Exhibit 99.1
FOR IMMEDIATE RELEASE
PXP Announces 2008 Results and Operating Highlights
| | • | | With revenues of $2.4 billion, PXP reported net income for the year of $524 million, or $4.81 per diluted share, before the impact of a non-cash impairment charge on its oil and gas properties, a gain on mark-to-market derivative contracts and a gain on sale of assets. Including the impact of these items, PXP reported a net loss of $709.1 million or $6.52 per diluted share for 2008. |
| | • | | PXP strengthened its year-end balance sheet by reducing net debt over $930 million, or 26%, from the third quarter 2008 and repurchased over 5% of shares outstanding during 2008. |
| | • | | PXP grew production sales volumes 10% pro forma for asset sales, and replaced 140% of 2008 full-year production with drill-bit, technical revisions and acquisitions. |
| | • | | PXP reported 292 million barrels of oil equivalent at year-end 2008 reflecting a 54% reduction in the NYMEX West Texas Intermediate oil price and substantially wider spot sales differentials than historical averages. These impacts resulted in a significant migration of proved undeveloped reserves into low risk potential reserves. |
| | • | | PXP completed its strategic asset rotation by investing $1.65 billion into a large, high potential/lower risk development portfolio with top-tier returns, and sold $3 billion of non-strategic oil and gas properties. |
| | • | | PXP drilled 26 gross highly successful wells in the Haynesville Shale during 2008 with Chesapeake Energy, providing further confirmation of potentially one of the largest domestic gas fields. A significant portion of PXP’s resources are planned for its emerging position in the Haynesville Shale where finding and development and full-cycle costs are some of the most attractive in the industry. Drilling results have been encouraging and with over 7,300 potential well locations after risk weighting, this asset area is expected to be a significant driver of future production and reserve growth. |
Strong Start in 2009
| | • | | Since the first of the year, PXP has drilled nine gross highly successful wells with Chesapeake Energy in the Haynesville Shale. Currently 18 wells are producing 100 million cubic feet per day (MMCFED) gross, 14.2 MMCFED net to PXP, and another 15 wells are waiting on completion. The joint venture plans to drill approximately 150 gross wells and run an average of 26 rigs during 2009. |
Page 2
| | • | | PXP has announced significant pay in the Friesian #2 well, the first confirmation of four high-impact exploration prospects. This well is scheduled to be deepened during the second quarter; the Ammazzo prospect is currently drilling; and the White Shark and Salida prospects will begin drilling in the second and third quarters, respectively. |
| | • | | PXP has monetized $1.125 billion in commodity derivative gains and will use proceeds to reduce debt further. Since the Haynesville acquisition in July 2008, net debt will be reduced by over $2 billion. |
| | • | | PXP has reset 2010 crude oil derivative positions with $55 floors and acquired $6.25 by $8.00 natural gas three way collars with a $4.80 sliding floor for 2010. |
2008 Fourth Quarter and Year End Detailed Results and Updated 2009 Full-Year Guidance
Houston, Texas, February 25, 2009—Plains Exploration & Production Company (NYSE:PXP) (“PXP” or the “Company”) today announces 2008 fourth quarter and full-year financial and operating results, revises 2009 full-year operating and financial guidance, and provides financial and operational updates.
During 2008, the Company successfully completed a major asset rotation from certain basins into the prolific Haynesville Shale while simultaneously reducing long term debt and the total number of shares outstanding. The Company also continued its policy of protecting the balance sheet through aggressively hedging its commodity price exposure through the use of put and collar contracts.
For 2009, the Company plans to maximize returns on its existing portfolio by high-grading reduced capital expenditures toward higher rate of return development projects, lowering lease operating expenses 15% to 20% and reducing cash general and administrative costs by 10%. The $1.050 billion capital budget is prudently allocated, based on the current economic conditions, to the Company’s major development areas including its emerging and prolific position in the Haynesville Shale where finding and development and full-cycle costs are some of the most attractive in the industry. PXP will drill its remaining committed high-impact exploration projects including the deepening of the Friesian discovery, its Salida prospect with Shell, and its White Shark prospect in Vietnam. Remaining capital spending will be focused on the Flatrock development in the Gulf of Mexico and maintaining production in its long-life reserve base in California.
