PXP Reports Substantially Higher Quarterly Earnings of $493 Million or $4.50 Per Diluted Share
HOUSTON, Nov. 6 /PRNewswire-FirstCall/ — Plains Exploration & Production Company (“PXP” or the “Company”) today announced financial and operating results for the third quarter 2008 and filed full-year 2009 operating guidance with the SEC in a Form 8-K.
Financial Highlights: — Net income increased to $493.1 million in the third quarter 2008 from $32.9 million in the third quarter 2007. Included in third quarter 2008 earnings is an after-tax gain on mark-to-market derivative contracts of $282.4 million. — PXP set its 2009 capital budget at $1.15 billion and lowered 2008 estimated operational capital expenditures from $1.5 billion to $1.2 billion due to lower estimated acreage costs and reductions in development costs attributed to the Permian and Piceance asset sale. — Strong liquidity is maintained with no significant debt maturities for approximately four years; and pro forma for the Permian and Piceance Basin properties sale, PXP’s liquidity improves to approximately $1.3 billion. In addition, PXP is supported by its positive derivative position which as of October 31, 2008 had a net value of approximately $930 million. Operational Highlights: Production — Oil and gas sales volumes averaged 92.4 thousand barrels of oil equivalent per day (BOEPD) in the third quarter 2008 compared to 57.1 thousand BOEPD in the third quarter 2007. — Hurricane downtime reduced third quarter 2008 volumes by approximately 170 thousand BOE. All production impacted by the hurricanes has been restored. Drilling Operations — Flatrock development continues delivering positive results with five successful wells to date and three of these wells currently producing approximately 37 million cubic feet equivalent per day (MMCFED) net to PXP. — Flatrock No. 4 well production test, through perforations in the primary Rob-L section, indicated a gross flow rate of approximately 109 MMCFD, 2,500 barrels per day of condensate and zero barrels of water, approximately 124 MMCFED (27 MMCFED net to PXP). This is in the same Rob-L sand which continues to produce at approximately 100 MMCFED at the Flatrock No. 2 well. — Flatrock No. 5 has encountered 90 net feet of pay as indicated by wireline logs and is currently drilling below 15,000 feet to a proposed total depth of 18,400 feet. — Flatrock No. 6 commenced drilling in late October 2008. — Additional multi-hundred BCFE Flatrock step-out prospects either currently drilling or preparing to spud are outlined below: — Tom Sauk exploratory well, operated by McMoRan and located on Louisiana State Lease 340, commenced drilling in August 2008 and is drilling below 12,500 feet towards a proposed total depth of 19,000 feet to evaluate potential Operc and Gyro sands in the Middle and Lower Miocene. PXP holds a 24.4% working interest. — Gladstone East exploration prospect, operated by McMoRan and located on Louisiana State Lease 340, is expected to commence drilling in November 2008 and carry over into 2009. This prospect, located in the Flatrock area, has multiple targets in the Rob-L and Operc sands in the Middle Miocene. PXP holds a 30% working interest. — Ammazzo exploration prospect, operated by McMoRan and located on South Marsh Island Block 251, is expected to commence drilling in November 2008 and carry over into 2009. The prospect, also located in the Flatrock area, has multiple targets in the Rob-L, Operc and Gyro sands in the Middle and Lower Miocene. PXP holds a 28% working interest. — Plans are underway to complete and test the South Timbalier Block 168 ultra-deep exploratory well operated by McMoRan. The well will be temporarily abandoned waiting completion. As previously reported, the well was drilled to a total depth of 32,997 feet and logs indicated four potential hydrocarbon bearing zones. PXP holds a 35% working interest. — Friesian #2 well, operated by PXP and located on Green Canyon Block 643, is currently drilling below 24,000 feet to a proposed total depth of 28,000 feet. Drilling results are expected before year end. — Drilling operations in the Haynesville Shale now include 14 rigs, up from six in August, with an average of approximately 26 rigs expected in 2009. For 2009, PXP allocated 40% of its 2009 capital budget, or approximately $460 million, to Haynesville activity pursuant to Chesapeake’s, our operator’s, 2009 operating plan. Drilling operations for our Haynesville Shale Joint Venture began in July 2008 and inaugural production commenced during the third quarter. Currently four wells are producing 36 MMCFED gross, 5 MMCFED net to PXP. With over 7,000 potential well locations, this asset area is expected to be a significant driver of future production and reserve growth. PXP holds a 20% interest in Chesapeake’s over 550,000 net