PXP Announces Fourth Quarter and Full-Year 2005 Results
HOUSTON, March 2 /PRNewswire-FirstCall/ — Plains Exploration & Production Company (“PXP” or the “Company”) today announced financial and operating results for the fourth quarter and full-year 2005.
Highlights of the year include: * PXP’s stock price increased 53 percent for the year ended December 31, 2005. Since the Company became independent in December 2002 the stock price has increased approximately 300 percent through December 31, 2005. * Established high impact exploration opportunities in the Deepwater Gulf of Mexico and the Green River Basin in Wyoming. PXP currently has interests in more than 40 blocks in the Deepwater Gulf of Mexico with a discovery recently announced by the operator of the Big Foot prospect. Approximately four additional prospects will be drilled in 2006. In the Green River Basin, PXP acquired rights with respect to 50,000 net acres in Sublette County, Wyoming. The acreage includes an existing indicated discovery and PXP expects well permitting to be completed and drilling to commence in 2007. * Focused the development and exploitation portfolio by acquiring producing properties in the Los Angeles Basin and acquiring an additional 16.7 percent interest in the offshore California Point Arguello Unit while selling our interests in non-core, mostly non- operated producing properties located in East Texas. * Significantly improved PXP’s financial outlook by terminating 2006 oil price swaps and collars, acquiring substantial oil price downside protection via put option contracts and improving our oil price realizations by negotiating lower contractual price differentials on most of our crude oil production. * Created a venture with Cook Hill Properties of Los Angeles to advance the development and monetization of our real estate surface holdings in California. * Established a $500 million stock repurchase program that is intended to return excess capital to our investors and generate shareholder value. FOURTH QUARTER 2005
For the quarter PXP reported production of 62.9 thousand barrels of oil equivalent per day (BOEPD) compared to 76.9 BOEPD for 2004. Production was lower year-over-year due to asset sales late in the fourth quarter 2004 and in the second quarter 2005 as well as to previously announced hurricane downtime and operational shut-ins.
For the quarter PXP reported a net income of $73.8 million, or $0.93 per diluted share, compared to a net income of $27.5 million, or $0.35 per diluted share, for the fourth quarter 2004. The results for the fourth quarter 2005 reflect the following items:
* $6.9 million pre-tax loss on market-to-market derivative contracts; cash payments related to the mark-to-market derivative contracts that settled during the quarter totaled $90.7 million; * $23.7 million pre-tax non cash charge to revenue related to certain oil and gas hedges; and * $0.5 million pre-tax credit related to stock-based compensation.
Without the effects of these items net income for the fourth quarter would have been $33.9 million, or $0.43 per diluted share compared to $18.3 million, or $0.24 per diluted share for 2004. See the end of this release for an explanation and reconciliation of non-GAAP financial measures.
Operating cash flow, a non-GAAP measure, was $96.0 million in the fourth quarter of 2005 compared to 2004 fourth quarter operating cash flow of $72.7 million.
The average realized sales price per BOE before hedging and derivative transactions was $51.71 during the fourth quarter of 2005 compared to $39.55 in the fourth quarter of 2004. Cash payments related to hedging and derivative transactions that settled during the quarter were $16.12 per BOE in 2005 compared to $15.25 in 2004.
Total production costs were $13.54 per BOE in the fourth quarter of 2005, compared to $9.33 per BOE in 2004. The year-over-year increase per unit is primarily attributable to higher steam gas costs, higher than expected lease operating costs due to workover activity and lower volumes associated with hurricane downtime and operational shut-ins.
Total oil and gas depreciation, depletion and amortization costs were $8.40 per BOE in the fourth quarter of 2005, compared to guidance of $7.00 per BOE and $6.99 per BOE in the fourth quarter of 2004. The fourth quarter 2005 includes an $8.7 million pre-tax charge to reflect the year-end depreciation rate increase to $8.40 per BOE from $6.89 per BOE in the third quarter of 2005.
General and administrative costs for the quarter, excluding stock-based compensation, were $14.4 million. The Company recorded a pre-tax credit of $4.2 million for SARs and a $3.8 million pre-tax charge related to vesting of restricted stock and restricted stock units. Cash payments for SARs exercised during the fourth quarter were approximately $9.1 million.