In 2009, PXP continues to be committed to strengthening its liquidity. During February, PXP entered into early settlement and reset arrangements in which the Company monetized its 2009 and 2010 crude oil put option contracts on 40,000 barrels of oil per day (BOPD) with weighted average strike prices of $106.16 and $111.49, respectively. As a result of these early settlements, the Company will realize $1.125 billion in proceeds, which it will use to reduce the outstanding balance on its secured revolving credit facility, further increasing its liquidity and positioning the Company to capitalize on future opportunities. The Company expects to have approximately
—MORE—
Page 3
$1.5 billion in borrowing base capacity after the pay down of the credit facility. The Company retained its existing $55 crude oil puts on 32,500 BOPD in 2009 and reset the strike price to $55 on 40,000 BOPD in 2010 with a deferred premium plus interest of $5 per barrel.
The monetization and reset arrangements accelerate cash receipts, while maintaining a derivative position that protects against further declines in oil and natural gas prices during 2009 and 2010. Current drilling plans for 2009 and 2010 are expected to result in tax deductions that will, to a significant degree, offset cash tax liabilities attributable to our derivative monetization. PXP also acquired natural gas three way collars on 40,000 million British thermal units per day for 2010. A summary of PXP’s open commodity derivative positions is located after the financial statements in this release.
FULL-YEAR 2008 RESULTS
For the full-year 2008 PXP reported a net loss of $709.1 million, or $6.52 per diluted share, on revenues of $2.4 billion. The loss reflects the following items:
| | • | | a $2.3 billion after-tax impairment of oil and gas properties due to significantly lower commodity prices at year-end 2008. This non-cash adjustment resulted from the application of full cost accounting rules; |
| | • | | a $972 million after-tax gain on mark-to-market derivative contracts; and |
| | • | | a $41 million after-tax gain on sale of assets. |
Without the effects of these items net income for the year would have been $524 million, or $4.81 per diluted share. An explanation and reconciliation of non-GAAP financial measures is included at the end of this release.
Operating cash flow, a non-GAAP measure, for the year was $1.5 billion. An explanation and reconciliation of non-GAAP financial measures is included at the end of this release.
Sales volumes for the full-year 2008 averaged 90.5 thousand barrels of oil equivalent per day (BOEPD). Full-year sales volumes adjusted for 2008 asset sales averaged 76.0 thousand BOEPD.
FOURTH QUARTER 2008 RESULTS
For the fourth quarter 2008 PXP reported a net loss of $1.6 billion, or $14.56 per diluted share, on revenues of $328.2 million. The loss reflects the following items:
| | • | | a $2.3 billion after-tax impairment of oil and gas properties due to significantly lower commodity prices at year-end 2008. This non-cash adjustment resulted from the application of full cost accounting rules; |
| | • | | a $728 million after-tax gain on mark-to-market derivative contracts; and |
—MORE—
Page 4
| | • | | a $19 million after-tax gain on sale of assets. |
Without the effects of these items the net loss for the quarter would have been $33.1 million, or $0.31 per diluted share. An explanation and reconciliation of non-GAAP financial measures is included at the end of this release.
Operating cash flow, a non-GAAP measure, was $292.8 million in the fourth quarter 2008. An explanation and reconciliation of non-GAAP financial measures is included at the end of this release.
Sales volumes for the fourth quarter averaged approximately 86.5 thousand BOEPD.
PROVED RESERVES
PXP’s year-end 2008 proved reserves total 292 million barrels of oil equivalent (MMBOE). Ninety-five percent of the reserves were engineered by third party independent engineers.
PXP added 47 MMBOE of proved reserves during 2008 from discoveries, extensions, technical revisions and acquisitions. These additions equate to replacing 140% of full-year 2008 production. Of these additions, approximately 65% (31 MMBOE) resulted from drilling success and performance improvements. The remaining 35% (16 MMBOE) was attributable to acquisitions. The drill-bit finding and development cost for the proved reserve additions from drilling success and performance improvements (discoveries, extensions and technical revisions) was $35.96 per barrel oil equivalent (BOE).