acre leasehold position. — Drilling operations in the South Texas and the Texas Panhandle areas continue to yield positive results. Production combined from these areas increased approximately 40% from January to September 2008. In South Texas, drilling has focused on the Los Mogotes, Lopez Ranch and Mills Bennett Fields and the area was producing 11,700 net BOEPD at the end of the third quarter. In the Texas Panhandle, production was approximately 8,100 net BOEPD at the end of the quarter with ongoing drilling successes in the Courson Ranch, Wheeler and Marvin Lake Fields. These asset areas provide multi-year drilling inventories supporting further reserve and production growth. — Los Angeles County Board of Supervisors recently passed enhanced environmental and safety standards supporting continued development of the Inglewood Field in the Baldwin Hills area of Los Angeles, California. This approval gives PXP the ability to drill up to 600 new wells at the Inglewood Field. — The County of San Luis Obispo California recently approved a permit to construct a water reclamation and treatment facility to improve operating efficiencies for oil recovery activities in PXP’s Arroyo Grande Field. The new facility will accelerate field development and production growth at the Arroyo Grande Field, which represents a significant development for our onshore California production operations. Construction is expected to begin by year-end 2008 followed by drilling and steaming operations to enhance the present production rate of 1,300 BOEPD with a 17% compound average growth rate over the next 10 years. — T-Ridge received final approval from the County of Santa Barbara California Board of Supervisors on October 7, 2008. This approval is an important milestone for this significant project. PXP is working to obtain approvals from the California State Lands Commission, the California Coastal Commission, and the federal Minerals Management Service, which would allow drilling to begin as early as the first quarter 2009. Divestiture — PXP agreed on September 24, 2008 to divest its oil and gas properties located in the Permian and the Piceance Basins for $1.25 billion to Occidental Petroleum Corporation. This transaction is expected to close on December 1, 2008. THREE MONTHS ENDED SEPTEMBER 30
PXP reported third quarter 2008 net income of $493.1 million, or $4.50 per diluted share, on revenues of $719.5 million, an increase from third quarter 2007 net income of $32.9 million, or $0.45 per diluted share, on revenues of $299.0 million. Higher revenues during the third quarter of 2008 were primarily due to a 62% increase in sales volumes and a $26.73 per barrel of oil equivalent (BOE) increase in realized prices. Included in third quarter 2008 earnings is an after-tax gain on mark-to-market derivative contracts of $282.4 million.
Sales volumes increased to 92.4 thousand BOEPD during the third quarter 2008 from 57.1 thousand BOEPD in the third quarter 2007 reflecting the acquisitions and divestments in 2007 and first half of 2008, as well as production from the Flatrock project. Third quarter 2008 sales volumes reflect the impacts of shut-in production associated with the recent Gulf of Mexico hurricanes. Hurricane downtime reduced third quarter volumes by approximately 170 thousand BOE. All production impacted by the hurricanes has been restored.
Total production costs per BOE were slightly higher during third quarter 2008 compared to the prior year period due primarily to increased per unit production and ad valorem taxes associated with the properties acquired in 2007. Total general and administrative costs per BOE were lower due primarily to higher sales volumes.
Operating cash flow, a non-GAAP measure, was $423.7 million in the third quarter 2008 compared to $146.0 million in the prior year period. The increase was due primarily to higher sales volumes and stronger commodity prices. An explanation and reconciliation of non-GAAP financial measures is included at the end of this release.
NINE MONTHS ENDED SEPTEMBER 30
Net income for the first nine months of 2008 was $859.6 million, or $7.72 per diluted share, on revenues of $2.1 billion, a significant increase from net income of $78.7 million, or $1.07 per diluted share, on revenues of $779.2 million for the same period a year ago. Higher revenues during the first nine months of 2008 were primarily due to a 70% increase in sales volumes and a $29.32 per BOE increase in realized prices. Included in the nine months ended September 30, 2008 is a $243.9 million after-tax gain on mark-to-market derivative contracts.
Sales volumes for the first nine months of 2008 increased to 91.9 thousand BOEPD from 54.2 thousand BOEPD for the same period in 2007. Higher year-over- year sales volumes primarily reflect the 2007 acquisitions.