FULL YEAR 2005
For 2005 PXP reported production of 64.6 thousand BOEPD compared to 62.5 BOEPD in 2004. Operating cash flow, a non-GAAP measure, was $343.9 million in 2005 compared to $223.2 million in the prior year period.
Due primarily to a mark-to-market charge for derivative fair value losses associated with the rise in oil prices during the year, PXP reported a net loss of $211.0 million, or $2.71 per diluted share as compared to net income of $8.8 million, or $0.14 per diluted share, for 2004. During 2005, PXP recognized the following items:
* $636.5 million pre-tax loss on mark-to-market derivative contracts. Cash payments related to the mark-to-market derivative contracts totaled $425.4 million, including the $145.4 million cash payment to eliminate the 2006 collars; * $82.8 million pre-tax non cash charge to revenue related to certain oil and gas hedges; and * $72.3 million pre-tax charge related to stock-based compensation.
Without the effects of these items net income for the year would have been $103.6 million, or $1.32 per diluted share compared to $63.9 million, or $1.00 per diluted share for 2004.
The average realized sales price per BOE before hedging and derivative transactions was $45.96 during 2005 compared to $35.92 in 2004. Cash payments related to hedging and derivative transactions that settled during the twelve months were $14.40 per BOE in 2005 compared to $11.24 in 2004.
Total production costs were $12.10 per BOE for the year, compared to $9.76 per BOE in 2004. The year-over-year increase per unit is primarily attributable to higher steam gas costs for the San Joaquin Valley production acquired through the Nuevo merger that was completed in May 2004 and higher lease operating expenses due to workover activity, increased field costs and lost volumes associated with shut-in production from Gulf of Mexico hurricanes.
General and administrative costs for the year, excluding stock-based compensation, were $50.3 million. The Company recognized a pre-tax stock-based compensation charge of $72.3 million during the year related to SARs and restricted stock. The Company recorded a pre-tax charge of $39.9 million for SARs and a $32.4 million pre-tax charge related to vesting of restricted stock and restricted stock units. Cash payments for SARs exercised during the year were approximately $22.5 million.
2005 RESERVES
As determined by its third party independent engineers, PXP’s year-end 2005 proven reserves totaled 401 million barrels of oil equivalent (MMBOE) compared to 419 MMBOE at year-end 2004. The 2005 reserve total includes the effect of divesting 26.2 MMBOE, acquiring 19.3 MMBOE, net negative revisions of 12.4 MMBOE notably related to Deep Inglewood and Rocky Point, drill-bit additions of 24.6 MMBOE and production for the year of 23.6 MMBOE. The Company’s total costs incurred for the year was $580.9 million, of which $129.1 million was exploration capital and $151.4 million was for acquisitions.
Year-end 2005 estimated proved reserves include 356 million barrels of oil and liquids and 268 billion cubic feet of natural gas. Approximately 67 percent of the reserves are classified as proved developed. PXP’s reserve-to- production ratio is about 17 years for total proved reserves.
The following table summarizes PXP’s 2005 and five-year reserve statistics.
2005 2001-2005 (A) (Million BOE) Beginning Reserves 419.3 220.0 Extensions/Discoveries/Improved Recovery 24.6 130.5 Revisions (12.4) (36.7) Acquisitions 19.3 257.1 Divestitures (26.2) (93.0) Production (23.6) (76.9) Ending Reserves 401.0 401.0 ($ Million) Exploration & Development Costs $ 429.5 $ 931.5 Acquisition Costs $ 151.4 $1,880.0 Total Costs Incurred $ 580.9 $2,811.5 (A) PXP was spun off from Plains Resources in December 2002. OPERATIONAL UPDATE
At PXP’s Rocky Point development offshore California, as a follow on to the successful re-drill of the C-14 well announced in November 2005, PXP and its partners approved and re-drilled the low volume C-13 well as an additional near horizontal side-track well and brought it on to production this February at a gross rate of 2,200 BOEPD. Based on the results of these two side-track near horizontal wells, a new well, the C-15, will be drilled with operations currently underway. With the addition of the C-15 well and including the original C-12 development well, the total Rocky Point well count will be four, all from the same platform. PXP’s working interest at Point Arguello and Rocky Point is approximately 69.3 percent. Further Rocky Point drilling beyond the new C-15 well is not presently anticipated; however, opportunities for additional drilling in the main Point Arguello Field are under review.
