreement. In addition, we have the obligation to absorb a majority of the losses or receive a majority of the benefits that could potentially be significant to the variable interest entity. As a result, we consolidate PXP Operations in our consolidated financial statements. The carrying amounts associated with PXP Operations, after eliminating the effect of intercompany transactions, were as follows (in thousands):

 

		March 31,     2011
Assets
Accounts receivable		$	20,377
Other			31
Oil and natural gas properties - full cost method
Subject to amortization - net of depreciation, depletion and amortization			108,175
Not subject to amortization			574,240
			702,823
Liabilities
Accounts payable			32,200
Other			5,026
Net carrying amount		$	665,597

Subsequent Event. In April 2011, two of the reverse like-kind exchange arrangements pursuant to IRC Section 1031 were concluded prior to the completion of a like-kind exchange involving any disposition of PXP properties. As a result, the related Eagle Ford Shale properties were transferred from PXP Operations LLC to PXP and the outstanding notes between PXP Operations LLC and PXP were settled. The remaining reverse like-kind exchange arrangements are expected to be concluded in May 2011.

Note 7 — Income Taxes

Income tax expense during interim periods is based on the estimated annual effective income tax rate plus any significant unusual or infrequently occurring items which are recorded in the period that the specific item occurs. For the three months ended March 31, 2011, income tax expense was approximately 40% of pre-tax income. The variance in our estimated annual effective tax rate from the 35% federal statutory rate primarily results from the tax effects of estimated annual permanent differences, including (i) expenses that are not deductible because of IRS limitations and (ii) state income taxes.

Note 8 — 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.

 

16

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Plugging, Abandonment and Remediation Obligations. Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically, when producing oil and gas assets are purchased the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we receive an indemnity with respect to those costs. We cannot 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, $71.2 million ($144.1 million undiscounted), is included in our asset retirement obligation as reflected on our balance sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $75.0 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At March 31, 2011, the escrow account had a balance of $17.8 million. The fair value of our guarantee at March 31, 2011, $0.4 million, considers the payment/performance risk of the purchaser and is included in other long-term liabilities in our balance sheet.

Operating Risks and Insurance Coverage. Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including well blowouts, cratering, explosions, oil spills, releases of gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property or injury to persons. Our operations in California, including transportation of oil by pipelines within the city and county of Los Angeles, are especially susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. We maintain coverage for earthquake damages in California but this coverage may not provide for the full effect of damages that could occur and we may be subject to additional liabilities. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of high premium costs. We are self-insured for named windstorms in the 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.

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

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

 

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Note 9 — Consolidating Financial Statements

We are the issuer of $600 million of 7³/₄% Senior Notes, $565 million of 10% Senior Notes, $500 million of 7% Senior Notes, $400 million of 7⁵/₈% Senior Notes due 2018, $400 million of 8⁵/₈% Senior Notes, $300 million of 7⁵/₈% Senior Notes due 2020 and $600 million of 6⁵/₈% Senior Notes as of March 31, 2011, which are jointly and severally guaranteed on a full and unconditional basis by certain of our existing domestic subsidiaries (referred to as “Guarantor Subsidiaries”). Certain of our subsidiaries do not guarantee the Senior Notes (referred to as “Non-Guarantor Subsidiaries”).

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)

MARCH 31, 2011

(in thousands of dollars)

 