Total production costs per BOE were slightly higher for the first nine months of 2008 compared to the same period in 2007. Lower per unit lease operating, steam gas and electricity costs due to increased sales volumes were offset by higher per unit gathering and transportation and production and ad valorem taxes associated with the properties acquired in 2007. Total general and administrative costs per BOE were lower due to higher sales volumes.
Operating cash flow for the first nine months of 2008, a non-GAAP measure, increased to $1.2 billion from $351.5 million reported in the prior year period. The increase was due primarily to higher sales volumes and stronger commodity prices.
Oil and gas capital expenditures, excluding acquisitions, were $806.4 million for the first nine months of 2008 compared to $573.0 million for the prior year period.
FULL-YEAR 2008 GUIDANCE UPDATE
Due to the pending asset sale, higher service costs and higher natural gas prices, we are revising estimates on certain items of our previously issued full-year 2008 guidance. Production is expected to average about 92 thousand BOEPD for 2008. Lease operating expenses per unit are higher than previously anticipated due primarily to increased well work and stimulation activity and higher service costs accompanied by higher water disposal costs associated with the Pogo and Piceance assets. Lease operating expenses per unit are now estimated to approximate $9.50 per BOE. Steam gas costs per unit are higher than previously anticipated due to significantly higher average natural gas prices and slightly higher volumes of natural gas used in steam generation. Steam gas costs per unit are now estimated to approximate $4.00 per BOE.
On September 30, 2008, the company had approximately $665 million available under its revolving credit facility, which had commitments of $2.7 billion. The commitments are from a diverse syndicate of 23 lenders with no single lender’s commitment representing more than 9% of the total.
Due to the pending $1.25 billion asset sale to Occidental, PXP’s revolving credit facility commitments will be voluntarily reduced from $2.7 billion to $2.3 billion upon closing of the transaction. Pro forma for the asset sale, PXP’s liquidity increases to approximately $1.3 billion and its borrowing base is established at $2.7 billion, well in excess of its commitments.
PXP’s liquidity is further supported by no near-term debt maturities and a material positive derivative position. The senior revolving credit facility matures November 6, 2012 and the next maturity of senior unsecured notes occurs on June 15, 2015. In addition, PXP’s positive derivative position as of October 31, 2008 had a net value of approximately $930 million.
PXP’s derivatives position remains unchanged. On average 80% of our 2009 and 2010 estimated oil production is protected with floors above $100 and approximately 80% of our estimated natural gas production through year-end 2009 is protected with either physical purchases used in our operations or $10 by $20 collars. On September 30, 2008 PXP’s mark-to-market position had a net value of approximately $338 million. On October 31, 2008 the mark-to-market position had a net value of approximately $930 million. A table summarizing PXP’s open commodity derivative positions as of October 1, 2008 is included at the end of this release.
2009 CAPITAL BUDGET
PXP’s Board of Directors approved a $1.15 billion 2009 capital budget. Approximately 50% of the capital investment is allocated to production and development activities, 40% to the Haynesville and 10% for exploration projects. PXP intends to fund its 2009 capital budget from internally generated funds and has flexibility to adjust spending as market conditions warrant.
The capital plan supports PXP’s growth initiatives by funding drilling programs in each of its key asset areas. Development activities primarily focus on the large, high-free cash flow California oil business and on the Haynesville, California, Texas Panhandle, South Texas and Gulf of Mexico growth areas. Exploration spending funds a number of high-potential projects in the Gulf of Mexico, onshore Gulf Coast and Vietnam asset areas.
Gulf of Mexico exploration projects include the Blackbeard East prospect located in South Timbalier Block 144 and the previously mentioned Ammazzo and Gladstone East prospects.
THIRD QUARTER CONFERENCE CALL
PXP plans to host its quarterly conference call tomorrow, November 7, 2008, at 8:00 a.m. Central time. Investors wishing to participate in the conference call may dial 1-800-567-9836 or 1-973-935-8460. The replay will be available through November 14, 2008 and can be accessed by dialing 1-800-642- 1687 or 1-706-645-9291. Conference call and replay ID: 69777216. A short slide presentation will be available in the Investor Information section of PXP’s website, http://www.pxp.com/.
PXP is an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploring and producing oil and gas in California, Texas, Louisiana and the Gulf of Mexico. PXP is headquartered in Houston, Texas.