The proved reserve additions attributed to drilling success in 2008 were offset by 204 MMBOE of negative price revisions. As required by current SEC reporting rules, year-end proved reserve volumes are calculated using commodity prices as of December 31, 2008. The price of natural gas at year-end 2008 was $5.71 per million British thermal units (MMBtu) compared to $7.48 per MMBtu a year ago. The West Texas Intermediate price of oil on December 31, 2008 was $44.60 per barrel, less than half of the $95.98 per barrel on the last day of 2007 when PXP’s proved reserves were last reported. The SEC also requires that proved reserves be calculated using service and production costs indicative of year-end 2008 levels, which were much higher than could be supported by the lower year-end commodity prices on an ongoing basis.
The majority of the price related revisions to oil and gas properties occurred on our long-life California oil reserves. The dramatic decline in the price of oil coupled with year-end differentials, which were approximately 86% wider than recent historical averages, were the primary causes of the revisions. Using year-end pricing as required by the SEC and recent historical average differentials rather than year-end differentials as required by the SEC, the reserve revisions related to price would have been 166 MMBOE. PXP sells its physical crude under term contracts to high quality counterparties to mitigate the risk of sudden fluctuations in differentials.
—MORE—
Page 5
The table below shows the amount of proved reserves recaptured from the negative price revisions of 204 MMBOE at various NYMEX prices instead of those in effect on December 31, 2008. PXP maintained production costs and well costs at December 2008 levels, recognizing that these costs are expected to decrease significantly.
Reserve Recapture
| | | | | | | | | | |
Nymex Prices
Oil $/Bbl | |
| Gas
$/MMBtu |
| | MMBOE | | Percent (%)
Recaptured | | |
| $44.60 | | $ | 5.71 | (1) | | 38 | | 19 | | |
| 60.00 | | | 6.00 | | | 138 | | 68 | | |
| 80.00 | | | 8.00 | | | 171 | | 84 | | |
| $95.98 | | $ | 7.48 | (2) | | 204 | | 100 | | |
| (1) | Using recent historical average differentials |
After considering the Company’s reserve adds during 2008, offset by the negative price revisions, divestments, and production during the year, total proved oil and gas reserves were 292 MMBOE as of December 31, 2008. All of these reserves are in the United States and 72% are proved developed (PD). Approximately 61% of the Company’s proved reserves are oil and natural gas liquids and 39% are natural gas.
PXP’s reserves are long-lived with a total reserves-to-production ratio of approximately 10 years and a PD reserves-to-production ratio of 7 years. The Company’s long-lived reserves, with low relative production decline rates, are particularly attractive in the current low commodity price environment in which industry drilling activity is significantly curtailed.
—MORE—
Page 6
The following tables summarize the proved reserve reconciliation and costs incurred.
| | | |
| Proved Reserves: | | 2008 | |
| | (MMBOE | ) |
Year End 2007 Proved Reserves | | 689.9 | |
Extensions, discoveries and other additions | | 41.9 | |
Revisions(1) | | (215.1 | ) |
Acquisitions | | 16.3 | |
Divestments | | (207.4 | ) |
Production | | (33.5 | ) |
| | | |
Year-end 2008 Proved Reserves | | 292.1 | |
| | | |
(1) Includes (11.4) MMBOE of technical revisions
| | | | |
| Costs Incurred: | | 2008 | |
| | | (In millions | ) |
Property acquisitions costs: | | | | |
Unproved properties | | $ | 1,878.8 | |
Proved properties | | | 267.2 | |
Exploration costs | | | 520.6 | |
Development costs | | | 576.8 | |
| | | | |
| | $ | 3,243.4 | |
| | | | |
OPERATING UPDATE
| | • | | The Haynesville Shale joint venture continues to experience outstanding drilling results and has drilled 35 wells, is currently operating 21 rigs, and has 18 wells producing 100 million cubic feet per day (MMCFED) gross, 14.2 MMCFED net to PXP. According to estimates by Chesapeake Energy, the joint venture anticipates producing approximately 575 MMCFED gross, or 65 MMCFED net to PXP, by year-end 2009. |
The last seven horizontal wells had gross initial production or test rates averaging approximately 16 MMCFED and the two most recent wells, which are currently waiting pipeline connection, tested in excess of 22 MMCFED. In addition, another 15 wells are waiting on completion. Also, a firm transportation agreement on the new Tiger Pipeline for approximately 1.0 BCF per day with a mid-2011 start up was recently announced by the operator.