		Issuer				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
ASSETS
Current Assets
Cash and cash equivalents		$	3,335			$	8			$	301			$	-			$	3,644
Accounts receivable and other
current assets			229,157				140,290				19,756				-				389,203
			232,492				140,298				20,057				-				392,847
Property and Equipment, at cost
Oil and natural gas properties - full cost method			3,964,707				8,956,066				755,497				-				13,676,270
Other property and equipment			50,336				42,179				47,306				-				139,821
			4,015,043				8,998,245				802,803				-				13,816,091
Less allowance for depreciation, depletion, amortization and impairment			(2,457,719)				(5,997,069)				(84,676)				2,211,488				(6,327,976)
			1,557,324				3,001,176				718,127				2,211,488				7,488,115
Investment in and Advances to Affiliates			5,287,021				(1,693,708)				(728,564)				(2,864,749)				-
Other Assets			796,848				546,223				-				-				1,343,071
		$	7,873,685			$	1,993,989			$	9,620			$	(653,261)			$	9,224,033
LIABILITIES AND
STOCKHOLDERS’ EQUITY
Current Liabilities		$	406,127			$	165,811			$	36,618			$	-			$	608,556
Long-Term Debt			3,451,131				-				-				-				3,451,131
Other Long-Term Liabilities			222,499				66,699				655				-				289,853
Deferred Income Taxes			338,194				288,961				(4,210)				795,814				1,418,759
Stockholders’ Equity			3,455,734				1,472,518				(23,443)				(1,449,075)				3,455,734
		$	7,873,685			$	1,993,989			$	9,620			$	(653,261)			$	9,224,033

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2010

(in thousands of dollars)

 

		Issuer				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
ASSETS
Current Assets
Cash and cash equivalents		$	6,020			$	8			$	406			$	-			$	6,434
Accounts receivable and other
current assets			256,561				133,761				6,131				-				396,453
			262,581				133,769				6,537				-				402,887
Property and Equipment, at cost
Oil and natural gas properties -
full cost method			3,878,473				8,721,483				679,654				-				13,279,610
Other property and equipment			49,110				41,736				46,304				-				137,150
			3,927,583				8,763,219				725,958				-				13,416,760
Less allowance for depreciation, depletion, amortization and impairment			(2,420,233)				(5,769,846)				(62,262)				2,056,333				(6,196,008)
			1,507,350				2,993,373				663,696				2,056,333				7,220,752
Investment in and Advances to Affiliates			5,088,866				(1,562,441)				(665,455)				(2,860,970)				-
Other Assets			726,277				545,021				-				-				1,271,298
		$	7,585,074			$	2,109,722			$	4,778			$	(804,637)			$	8,894,937
LIABILITIES AND
STOCKHOLDERS’ EQUITY
Current Liabilities		$	362,741			$	147,246			$	23,702			$	-			$	533,689
Long-Term Debt			3,344,717				-				-				-				3,344,717
Other Long-Term Liabilities			216,426				61,761				329				-				278,516
Deferred Income Taxes			278,225				323,829				(1,753)				754,749				1,355,050
Stockholders’ Equity			3,382,965				1,576,886				(17,500)				(1,559,386)				3,382,965
		$	7,585,074			$	2,109,722			$	4,778			$	(804,637)			$	8,894,937

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED MARCH 31, 2011

(in thousands of dollars)

 

		Issuer				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
Revenues
Oil sales		$	260,102			$	54,449			$	17,292			$	-			$	331,843
Gas sales			3,153				93,433				216				-				96,802
Other operating revenues			236				1,433				-				-				1,669
			263,491				149,315				17,508				-				430,314
Costs and Expenses
Production costs			74,989				43,662				3,356				-				122,007
General and administrative			22,704				13,127				192				-				36,023
Depreciation, depletion, amortization and accretion			43,223				58,318				8,215				29,044				138,800
Impairment of oil and gas properties			-				169,994				14,204				(184,198)				-
Other operating income			-				(304)				-				-				(304)
			140,916				284,797				25,967				(155,154)				296,526
Income (Loss) from Operations			122,575				(135,482)				(8,459)				155,154				133,788
Other (Expense) Income
Equity in earnings of subsidiaries			(11,663)				(8)				-				11,671				-
Interest expense			(563)				(31,070)				(771)				-				(32,404)
Loss on mark-to-market derivative contracts			(50,996)				-				-				-				(50,996)
Gain on investment measured at fair value			67,254				-				-				-				67,254
Other income (expense)			470				196				(112)				-				554
Income (Loss) Before Income Taxes			127,077				(166,364)				(9,342)				166,825				118,196
Income tax (expense) benefit			(56,098)				61,996				3,399				(56,514)				(47,217)
Net Income (Loss)		$	70,979			$	(104,368)			$	(5,943)			$	110,311			$	70,979