ADDITIONAL INFORMATION & FORWARD LOOKING STATEMENTS
This press release contains forward-looking information regarding PXP that is intended to be covered by the safe harbor “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995. All statements included in this press release that address activities, events or developments that PXP expects, believes or anticipates will or may occur in the future are forward-looking statements. These include statements regarding:
* completion of proposed transaction, * reserve and production estimates, * oil and gas prices, * the impact of derivative positions, * production expense estimates, * cash flow estimates, * future financial performance, * capital and credit market conditions, * planned capital expenditures, and * other matters that are discussed in PXP’s filings with the SEC.
These statements are based on our current expectations and projections about future events and involve known and unknown risks, uncertainties, and other factors that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Please refer to our filings with the SEC, including our Form 10-K for the year ended December 31, 2007, for a discussion of these risks.
All forward-looking statements in this report are made as of the date hereof, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report and our other filings with the SEC. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. Except for any obligation to disclose material information under the Federal securities laws, we do not intend to update these forward-looking statements and information.
Plains Exploration & Production Company Consolidated Statements of Income (Unaudited) (amounts in thousands, except per share data) Three Months Ended Nine Months Ended September 30, September 30, 2008 2007 2008 2007 Revenues Oil sales $528,787 $276,096 $1,531,138 $713,197 Gas sales 181,971 22,696 528,374 63,441 Other operating revenues 8,779 177 15,805 2,571 719,537 298,969 2,075,317 779,209 Costs and Expenses Production costs Lease operating expenses 76,943 52,696 236,699 147,471 Steam gas costs 37,418 22,349 110,175 76,630 Electricity 14,367 11,197 36,665 29,464 Production and ad valorem taxes 27,348 5,118 77,757 15,419 Gathering and transportation expenses 4,405 3,026 15,356 4,432 General and administrative 29,374 22,007 114,505 74,417 Depreciation, depletion and amortization 139,956 69,731 411,558 180,932 Accretion 3,258 2,297 9,868 6,832 333,069 188,421 1,012,583 535,597 Income from Operations 386,468 110,548 1,062,734 243,612 Other Income (Expense) Gain on sale of assets – – 34,658 – Interest expense (32,994) (18,165) (87,114) (35,223) Debt extinguishment costs (3,138) – (13,401) – Gain (loss) on mark-to-market derivative contracts 451,083 (39,155) 390,175 (75,582) Other income (expense) (13,842) (372) (12,181) 952 Income Before Income Taxes 787,577 52,856 1,374,871 133,759 Income tax (expense) benefit Current (210,023) 2,183 (312,276) 2,183 Deferred (84,409) (22,179) (203,031) (57,194) Net Income $493,145 $32,860 $859,564 $78,748 Earnings per share Basic $4.58 $0.45 $7.87 $1.09 Diluted $4.50 $0.45 $7.72 $1.07 Weighted Average Shares Outstanding Basic 107,725 72,859 109,195 72,499 Diluted 109,617 73,811 111,297 73,526 Plains Exploration & Production Company Operating Data (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, 2008 2007 2008 2007 Daily Average Volumes Oil and liquids sales (Bbls) 55,803 47,482 56,199 47,233 Gas (Mcf) Production 225,232 63,768 220,145 48,108 Used as fuel 5,691 6,096 6,053 6,313 Sales 219,541 57,672 214,092 41,795 BOE Production 93,342 58,110 92,890 55,251 Sales 92,393 57,094 91,881 54,199 Unit Economics (in dollars) Average NYMEX Prices Oil $118.22 $75.15 $113.52 $66.19 Gas 10.28 6.18 9.76 6.84 Average Realized Sales Price Before Derivative Transactions Oil (per Bbl) $103.00 $63.19 $99.43 $55.31 Gas (per Mcf) 9.01 4.28 9.00 5.56 Per BOE 83.62 56.89 81.81 52.49 Cash Margin per BOE (1) Oil and gas revenues $83.62 $56.89 $81.81 $52.49 Costs and expenses Lease operating expenses $(9.06) $(10.04) $(9.40) $(9.96) Steam gas costs (4.40) (4.26) (4.38) (5.18) Electricity (1.69) (2.13) (1.46) (1.99) Production and ad valorem taxes (3.22) (0.97) (3.09) (1.04) Gathering