The joint venture expects to run an average of 26 rigs during 2009. PXP plans on spending approximately 43% of its 2009 capital budget on the Haynesville Shale.
| | • | | Flatrock gross production is over 200 MMCFED, 45 MMCFED net to PXP, and proved reserves at year-end 2008, as estimated by independent reservoir engineers, were in excess of 350 billion cubic feet of natural gas equivalent gross (BCFE), 74.4 BCFE net to PXP. |
—MORE—
Page 7
Four wells are currently producing, a fifth well is being completed and a sixth well is drilling. Significant pay has been logged in all six wells.
| | • | | Two multi-hundred BCFE Flatrock step-out prospects are drilling: |
| | – | | Tom Sauk, operated by McMoRan and located on Louisiana State Lease 340, is drilling below 19,800 feet towards a new proposed total depth of 21,150 feet to test the deeper Gyro sands. PXP holds a 24.4% working interest. |
| | – | | Ammazzo, operated by McMoRan and located on South Marsh Island Block 251, is currently drilling below 12,000 feet towards a proposed total depth of 24,500 feet. PXP holds a 28.1% working interest. |
| | • | | The Friesian #2 well, as previously announced, encountered approximately 389 net feet of oil saturated Miocene aged sands with three main sand lobes encountering more than 210 net feet of high quality oil pay plus a fourth sand lobe encountering 179 additional feet of oil pay that was not fully evaluated. |
These four pay sands, all full to base with oil, are the uppermost field pays at the prolific Tahiti field approximately eight miles to the west across the basin syncline. Existing data show strong correlation, both geologic and pressure, from the initial Miocene field pay sands at Tahiti to the drilled portion of our Friesian #2 well. Early stage commercialization initiatives for Friesian production are under study with multiple parties to target initial production by 2012.
2009 FULL-YEAR GUIDANCE
Updated 2009 full-year financial and operational guidance is included at the end of this release and reflects the impact of the following forecasted 2009 items:
| | • | | Lower capital budget of $1.050 billion. |
| | • | | Targeted 10% reduction in total cash general and administrative expense. |
| | • | | Targeted 15% to 20% reduction in total lease operating expense. |
| | • | | Production sales volumes range of 78 to 82 thousand BOEPD. |
CONFERENCE CALL
PXP will host a conference call Thursday, February 26, 2009 at 8:30 a.m. Central time. Investors wishing to participate in the conference call may dial 1-800-567-9836 or 1-973-935-8460. Conference call and replay ID is: 81216952. The replay will be available through Thursday, March 12, 2009 and can be accessed by dialing 1-800-642-1687 or 1-706-645-9291. A live webcast of the conference call will be available in the Investor Information section of PXP’s website at www.pxp.com during the call and for 60 days after the event date.
—MORE—
Page 8
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:
| * | reserve and production estimates, |
| * | the impact of derivative positions, |
| * | production expense 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, as amended, 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.