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME (Unaudited)

THREE MONTHS ENDED MARCH 31, 2010

(in thousands of dollars)

 

		Issuer				Guarantor   Subsidiaries				Non- Guarantor   Subsidiaries				Intercompany   Eliminations				Consolidated
Revenues
Oil sales		$	234,175			$	41,829			$	-			$	-			$	276,004
Gas sales			25,514				82,225				-				-				107,739
Other operating revenues			106				201				-				-				307
			259,795				124,255				-				-				384,050
Costs and Expenses
Production costs			75,460				34,606				-				-				110,066
General and administrative			24,858				12,527				5				-				37,390
Depreciation, depletion, amortization and accretion			59,134				30,067				-				37,603				126,804
Legal recovery			-				(8,423)				-				-				(8,423)
Other operating income			-				(569)				-				-				(569)
			159,452				68,208				5				37,603				265,268
Income (Loss) from Operations			100,343				56,047				(5)				(37,603)				118,782
Other (Expense) Income
Equity in earnings of subsidiaries			(386)				129				-				257				-
Interest expense			(13)				(20,509)				(531)				-				(21,053)
Debt extinguishment costs			(728)				-				-				-				(728)
Gain on mark-to-market derivative contracts			7,856				-				-				-				7,856
Other income			615				594				97				-				1,306
Income (Loss) Before Income Taxes			107,687				36,261				(439)				(37,346)				106,163
Income tax (expense) benefit			(49,159)				(14,494)				198				15,820				(47,635)
Net Income (Loss)		$	58,528			$	21,767			$	(241)			$	(21,526)			$	58,528

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

THREE MONTHS ENDED MARCH 31, 2011

(in thousands of dollars)

 

		Issuer				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)		$	70,979			$	(104,368)			$	(5,943)			$	110,311			$	70,979
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment			43,223				228,312				22,419				(155,154)				138,800
Equity in earnings of subsidiaries			11,663				8				-				(11,671)				-
Deferred income tax expense (benefit)			43,105				(34,868)				(2,457)				41,065				46,845
Loss on mark-to-market derivative contracts			50,996				-				-				-				50,996
Gain on investment measured at fair value			(67,254)				-				-				-				(67,254)
Non-cash compensation			12,204				4,602				-				-				16,806
Other non-cash items			851				-				67				-				918
Change in assets and liabilities from operating activities
Accounts receivable and other assets			8,163				(7,728)				(13,692)				-				(13,257)
Accounts payable and other liabilities			14				2,760				4,941				(2,963)				4,752
Income taxes receivable/payable			40,378				-				-				-				40,378
Net cash provided by operating activities			214,322				88,718				5,335				(18,412)				289,963
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties			(97,511)				(199,444)				(61,517)				-				(358,472)
Acquisition of oil and gas properties			(46)				(14,896)				(9,569)				-				(24,511)
Proceeds from sales of oil and gas properties, net of costs and expenses			11,987				-				-				-				11,987
Derivative settlements			(15,021)				-				-				-				(15,021)
Additions to other property and equipment			(1,226)				(443)				(1,002)				-				(2,671)
Net cash used in investing activities			(101,817)				(214,783)				(72,088)				-				(388,688)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities			1,313,850				-				-				-				1,313,850
Repayments of revolving credit facilities			(1,808,850)				-				-				-				(1,808,850)
Proceeds from issuance of Senior Notes			600,000				-				-				-				600,000
Costs incurred in connection with financing arrangements			(9,069)				-				-				-				(9,069)
Investment in and advances to affiliates			(211,125)				126,065				66,648				18,412				-
Other			4				-				-				-				4
Net cash (used in) provided by financing activities			(115,190)				126,065				66,648				18,412				95,935
Net decrease in cash and cash equivalents			(2,685)				-				(105)				-				(2,790)
Cash and cash equivalents, beginning of period			6,020				8				406				-				6,434
Cash and cash equivalents, end of period		$	3,335			$	8			$	301			$	-			$	3,644