and transportation (0.52) (0.58) (0.61) (0.30) Gross margin before DD&A (GAAP) 64.73 38.91 62.87 34.02 Cash derivative settlements (1.81) (4.88) (2.17) (5.10) Cash margin (Non-GAAP) $62.92 $34.03 $60.70 $28.92 (1) Cash margin (a non-GAAP measure) is calculated by adjusting gross margin before DD&A (a GAAP measure) to deduct cash derivative settlements. Management believes this presentation may be helpful to investors as it represents the cash generated by our oil and gas production that is available for, among other things, capital expenditures and debt service. PXP management uses this information to analyze operating trends and for comparative purposes within the industry. This measure is not intended to replace the GAAP statistic but to provide additional information that may be helpful in evaluating the Company’s operational trends and performance. Plains Exploration & Production Company Consolidated Balance Sheets (in thousands of dollars) September 30, December 31, 2008 2007 ASSETS (Unaudited) Current Assets Cash and cash equivalents $2,427 $25,446 Restricted cash – 59,092 Accounts receivable 362,015 304,972 Commodity derivative contracts 79,236 2,186 Inventories 29,643 18,394 Deferred income taxes 19,474 229,893 Other current assets 12,240 34,937 505,035 674,920 Property and Equipment, at cost Oil and natural gas properties – full cost method Subject to amortization 7,328,579 7,340,238 Not subject to amortization 3,147,345 1,951,783 Other property and equipment 117,946 85,928 10,593,870 9,377,949 Less allowance for depreciation, depletion and amortization (1,404,010) (1,000,722) 9,189,860 8,377,227 Goodwill 535,280 536,822 Commodity Derivative Contracts 293,439 – Other Assets 112,240 104,382 $10,635,854 $9,693,351 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts payable $381,603 $319,583 Commodity derivative contracts 30,262 79,938 Royalties and revenues payable 145,411 132,919 Stock appreciation rights 5,116 63,106 Interest payable 32,696 25,330 Income taxes payable 194,965 3,492 Accrued merger expenses 964 77,980 Other current liabilities 133,524 115,698 924,541 818,046 Long-Term Debt Senior revolving credit facility 2,034,131 2,205,000 Senior notes 1,500,000 1,100,000 3,534,131 3,305,000 Other Long-Term Liabilities Asset retirement obligation 183,197 184,080 Other 125,374 88,547 308,571 272,627 Deferred Income Taxes 1,931,823 1,959,431 Stockholders’ Equity Common stock 1,128 1,128 Additional paid-in capital 2,729,070 2,711,617 Retained earnings 1,483,557 623,993 Accumulated other comprehensive income 1,496 1,566 Treasury stock (278,463) (57) 3,936,788 3,338,247 $10,635,854 $9,693,351 Plains Exploration & Production Company Consolidated Statements of Cash Flows (Unaudited) (in thousands of dollars) Three Months Ended Nine Months Ended September 30, September 30, 2008 2007 2008 2007 CASH FLOWS FROM OPERATING ACTIVITIES Net income $493,145 $32,860 $859,564 $78,748 Items not affecting cash flows from operating activities Gain on sale of assets – – (34,658) – Depreciation, depletion, amortization and accretion 143,214 72,028 421,426 187,764 Deferred income taxes 84,409 22,179 203,031 57,194 Debt extinguishment costs 3,138 – 13,401 – (Gain) loss on commodity derivative contracts (451,083) 39,155 (390,175) 75,582 Noncash compensation (1,520) 5,120 38,931 26,741 Other noncash items 1,344 251 4,230 220 Change in assets and liabilities from operating activities 264,930 (27,082) 31,189 (140,488) Net cash provided by operating activities 537,577 144,511 1,146,939 285,761 CASH FLOWS FROM INVESTING ACTIVITIES Additions to oil and gas properties (247,082) (218,132) (688,205) (476,314) Acquisition of oil and gas properties (1,681,676) (1,532) (2,012,969) (975,407) Acquisition of Pogo Producing Company (1,801) – (76,645) – Derivative settlements (6,619) (25,616) (36,212) (74,759) Proceeds from property sales, net of costs and expenses 18,278 – 1,736,059 – Decrease in restricted cash – – 59,092 – Additions to other property and equipment (7,005) (4,424) (34,448) (28,588) Other, net (442) (7,438) (1,671) (10,869) Net cash used in investing activities (1,926,347) (257,142) (1,054,999) (1,565,937) CASH FLOWS FROM FINANCING ACTIVITIES