The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In this press release, we provide reserve estimates based upon factors which SEC guidelines may prohibit from being included in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves calculated in accordance with SEC guidelines and accordingly are subject to substantially greater risk of actually being realized by PXP.
| | |
Contact: | | |
Investors: | | Media: |
Hance Myers, 713-579-6291 | | Scott Winters, 713-579-6190 |
hmyers@pxp.com | | swinters@pxp.com |
—MORE—
Page 9
Plains Exploration & Production Company
Consolidated Statements of Income
(amounts in thousands, except per share data)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Twelve Months Ended
December 31, | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| | | (Unaudited) | | | | | | | |
Revenues | | | | | | | | | | | | | | | | |
Oil sales | | $ | 235,539 | | | $ | 403,179 | | | $ | 1,766,677 | | | $ | 1,116,376 | |
Gas sales | | | 91,512 | | | | 89,975 | | | | 619,886 | | | | 153,416 | |
Other operating revenues | | | 1,103 | | | | 477 | | | | 16,908 | | | | 3,048 | |
| | | | | | | | | | | | | | | | |
| | | 328,154 | | | | 493,631 | | | | 2,403,471 | | | | 1,272,840 | |
| | | | | | | | | | | | | | | | |
Costs and Expenses | | | | | | | | | | | | | | | | |
Production costs | | | | | | | | | | | | | | | | |
Lease operating expenses | | | 90,713 | | | | 78,374 | | | | 327,412 | | | | 225,845 | |
Steam gas costs | | | 20,981 | | | | 26,834 | | | | 131,156 | | | | 103,464 | |
Electricity | | | 16,070 | | | | 10,303 | | | | 52,735 | | | | 39,767 | |
Production and ad valorem taxes | | | 16,231 | | | | 17,217 | | | | 93,988 | | | | 32,636 | |
Gathering and transportation expenses | | | 5,781 | | | | 6,978 | | | | 21,137 | | | | 11,410 | |
General and administrative | | | 38,801 | | | | 49,589 | | | | 153,306 | | | | 124,006 | |
Depreciation, depletion and amortization | | | 196,890 | | | | 125,346 | | | | 608,448 | | | | 306,278 | |
Impairment of oil and gas properties | | | 3,629,666 | | | | — | | | | 3,629,666 | | | | — | |
Accretion | | | 3,168 | | | | 2,968 | | | | 13,036 | | | | 9,800 | |
| | | | | | | | | | | | | | | | |
| | | 4,018,301 | | | | 317,609 | | | | 5,030,884 | | | | 853,206 | |
| | | | | | | | | | | | | | | | |
Income (Loss) from Operations | | | (3,690,147 | ) | | | 176,022 | | | | (2,627,413 | ) | | | 419,634 | |
Other Income (Expense) | | | | | | | | | | | | | | | | |
Gain on sale of assets | | | 31,031 | | | | — | | | | 65,689 | | | | — | |
Interest expense | | | (29,877 | ) | | | (33,685 | ) | | | (116,991 | ) | | | (68,908 | ) |
Debt extinguishment costs | | | (4,855 | ) | | | — | | | | (18,256 | ) | | | — | |
Gain (loss) on mark-to-market derivative contracts | | | 1,165,742 | | | | (12,967 | ) | | | 1,555,917 | | | | (88,549 | ) |
Other income (expense) | | | (394 | ) | | | 5,370 | | | | (12,575 | ) | | | 6,322 | |
| | | | | | | | | | | | | | | | |
Income (Loss) Before Income Taxes | | | (2,528,500 | ) | | | 134,740 | | | | (1,153,629 | ) | | | 268,499 | |
Income tax (expense) benefit | | | | | | | | | | | | | | | | |
Current | | | 81,461 | | | | 2,494 | | | | (230,815 | ) | | | 4,677 | |
Deferred | | | 878,381 | | | | (57,231 | ) | | | 675,350 | | | | (114,425 | ) |
| | | | | | | | | | | | | | | | |
Net Income (Loss) | | $ | (1,568,658 | ) | | $ | 80,003 | | | $ | (709,094 | ) | | $ | 158,751 | |