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

THREE MONTHS ENDED MARCH 31, 2010

(in thousands of dollars)

 

		Issuer				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)		$	58,528			$	21,767			$	(241)			$	(21,526)			$	58,528
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion			59,134				30,067				-				37,603				126,804
Equity in earnings of subsidiaries			386				(129)				-				(257)				-
Deferred income tax (benefit) expense			(16,591)				35,645				(198)				24,041				42,897
Debt extinguishment costs			728				-				-				-				728
Gain on mark-to-market derivative contracts			(7,856)				-				-				-				(7,856)
Non-cash compensation			13,225				3,675				-				-				16,900
Other non-cash items			1,367				4				-				-				1,371
Change in assets and liabilities from operating activities
Accounts receivable and other assets			6,582				(6,987)				668				-				263
Accounts payable and other liabilities			(28,335)				(2,921)				(6)				-				(31,262)
Income taxes receivable/payable			13,405				-				-				-				13,405
Net cash provided by operating activities			100,573				81,121				223				39,861				221,778
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties			(123,009)				(143,076)				(930)				-				(267,015)
Acquisition of oil and gas properties			-				51,065				-				-				51,065
Derivative settlements			(9,460)				-				-				-				(9,460)
Additions to other property and equipment			(712)				(1)				(1,424)				-				(2,137)
Net cash used in investing activities			(133,181)				(92,012)				(2,354)				-				(227,547)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities			625,935				-				-				-				625,935
Repayments of revolving credit facilities			(855,935)				-				-				-				(855,935)
Proceeds from issuance of Senior Notes			300,000				-				-				-				300,000
Costs incurred in connection with financing arrangements			(5,344)				-				-				-				(5,344)
Investment in and advances to affiliates			25,312				10,888				3,661				(39,861)				-
Net cash provided by financing activities			89,968				10,888				3,661				(39,861)				64,656
Net increase (decrease) in cash and cash equivalents			57,360				(3)				1,530				-				58,887
Cash and cash equivalents, beginning of period			1,304				11				544				-				1,859
Cash and cash equivalents, end of period		$	58,664			$	8			$	2,074			$	-			$	60,746

 

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

The following information should be read in connection with the information contained in the consolidated financial statements and notes thereto included elsewhere in this report and our Form 10-K for the year ended December 31, 2010.

Company Overview

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

•  Onshore California;

•  Offshore California;

•  the Gulf Coast Region;

•  the Mid-Continent Region; and

•  the Rocky Mountains.

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

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

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

Recent Developments

In response to market conditions related to the Gulf of Mexico drilling moratorium in 2010 and as part of our ongoing portfolio optimization, we engaged Barclays Capital and Jefferies & Company to assist us in evaluating various alternatives with respect to our Gulf of Mexico operations. In December 2010, we completed the divestment of our Gulf of Mexico shallow water shelf properties to McMoRan. We continue to evaluate alternatives to separate our deepwater and onshore businesses, which include separately capitalizing our deepwater business through a joint venture or outside capital, spinning off or divesting these assets.

 

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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 March 31, 2011, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 25%.

Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. If oil and gas prices decline in the future, impairments of our oil and gas properties could occur. Impairment charges required by these rules do not directly impact our cash flows from operating activities.

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

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

Results Overview

For the three months ended March 31, 2011, we reported net income of $71.0 million, or $0.49 per diluted share, compared to net income of $58.5 million, or $0.41 per diluted share, for the three months ended March 31, 2010. The increase primarily reflects higher oil prices and an increase in natural gas sales. Significant transactions which affect comparisons between the periods include the divestment of our Gulf of Mexico shallow water shelf properties to McMoRan, the acquisition of Eagle Ford Shale properties during the fourth quarter 2010 and a gain on investment measured at fair value partially offset by a loss on mark-to-market derivative contracts during 2011.