Also offshore California at the Point Pedernales Field, rig refurbishment activities were completed in January and the first of four planned in-fill wells has been drilled to its planned total depth. Completion and initial production are expected later this month. Drilling operations at Point Pedernales will not necessarily be sequential as workovers of existing wells will also be conducted with the available platform rig. PXP has a 100 percent working interest at Point Pedernales.
In California’s Los Angeles Basin, 38 wells have been completed in the fourth quarter and thus far in 2006. Drilling activities during this period have been concentrated in the Inglewood Field in the Vickers-Rindge waterflood zone, the Moynier formation with a newly initiated waterflood, and to a lesser extent in the Sentous Sand primary recovery zone. Drilling will continue in Inglewood in the Vickers-Rindge and in expanding the successful Moynier development. Additionally a pay interval called the Rubel located between the Vickers-Rindge and Moynier will be drilled, pilot waterflooded, and evaluated this year. PXP has a 100 percent working interest and 80-85 percent income interest in Inglewood. Additional drilling in the Los Angeles Basin in the Las Cienegas Field which was acquired last year should begin this summer.
In the San Joaquin Valley (SJV), 101 wells have been drilled in the fourth quarter and thus far in 2006. In the Midway Sunset Field, 24 producers were completed, and 11 more producers are in the completion/steaming process and have not yet started production. At the Mt. Poso Field, which produces lighter oil without the need for steaming, 4 new wells were completed with another 12 wells being completed or recovering completion fluids. In the Cymric Field, 9 producers were completed with another 5 producers not yet producing and 8 new steam injection wells were drilled. The remaining new wells included stratigraphic tests to define field expansion possibilities, steam temperature observation wells, and drilling in other SJV fields. Total new drilling in the San Joaquin Valley should total slightly over 200 wells in 2006. In addition to drilling activities, considerable facilities construction or expansion is underway to support both new and increased production and steam volumes in Midway Sunset, Cymric, Belridge, and McKittrick Fields. PXP generally has a 100 percent working interest and 80-100 percent income interest in the above listed San Joaquin Valley fields.
In the south Louisiana portion of PXP’s Eastern Development Unit, success continued at the Queen Bess Isle Field in Jefferson Parish with the third of three PXP drilled wells finding pay. The well was completed as a single zone completion with additional up hole pay available for a future completion. The well was brought on to sales in February at a rate of 7.5 MMCFD. PXP has a 50 percent working interest and approximate 42.7 percent income interest in Queen Bess #3. Three Breton Sound wells are anticipated in 2006 with one completion each in the second, third, and fourth quarters.
In the Texas portion of the Eastern Development Unit, PXP completed a horizontal Wolfcamp formation test in the Pakenham Field which is currently flowing to sales at a rate of 1.2 MMCFD. This is the field’s first horizontal well in the Wolfcamp which is the primary producing zone at Pakenham. PXP has a 100 percent working interest and 75 percent income interest in the well. Also in Texas during 2005, PXP assembled acreage over several specific Ellenburger Formation exploratory prospects in West Texas and several more Pettit Formation prospects in East Texas. Net acreage totals exceed 32,000 acres with additional acreage acquisition possible. Both zones will be evaluated initially with vertical pilot holes and if pay is indicated the resources will be exploited with horizontal wells. Initial test wells on both an Ellenburger and Pettit prospect are currently drilling. If successful, gas production is expected at rates between 2 and 6 MMCFD per well. PXP will have a 75-100 percent working interest in most of the Ellenburger and Pettit acreage.
In the deep water Middle/Lower Miocene trend area of the Gulf of Mexico, PXP owns a 12.5 percent working interest in the Big Foot prospect announced by the operator earlier this year as a successful well with as much as 300 feet or more of net oil pay. Appraisal operations at Big Foot are underway. PXP is also currently participating in drilling the Caesar Prospect with a 17.5 percent working interest. Two additional deep water Miocene exploratory tests are also anticipated later in 2006. PXP’s deepwater Miocene prospect inventory now totals 13 prospects on over 40 blocks with interests averaging about 15 percent.
2006 OUTLOOK
PXP plans to issue updated annual guidance for 2006 via Form 8-K to reflect an increase in the depreciation, depletion and amortization rate to a range of $8.40 to $8.50 per BOE. PXP reaffirms all other 2006 estimates originally filed on December 6, 2005.