Revolving credit facilities Borrowings 7,263,596 533,315 11,501,352 1,989,565 Repayments (5,840,465) (428,315) (11,672,221) (1,745,065) Proceeds from issuance of long-term debt – – 400,000 1,100,000 Costs incurred in connection with financing arrangements (19,384) (265) (25,448) (18,182) Derivative settlements (11,009) – (24,097) – Purchase of treasury stock – – (304,192) (47,485) Other (4,035) 1,700 9,647 5,041 Net cash provided by (used in) financing activities 1,388,703 106,435 (114,959) 1,283,874 Net (decrease) increase in cash and cash equivalents (67) (6,196) (23,019) 3,698 Cash and cash equivalents, beginning of period 2,494 10,793 25,446 899 Cash and cash equivalents, end of period $2,427 $4,597 $2,427 $4,597 Plains Exploration & Production Company Summary of Open Derivative Positions at October 1, 2008 Instrument Daily Period Type Volumes Average Price (1) Index Sales of Crude Oil Production 2008 Oct – Dec Put options 42,000 Bbls $55.00 Strike price WTI Oct – Dec Collar 2,500 Bbls $60.00 Floor – $80.13 WTI Ceiling 2009 Jan – Dec Put options 32,500 Bbls $55.00 Strike price WTI Jan – Dec Put options 40,000 Bbls $106.16 Strike price WTI 2010 Jan – Dec Put options 40,000 Bbls $111.49 Strike price WTI Sales of Natural Gas Production 2008 Oct – Dec Collar 15,000 MMBtu $8.00 Floor – $12.11 Henry Hub Ceiling Oct – Dec Collar 150,000 MMBtu $10.00 Floor – $20.00 Henry Hub Ceiling 2009 Jan – Dec Collar 150,000 MMBtu $10.00 Floor – $20.00 Henry Hub Ceiling (1) The average strike prices do not reflect the cost to purchase the put options or collars. Plains Exploration & Production Company Reconciliation of GAAP to Non-GAAP Measure
The following table reconciles Net Cash Provided by Operating Activities (GAAP) to Operating Cash Flow (Non-GAAP) for the three and nine months ended September 30, 2008 and 2007. Management believes this presentation may be useful to investors because it is illustrative of the impact of the Company’s derivative contracts. PXP management uses this information for comparative purposes within the industry and as a means of measuring the Company’s ability to fund capital expenditures and service debt. This measure is not intended to replace the GAAP statistic but to provide additional information that may be helpful in evaluating the Company’s operational trends and performance.
Operating cash flow is calculated by adjusting the GAAP measure of cash provided by operating activities to exclude the effect of current income taxes attributable to the taxable gain on the anticipated sale of our remaining interest in the Permian and Piceance Basin properties which is expected to close in December 2008 and changes in operating assets and liabilities and include derivative cash flows that are classified as financing or investing activities in the statement of cash flows. Pursuant to GAAP certain cash payments with respect to our derivative instruments are required to be reflected as financing or investing activities.
Three Months Ended September 30, 2008 2007 (millions of dollars) Net cash provided by operating activities (GAAP) $537.6 $144.5 Changes in operating assets and liabilities (264.9) 27.1 Current income taxes on the tax gain on sale of oil and gas properties 168.6 – Cash payments for commodity derivative contracts that settled during the period that are reflected as investing or financing cash flows in the statement of cash flows (17.6) (25.6) Operating cash flow (Non-GAAP) $423.7 $146.0 Nine Months Ended September 30, 2008 2007 (millions of dollars) Net cash provided by operating activities (GAAP) $1,146.9 $285.8 Changes in operating assets and liabilities (31.2) 140.5 Current income taxes on the tax gain on sale of oil and gas properties 168.6 – Cash payments for commodity derivative contracts that settled during the period that are reflected as investing or financing cash flows in the statement of cash flows (60.3) (74.8) Operating cash flow (Non-GAAP) $1,224.0 $351.5
Plains Exploration & Production Company
CONTACT: investors, Hance Myers, +1-713-579-6291, email@example.com, ormedia, Scott Winters, +1-713-579-6190, firstname.lastname@example.org, both of PlainsExploration & Production Company
Web site: http://www.pxp.com/