 

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Results of Operations

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

 

		Three Months Ended   March 31,
		2011				2010
Sales Volumes
Oil and liquids sales (MBbls)			3,966				4,070
Gas (MMcf)
Production			24,230				22,013
Used as fuel			521				478
Sales			23,709				21,535
MBOE
Production			8,004				7,738
Sales			7,918				7,659
Daily Average Volumes
Oil and liquids sales (Bbls)			44,068				45,217
Gas (Mcf)
Production			269,222				244,594
Used as fuel			5,788				5,313
Sales			263,434				239,281
BOE
Production			88,938				85,983
Sales			87,974				85,097
Unit Economics (in dollars)
Average NYMEX Prices
Oil		$	94.60			$	78.88
Gas			4.09				5.27
Average Realized Sales Price
Before Derivative Transactions
Oil (per Bbl)		$	83.67			$	67.82
Gas (per Mcf)			4.08				5.00
Per BOE			54.14				50.11
Costs and Expenses per BOE
Production costs
Lease operating expenses		$	9.12			$	8.16
Steam gas costs			1.99				2.57
Electricity			1.23				1.31
Production and ad valorem taxes			1.46				1.10
Gathering and transportation			1.61				1.23
DD&A (oil and gas properties)			16.28				15.33

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

 

		Three Months Ended March 31,
		2011				2010
Oil derivatives		$	(15,641)			$	(14,549)
Natural gas derivatives			620				5,089
		$	(15,021)			$	(9,460)

 

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Comparison of Three Months Ended March 31, 2011 to Three Months Ended March 31, 2010

Oil and gas revenues. Oil and gas revenues increased $44.9 million, to $428.6 million for 2011 from $383.7 million for 2010 primarily due to higher average realized oil prices partially offset by lower average realized gas prices.

Oil revenues increased $55.8 million to $331.8 million for 2011 from $276.0 million for 2010 reflecting higher average realized prices ($64.5 million). Our average realized price for oil increased $15.85 to $83.67 per Bbl for 2011 from $67.82 per Bbl for 2010.

Gas revenues decreased $10.9 million to $96.8 million in 2011 from $107.7 million in 2010 reflecting lower average realized prices ($19.8 million), partially offset by higher sales volumes ($8.9 million). Our average realized price for gas was $4.08 per Mcf in 2011 compared to $5.00 per Mcf in 2010. Gas sales volumes increased 24.1 MMcf per day to 263.4 MMcf per day in 2011 from 239.3 MMcf per day in 2010, primarily reflecting increased production from our Haynesville Shale properties partially offset by our Gulf of Mexico shallow water properties divested in December 2010. Excluding the impact of our divestments in 2010, production increased 73.6 MMcf per day in 2011.

Lease operating expenses. Lease operating expenses increased $9.8 million, to $72.3 million in 2011 from $62.5 million in 2010, reflecting scheduled repair and maintenance expenditures primarily at our California properties and an increased number of producing wells at our Eagle Ford Shale and Panhandle properties.

Steam gas costs. Steam gas costs decreased $3.9 million to $15.8 million in 2011 from $19.7 million in 2010, primarily reflecting lower cost of gas used in steam generation partially offset by higher volumes. In 2011, we burned approximately 4.1 Bcf of natural gas at a cost of approximately $3.88 per MMBtu compared to 3.7 Bcf at a cost of approximately $5.35 per MMBtu in 2010.

Production and ad valorem taxes. Production and ad valorem taxes increased $3.1 million, to $11.5 million in 2011 from $8.4 million in 2010, reflecting higher ad valorem taxes due to an increase in the number of wells drilled at our Haynesville Shale properties and higher production taxes due to increased production primarily from our Panhandle properties.

Gathering and transportation expenses. Gathering and transportation expenses increased $3.3 million, to $12.7 million in 2011 from $9.4 million in 2010, primarily reflecting an increase in production from our Haynesville Shale properties.

General and administrative expense. G&A expense decreased $1.4 million, to $36.0 million in 2011 from $37.4 million in 2010 primarily due to a decrease in stock-based compensation expense.

Depreciation, depletion and amortization. DD&A expense increased $12.1 million, to $134.5 million in 2011 from $122.4 million in 2010. The increase is attributable to our oil and gas depletion, primarily due to a higher per unit rate ($7.4 million) and increased production ($4.3 million). Our oil and gas unit of production rate increased to $16.28 per BOE in 2011 compared to $15.33 per BOE in 2010.