FOURTH QUARTER AND FULL-YEAR EARNINGS CONFERENCE CALL
PXP will host a conference call tomorrow March 3, 2006 at 8:30 a.m. Central to discuss the results and other forward-looking items. Investors wishing to participate may dial 1-800-370-0740 or 1-973-409-9259. The replay will be available through March 17, 2006 and can be accessed by dialing 1-877-519-4471 or 1-973-341-3080, Replay ID: 6936123.
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:
* reserve and production estimates, * oil and gas prices, * the impact of derivative positions, * production expense estimates, * cash flow estimates, * future financial performance, * 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, 2004, 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. 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.
PXP is an independent oil and gas company primarily engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas in its core areas of operation: onshore and offshore California, West Texas and the Gulf Coast region of the United States. PXP is headquartered in Houston, Texas.
Plains Exploration & Production Company Consolidated Statements of Income (amounts in thousands, except per share data) Quarter Ended Year Ended December 31, December 31, 2005 2004 2005 2004(A) Revenues Oil sales $218,900 $150,554 $734,032 $448,056 Gas sales 54,128 64,371 206,736 221,360 Other operating revenues 1,390 689 3,652 2,290 274,418 215,614 944,420 671,706 Costs and Expenses Production costs Lease operating expenses 35,106 30,474 140,595 122,540 Steam gas costs 27,260 17,901 78,277 40,521 Electricity 8,139 8,417 31,817 30,137 Production and ad valorem taxes 6,064 7,214 24,478 22,332 Gathering and transportation expenses 1,709 1,983 10,125 7,550 General and administrative G&A excluding items below 14,445 11,123 50,321 35,394 Stock appreciation rights (4,245) 7,015 39,856 35,464 Other stock-based compensation 3,792 1,447 32,449 8,092 Merger related costs — 2,772 — 6,247 Provision for legal and regulatory settlements — 6,845 — 6,845 Depletion, depreciation, amortization and accretion 52,346 53,743 187,915 147,985 144,616 148,934 595,833 463,107 Income from Operations 129,802 66,680 348,587 208,599 Other Income (Expense) Gain (loss) on mark-to-market derivative contracts (6,904) (24,472) (636,473) (150,314) Debt extinguishment costs — — — (19,691) Interest expense (15,382) (10,788) (55,421) (37,294) Interest and other income 3,544 54 3,324 723 Income (Loss) Before Income Taxes 111,060 31,474 (339,983) 2,023 Income tax (expense) benefit Current 802 232 229 (375) Deferred (38,074) (4,179) 128,745 7,192 Net Income (Loss) $73,788 $27,527 $(211,009) $8,840 Earnings per Share Basic $0.94 $0.36 $(2.71) $0.14 Diluted $0.93 $0.35 $(2.71) $0.14 Weighted Average Shares Outstanding Basic 78,305 77,043 77,726 63,542 Diluted 78,997 77,824 77,726 64,014 (A) Reflects the acquisition of Nuevo Energy Company effective May 14, 2004. Plains Exploration & Production Company Operating Data Quarter Ended Year Ended December 31, December 31, 2005 2004 2005 2004(A) Sales Volumes Oil and Liquids (MBbls) 4,880 5,267 18,671 16,441 Gas (MMcf) 5,446 10,859 29,359 38,590 MBOE 5,787 7,076 23,564 22,872 Average Daily Sales Volumes Oil and Liquids (Bbls) 53,038 57,246 51,154 44,920 Gas (Mcf) 59,195 118,027 80,435 105,436 BOE 62,904 76,917 64,560 62,493 Unit Economics (in dollars) Average NYMEX Prices Oil $60.03 $48.27 $56.61 $41.43 Gas 12.97 7.11 8.62 6.14 Average Realized Sales Price Before Derivative Transactions Oil (per Bbl) $49.80 $40.19 $46.76 $36.12 Gas (per Mcf) 10.32 6.29 7.15 5.90 Per BOE 51.71 39.55 45.96 35.92 Production expenses per BOE Lease operating expenses $6.07 $4.31 $5.97 $5.36 Steam gas costs 4.71 2.53 3.32 1.77 Electricity 1.41 1.19 1.35 1.32 Production and ad valorem taxes 1.05 1.02 1.03 0.98 Gathering and transportation expenses 0.30 0.28 0.43 0.33 Cash payments related to 2005 and 2004 derivative contracts that settled during the periods were as follows ($/millions): Contracts accounted for using hedge