| | | | | | | | | | | | | | | | |
Earnings (Loss) per share | | | | | | | | | | | | | | | | |
Basic | | $ | (14.56 | ) | | $ | 0.83 | | | $ | (6.52 | ) | | $ | 2.02 | |
Diluted | | $ | (14.56 | ) | | $ | 0.81 | | | $ | (6.52 | ) | | $ | 1.99 | |
Weighted Average Shares Outstanding | | | | | | | | | | | | | | | | |
Basic | | | 107,733 | | | | 96,813 | | | | 108,828 | | | | 78,627 | |
| | | | | | | | | | | | | | | | |
Diluted | | | 107,733 | | | | 98,452 | | | | 108,828 | | | | 79,808 | |
| | | | | | | | | | | | | | | | |
—MORE—
Page 10
Plains Exploration & Production Company
Operating Data (Unaudited)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Twelve Months Ended
December 31, | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
Daily Average Volumes | | | | | | | | | | | | | | | | |
Oil and liquids sales (Bbls) | | | 53,215 | | | | 56,837 | | | | 55,449 | | | | 49,655 | |
Gas (Mcf) | | | | | | | | | | | | | | | | |
Production | | | 205,804 | | | | 175,858 | | | | 216,540 | | | | 80,307 | |
Used as fuel | | | 6,130 | | | | 6,293 | | | | 6,073 | | | | 6,307 | |
Sales | | | 199,674 | | | | 169,565 | | | | 210,467 | | | | 74,000 | |
BOE | | | | | | | | | | | | | | | | |
Production | | | 87,511 | | | | 86,152 | | | | 91,539 | | | | 63,041 | |
Sales | | | 86,500 | | | | 85,098 | | | | 90,527 | | | | 61,986 | |
Unit Economics (in dollars) | | | | | | | | | | | | | | | | |
Average NYMEX Prices | | | | | | | | | | | | | | | | |
Oil | | $ | 59.08 | | | $ | 90.50 | | | $ | 99.75 | | | $ | 72.36 | |
Gas | | | 6.97 | | | | 6.94 | | | | 9.06 | | | | 6.86 | |
Average Realized Sales Price Before | | | | | | | | | | | | | | | | |
Derivative Transactions | | | | | | | | | | | | | | | | |
Oil (per Bbl) | | $ | 48.12 | | | $ | 77.10 | | | $ | 87.05 | | | $ | 61.60 | |
Gas (per Mcf) | | | 4.98 | | | | 5.77 | | | | 8.05 | | | | 5.68 | |
Per BOE | | | 41.10 | | | | 62.99 | | | | 72.03 | | | | 56.12 | |
Cash Margin per BOE (1) | | | | | | | | | | | | | | | | |
Oil and gas revenues | | $ | 41.10 | | | $ | 62.99 | | | $ | 72.03 | | | $ | 56.12 | |
Costs and expenses | | | | | | | | | | | | | | | | |
Lease operating expenses | | $ | (11.40 | ) | | $ | (10.01 | ) | | $ | (9.88 | ) | | $ | (9.98 | ) |
Steam gas costs | | | (2.64 | ) | | | (3.43 | ) | | | (3.96 | ) | | | (4.57 | ) |
Electricity | | | (2.02 | ) | | | (1.32 | ) | | | (1.59 | ) | | | (1.76 | ) |
Production and ad valorem taxes | | | (2.04 | ) | | | (2.20 | ) | | | (2.84 | ) | | | (1.44 | ) |
Gathering and transportation | | | (0.73 | ) | | | (0.89 | ) | | | (0.64 | ) | | | (0.50 | ) |
| | | | | | | | | | | | | | | | |
Gross margin before DD&A (GAAP) | | | 22.27 | | | | 45.14 | | | | 53.12 | | | | 37.87 | |
Cash derivative settlements | | | 5.77 | | | | (4.03 | ) | | | (0.26 | ) | | | (4.73 | ) |
| | | | | | | | | | | | | | | | |
Cash margin (Non-GAAP) | | $ | 28.04 | | | $ | 41.11 | | | $ | 52.86 | | | $ | 33.14 | |
| | | | | | | | | | | | | | | | |
| (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. |
—MORE—
Page 11
Plains Exploration & Production Company
Consolidated Balance Sheets
(in thousands of dollars)
| | | | | | | | |
| | | December 31,
2008 | | | December 31,
2007 | |
ASSETS | | | | | | | | |
Current Assets | | | | | | | | |
Cash and cash equivalents | | $ | 311,875 | | | $ | 25,446 | |
Restricted cash | | | — | | | | 59,092 | |