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

Interest expense. Interest expense increased $11.3 million, to $32.4 million in 2011 from $21.1 million in 2010, primarily due to greater average debt outstanding and lower capitalized interest partially offset by lower average interest rates. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization but in the process of development. We capitalized $31.1 million and $34.3 million of interest in 2011 and 2010, respectively.

 

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(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 or receiving a payment from the counterparty.

We recognized a $51.0 million loss in the first quarter of 2011 related to our mark-to-market derivative contracts, which was primarily associated with a decrease in the fair value of our 2011 and 2012 crude oil puts and our 2011 crude oil collars due to higher crude oil forward prices. In the first quarter of 2010, we recognized a $7.9 million gain related to mark-to-market derivative contracts.

Gain on investment measured at fair value. At March 31, 2011, we owned 51.0 million shares of McMoRan common stock. We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as gain on investment measured at fair value in our income statement.

We recognized a $67.3 million gain in the first quarter of 2011 related to our McMoRan investment, which was primarily associated with (i) a lower discount on the marketability of the shares due to a reduced term on the restrictions and lower volatility of the instrument and (ii) an increase in McMoRan’s stock price.

Income taxes. For the first quarter of 2011, income tax expense was approximately 40% of pre-tax income. The variance between this effective tax rate and the 35% federal statutory rate results from the tax effects of estimated annual permanent differences, including (i) expenses that are not deductible because of IRS limitations and (ii) state income taxes.

For the first quarter of 2010, income tax expense was approximately 45% of pre-tax income. The effective tax rate of 45% for the quarter resulted primarily from expenses that are not deductible because of IRS limitations, state income taxes and adjustments to deferred taxes for differences in the reporting of stock-based compensation expenses for financial statement and income tax reporting purposes.

Liquidity and Capital Resources

Our liquidity may be affected by declines in oil and gas prices, an inability to access the capital and credit markets and the success of our commodity price risk management activities, which may subject us to the credit risk of the counterparties to these agreements. These situations may arise due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions that cause substantial or extended declines in oil and gas prices. Volatility and disruption in the financial and credit markets may adversely affect the financial condition of lenders in our senior revolving credit facility, the counterparties to our commodity price risk management agreements, our insurers and our oil and natural gas purchasers. These market conditions may adversely affect our liquidity by limiting our ability to access the capital and credit markets.

Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity. At March 31, 2011, we had approximately $1.3 billion available for future secured borrowings under our senior revolving credit facility, which had an aggregate borrowing base of $1.45 billion. 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. In April 2011, our borrowing base was increased to $1.8 billion from $1.45 billion. The commitments remained unchanged at $1.4 billion. See Financing Activities.

 

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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 March 31, 2011, the commitments are from a diverse syndicate of 21 lenders and no single lender’s commitment represented more than 7% of the total commitments.

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

We have made and will continue to make substantial capital expenditures for the acquisition, development, exploration and production of oil and gas. Our 2011 capital budget is approximately $1.2 billion, including capitalized interest and general and administrative expenses. We intend to fund our 2011 capital budget from internally generated funds and borrowings under our senior revolving credit facility. In addition, we could curtail the portion of our capital expenditures that is discretionary if our cash flows decline from expected levels.

We believe that we have sufficient liquidity through our forecasted cash flow from operations and borrowing capacity under our senior revolving credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies and anticipated capital expenditures. We have no near-term debt maturities. Our senior revolving credit facility matures on May 4, 2016 and the next maturity of our senior notes will occur on June 15, 2015.

Working Capital

At March 31, 2011, we had a working capital deficit of approximately $215.7 million. We generally have a working capital deficit because we use excess cash to pay down borrowings under our senior revolving credit facility. Our working capital fluctuates for various reasons, including the fair value of our commodity derivative instruments and stock appreciation rights.