accounting Oil $— $84.6 $53.0 $207.4 Gas 2.6 7.4 6.3 17.5 Mark-to-market contracts 90.7 15.9 280.0 32.2 (A) Reflects the acquisition of Nuevo Energy Company effective May 14, 2004. PLAINS EXPLORATION & PRODUCTION COMPANY CONSOLIDATED BALANCE SHEETS (in thousands of dollars) December 31, 2005 2004 ASSETS Current Assets Cash and cash equivalents $1,552 $1,545 Accounts receivable 148,691 122,288 Inventories 10,325 8,505 Deferred income taxes 128,816 76,823 Assets held for sale — 44,222 Other current assets 3,948 4,784 293,332 258,167 Property and Equipment, at cost Oil and natural gas properties – full cost method 2,717,096 2,481,584 Other property and equipment 16,282 12,546 2,733,378 2,494,130 Less allowance for depreciation, depletion and amortization (498,075) (323,041) 2,235,303 2,171,089 Goodwill 173,858 170,467 Other Assets 39,449 33,522 $2,741,942 $2,633,245 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts payable $122,996 $90,469 Commodity derivative contracts 85,596 175,473 Royalties payable 43,279 39,174 Stock appreciation rights 55,170 34,589 Interest payable 13,000 13,070 Deposit on assets held for sale — 40,711 Other current liabilities 43,957 32,909 363,998 426,395 Long-Term Debt 8.75% Senior Subordinated Notes 276,538 276,727 7.125% Senior Notes 248,837 248,741 Revolving credit facility 272,000 110,000 797,375 635,468 Other Long-Term Liabilities Asset retirement obligation 155,865 126,850 Commodity derivative contracts 440,543 244,140 Other 7,014 10,534 603,422 381,524 Deferred Income Taxes 260,694 319,483 Stockholders’ Equity Common stock 784 772 Additional paid-in capital 936,101 913,466 Retained earnings (deficit) (130,661) 80,406 Accumulated other comprehensive income (89,566) (123,874) Treasury stock, at cost (205) (395) 716,453 870,375 $2,741,942 $2,633,245 Plains Exploration & Production Company Consolidated Statements of Cash Flows (thousands of dollars) Quarter Ended Year Ended December 31, December 31, 2005 2004 2005 2004 CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $73,788 $27,527 $(211,009) $8,840 Items not affecting cash flows from operating activities Depreciation, depletion, amortization and accretion 52,346 53,743 187,915 147,985 Deferred income taxes 38,074 4,179 (128,745) (7,192) Debt extinguishment costs — — — (4,453) Commodity derivative contracts Loss (gain) on derivatives (58,686) (16,365) 300,152 49,841 Reclassify financing derivative settlements 94,518 42,247 459,450 103,521 Noncash compensation Stock appreciation rights (13,375) 2,384 17,354 20,268 Other noncash compensation 3,952 1,447 33,030 8,092 Other noncash items (24) (52) (93) (144) Changes in assets and liabilities from operating activities (15,434) (2,060) (194,720) 36,461 Net cash provided by operating activities 175,159 113,050 463,334 363,219 CASH FLOWS FROM INVESTING ACTIVITIES Acquisition, exploration, development and other costs (115,749) (69,288) (509,127) (211,387) Acquisition of Nuevo Energy Company — — — (14,156) Proceeds from property sales 3,354 153,097 346,450 238,989 Other (2,220) (2,293) (5,743) (8,032) Net cash provided by (used in) investing activities (114,615) 81,516 (168,420) 5,414 CASH FLOWS FROM FINANCING ACTIVITIES Change in revolving credit facilities 33,500 (153,000) 162,000 (101,000) Proceeds from debt issuance — — — 248,695 Retirement of debt assumed in acquisition of Nuevo Energy Company — — — (405,000) Derivative settlements (94,518) (42,247) (459,450) (103,521) Other 720 436 2,543 (7,639) Net cash provided by (used in) financing activities (60,298) (194,811) (294,907) (368,465) Net increase (decrease) in cash and cash equivalents 246 (245) 7 168 Cash and cash equivalents, beginning of period 1,306 1,790 1,545 1,377 Cash and cash equivalents, end of period $1,552 $1,545 $1,552 $1,545 Plains Exploration & Production Company Summary of Open Derivative Positions at December 31, 2005 Instrument Daily Average Period Type Volumes Price Index Sales of Crude Oil Production 2006 Jan – Dec Put options 50,000/Bbls $55.00 Strike price WTI 2007 Jan – Dec Collar 22,000/Bbls $25.00 Floor – $34.76 Ceiling WTI Jan – Dec Put options 50,000/Bbls $55.00 Strike price WTI 2008 Jan – Dec Collar 22,000/Bbls $25.00 Floor – $34.76 Ceiling WTI Purchases of Natural Gas 2006 Jan – Dec Call options 30,000/MMBtu $12.00 Strike price Socal Plains Exploration & Production Company Reconciliation of GAAP to Non-GAAP Measures