Financing Activities

Senior Revolving Credit Facility. In March 2011, our borrowing base was adjusted from $1.6 billion to $1.45 billion in recognition of our issuance of the 6⁵/₈% Senior Notes. The aggregate commitments of the lenders under our senior revolving credit facility are $1.4 billion. At March 31, 2011, our availability for future secured borrowings under our senior revolving credit facility was approximately $1.3 billion and we had $125 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 quarter ended March 31, 2011 was $634.8 million. In April 2011, our borrowing base was increased to $1.8 billion. 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 relevant factors. 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.

Amounts borrowed under our senior revolving credit facility, as amended, bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; (ii) a variable amount ranging from 0.50% to 1.50% plus the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus  ¹/2 of 1%, and (3) the adjusted LIBOR plus 1%; or (iii) the overnight federal funds rate plus an additional variable amount ranging from 1.50% to 2.50% for swingline loans. The additional variable amount of interest payable on outstanding borrowings is based on the utilization rate as a percentage of the total amount of funds borrowed under our senior revolving credit facility to the borrowing base. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% for 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.

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, 2011, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding fourteen days and all amounts outstanding are due and payable no later than June 1, 2011. 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 March 31, 2011. The daily average outstanding balance for the quarter ended March 31, 2011 was $53.9 million.

In March 2011, we issued $600 million of 6⁵/₈% Senior Notes at par. We received approximately $590 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes. We may redeem all or part of the 6⁵/₈% Senior Notes on or after May 1, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to May 1, 2014 we may, at our option, redeem up to 35% of the 6⁵/₈% Senior Notes with the proceeds of certain equity offerings. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 6⁵/₈% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The 6⁵/₈% Senior Notes are general unsecured senior obligations. They are jointly and severally guaranteed on a full and unconditional basis by certain of our existing domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. These 6⁵/₈% 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 6⁵/₈% Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our senior revolving credit facility, to the extent of our assets constituting collateral securing that indebtedness; and effectively subordinate to all existing and future indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our non-guarantor subsidiaries.

 

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Cash Flows

 

		Three Months Ended March 31,
		2011				2010
		(in millions)
Cash provided by (used in)
Operating activities		$	290.0			$	221.8
Investing activities			(388.7)				(227.5)
Financing activities			95.9				64.7

Net cash provided by operating activities was $290.0 million for the first quarter of 2011 compared to $221.8 million in the first quarter of 2010. The increase primarily reflects higher operating income in 2011 as a result of higher average realized oil prices and a $40.4 million refund of income tax paid in prior years.

Net cash used in investing activities of $388.7 million in 2011 primarily reflects additions to oil and gas properties of $358.5 million. Net cash used in investing activities of $227.5 million in 2010 primarily reflects additions to oil and gas properties of $267.0 million, offset by a $51.1 million cash inflow associated with an adjustment to the final settlement of the $1.1 billion payment to Chesapeake Energy Corporation in September 2009 related to the prepayment of the Haynesville drilling carry.

Net cash provided by financing activities of $95.9 million in 2011 primarily reflects proceeds from the $600 million offering of 6⁵/₈% Senior Notes partially offset by the net reduction in borrowings under our senior revolving credit facility of $495 million. Net cash provided by financing activities of $64.7 million in 2010 primarily reflects proceeds from the $300 million offering of 7⁵/₈% Senior Notes due 2020 partially offset by the net reduction in borrowings under our senior revolving credit facility of $230 million.

Stock Repurchase Program

Our board of directors has authorized the repurchase of shares of our common stock. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. We currently have $695.8 million in authorized repurchases remaining under the program.

Critical Accounting Policies and Estimates

Management makes many estimates and assumptions in the application of generally accepted accounting principles that may have a material impact on our consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on information available prior to the issuance of the financial statements. Changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates. Critical accounting policies related to oil and gas reserves, impairments of oil and gas properties, oil and natural gas properties not subject to amortization, DD&A, commodity pricing and risk management activities, stock-based compensation, allocation of purchase price in business combinations, goodwill and income taxes are discussed in our Annual Report on Form 10-K for the year ended December 31, 2010.

 

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Recent Accounting Pronouncements

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

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

 

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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;

 

•

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

 

•

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

 

•

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

 

•

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

 

•

the success of our derivative activities;

 

•

the success of our risk management activities;

 

•

the effects of competition;

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

the value and completion of the separation of our Gulf of Mexico deepwater assets;

 

•

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

 

•

the ability and willingness of our current or potential counterparties to fulfill their obligations to us or to enter into transactions with us in the future; and

 

•

general economic, market, industry or business conditions.

All forward-looking statements in this report are made as of the date hereof, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report and our other filings with the SEC. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. We do not intend to update these forward-looking statements and information except as required by law. See our filings with the SEC, including Item 1A – Risk Factors and Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates in our Annual Report on Form 10-K for the year ended December 31, 2010.

 

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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.

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

As of March 31, 2011, we had the following outstanding commodity derivative contracts, all of which settle monthly:

 

Period		Instrument Type		Daily Volumes		Average Price (1)		Average Deferred Premium		Index
Sales of Crude Oil Production
2011
Apr - Dec		Put options (2)		31,000 Bbls		$80.00 Floor with a $60.00 Limit		$5.023 per Bbl		WTI
Apr - Dec		Three-way collars (3)		9,000 Bbls		$80.00 Floor with a $60.00 Limit		$1.00 per Bbl		WTI
						$110.00 Ceiling
2012
Jan - Dec		Put options (2)		40,000 Bbls		$80.00 Floor with a $60.00 Limit		$6.087 per Bbl		WTI
Sales of Natural Gas Production
2011
Apr - Dec		Three-way collars (4)		200,000 MMBtu		$4.00 Floor with a $3.00 Limit		-		Henry Hub
						$4.92 Ceiling
2012
Jan - Dec		Put options (5)		160,000 MMBtu		$4.30 Floor with a $3.00 Limit		$0.294 per MMBtu		Henry Hub

 

(1)

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

(2)

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

(3)

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

(4)

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

(5)

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

 

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The fair value of outstanding crude oil and natural gas commodity derivative instruments at March 31, 2011 and the change in fair value that would be expected from a 10% price increase or decrease is shown below (in millions):

 

						Effect of 10%
		Fair Value   Asset				Price    Increase				Price   Decrease
Crude oil put options		$	50			$	(18)			$	29
Crude oil collars			(15)				(17)				11
Natural gas collars			(7)				(14)				13
Natural gas put options			13				(5)				8
		$	41			$	(54)			$	61

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

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

Equity Price Risk

We are exposed to market risk because we own an equity investment in McMoRan common stock. See Note 4 – Investment and Note 5 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our equity investment. At March 31, 2011, the investment, comprised of 51.0 million shares of McMoRan common stock, was valued at approximately $731.6 million. A 10% change in the underlying equity market price per share would result in a $73.2 million increase or decrease in the fair value of our investment, recognized in the income statement.

ITEM 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer believe that the disclosure controls and procedures as of March 31, 2011 were effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2011 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 6. Exhibits

 

Exhibit No.		Description
4.1		Twelfth Supplemental Indenture, dated as of March 29, 2011, to the Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the subsidiary guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 29, 2011, File No. 1-31470).
31.1*		Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Chief Executive Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*		Chief Financial Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**		XBRL Instance Document
101.SCH**		XBRL Taxonomy Extension Schema Document
101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**		XBRL Taxonomy Extension Label Linkbase Document
101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document

 

*	Filed herewith

**	Furnished herewith

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

 

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SIGNATURES

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

 

		PLAINS EXPLORATION & PRODUCTION COMPANY
Date: May 5, 2011
		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
4.1		Twelfth Supplemental Indenture, dated as of March 29, 2011, to the Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the subsidiary guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 29, 2011, File No. 1-31470).
31.1*		Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Chief Executive Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*		Chief Financial Officer Certification Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**		XBRL Instance Document
101.SCH**		XBRL Taxonomy Extension Schema Document
101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**		XBRL Taxonomy Extension Label Linkbase Document
101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document

 

*	Filed herewith

**	Furnished herewith

 

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