The following chart reconciles Net Cash Provided by Operating Activities (GAAP) to Operating Cash Flow (non-GAAP) for the three-month and the twelve- month periods ended December 31. 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 changes in assets and liabilities and include derivative cash flows that are classified as a financing activity in the statement of cash flows. Pursuant to SFAS 149 “Amendment of SFAS 133, Derivative Instruments and Hedging Activities”, certain of our derivative instruments are deemed to contain a significant financing element and cash flows associated with these positions are required to be reflected as financing activities. The cash flows that were reclassified in the tables below reflect settlements for 2005 and 2004 positions and do not include the $145.4 million that we paid in the second quarter of 2005 to eliminate our 2006 collar positions.
Quarter Ended Year Ended December 31, December 31, 2005 2004 2005 2004 (millions of dollars) Net cash provided by operating activities (GAAP) $175.1 $113.0 $463.3 $363.2 Changes in operating assets and liabilities Commodity derivative contracts 3.7 (4.1) 139.0 (19.7) Other 11.8 6.0 55.7 (16.8) Cash payments for commodity derivative contracts that settled during the period that are reflected as financing cash flows in the statement of cash flows (94.6) (42.2) (314.1) (103.5) Operating cash flow (Non-GAAP) $96.0 $72.7 $343.9 $223.2 2005 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year (millions of dollars) Net cash provided by operating activities (GAAP) $97.8 $15.7 $174.7 $175.1 $463.3 Changes in operating assets and liabilities Commodity derivative contracts (3.0) 145.9 (7.6) 3.7 139.0 Other 34.1 (3.4) 13.2 11.8 55.7 Cash payments for commodity derivative contracts that settled during the period that are reflected as financing cash flows in the statement of cash flows (50.8) (74.6) (94.1) (94.6) (314.1) Operating cash flow (Non-GAAP) $78.1 $83.6 $86.2 $96.0 $343.9 Plains Exploration & Production Company Reconciliation of GAAP to Non-GAAP Measures
The following chart reconciles net income (loss) (GAAP) to net income (loss) excluding certain items (Non-GAAP) for the three-month and the twelve- month periods ended December 31. This measure excludes certain items that management believes affect the comparability of operating results. Items excluded are generally items whose timing or amount cannot be reasonably estimated. Management believes this presentation may be helpful to investors who want to isolate the impacts from oil and gas derivative contracts and stock-based compensation. 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.
Quarter Ended Year Ended December 31, December 31, 2005 2004 2005 2004 (millions of dollars) Net income (loss) (GAAP) $73.8 $27.5 $(211.0) $8.8 Loss on mark-to-market derivative contracts 6.9 24.5 636.5 150.3 Cash payments on mark-to-market derivative contracts (90.7) (15.9) (280.0) (32.2) Non cash charge to revenue for oil and gas hedges 23.7 (27.0) 82.9 (73.0) Stock-based compensation (0.5) 8.5 72.2 43.6 Adjust income taxes 20.7 0.7 (197.0) (33.6) Net income (loss) excluding certain items (Non-GAAP) $33.9 $18.3 $103.6 $63.9
The cash payment on mark-to-market derivative contracts in the table above reflects settlements for 2005 positions. The 2005 amount does not include the $145.4 million that we paid in the second quarter of 2005 to eliminate our 2006 collar positions.
Plains Exploration & Production Company
CONTACT: Scott D. Winters, Vice President – Investor Relations of PlainsExploration & Production Company, +1-713-579-6190, or +1-800-934-6083
Web site: http://www.plainsxp.com/