Accounts receivable | | | 175,896 | | | | 304,972 | |
Commodity derivative contracts | | | 945,838 | | | | 2,186 | |
Inventories | | | 23,368 | | | | 18,394 | |
Deferred income taxes | | | — | | | | 229,893 | |
Other current assets | | | 19,464 | | | | 34,937 | |
| | | | | | | | |
| | | 1,476,441 | | | | 674,920 | |
| | | | | | | | |
Property and Equipment, at cost | | | | | | | | |
Oil and natural gas properties - full cost method | | | | | | | | |
Subject to amortization | | | 7,106,785 | | | | 7,340,238 | |
Not subject to amortization | | | 2,513,424 | | | | 1,951,783 | |
Other property and equipment | | | 110,990 | | | | 85,928 | |
| | | | | | | | |
| | | 9,731,199 | | | | 9,377,949 | |
Less allowance for depreciation, depletion, amortization and impairment | | | (5,217,803 | ) | | | (1,000,722 | ) |
| | | | | | | | |
| | | 4,513,396 | | | | 8,377,227 | |
| | | | | | | | |
Goodwill | | | 535,265 | | | | 536,822 | |
| | | | | | | | |
Commodity Derivative Contracts | | | 530,181 | | | | — | |
| | | | | | | | |
Other Assets | | | 56,632 | | | | 104,382 | |
| | | | | | | | |
| | $ | 7,111,915 | | | $ | 9,693,351 | |
| | | | | | | | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | |
Current Liabilities | | | | | | | | |
Accounts payable | | $ | 363,713 | | | $ | 319,583 | |
Commodity derivative contracts | | | — | | | | 79,938 | |
Royalties and revenues payable | | | 87,874 | | | | 132,919 | |
Stock appreciation rights | | | 2,975 | | | | 63,106 | |
Interest payable | | | 20,843 | | | | 25,330 | |
Income taxes payable | | | 102,948 | | | | 3,492 | |
Deferred income taxes | | | 285,426 | | | | — | |
Accrued merger expenses | | | — | | | | 77,980 | |
Other current liabilities | | | 129,866 | | | | 115,698 | |
| | | | | | | | |
| | | 993,645 | | | | 818,046 | |
| | | | | | | | |
Long-Term Debt | | | 2,805,000 | | | | 3,305,000 | |
| | | | | | | | |
Other Long-Term Liabilities | | | | | | | | |
Asset retirement obligation | | | 159,473 | | | | 184,080 | |
Commodity derivative contracts | | | — | | | | 33,821 | |
Other | | | 32,061 | | | | 54,726 | |
| | | | | | | | |
| | | 191,534 | | | | 272,627 | |
| | | | | | | | |
Deferred Income Taxes | | | 744,456 | | | | 1,959,431 | |
| | | | | | | | |
Stockholders’ Equity | | | | | | | | |
Common stock | | | 1,129 | | | | 1,128 | |
Additional paid-in capital | | | 2,739,625 | | | | 2,711,617 | |
Retained earnings (deficit) | | | (85,101 | ) | | | 623,993 | |
Accumulated other comprehensive income | | | (684 | ) | | | 1,566 | |
Treasury stock, at cost | | | (277,689 | ) | | | (57 | ) |
| | | | | | | | |
| | | 2,377,280 | | | | 3,338,247 | |
| | | | | | | | |
| | $ | 7,111,915 | | | $ | 9,693,351 | |
| | | | | | | | |
—MORE—
Page 12
Plains Exploration & Production Company
Consolidated Statements of Cash Flows
(in thousands of dollars)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Twelve Months Ended
December 31, | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| | | (Unaudited) | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | | | | | | | | | | |
Net income (loss) | | $ | (1,568,658 | ) | | $ | 80,003 | | | $ | (709,094 | ) | | $ | 158,751 | |
Items not affecting cash flows from operating activities | | | | | | | | | | | | | | | | |
Gain on sale of assets | | | (31,031 | ) | | | — | | | | (65,689 | ) | | | — | |
Depreciation, depletion, amortization and accretion | | | 200,058 | | | | 128,314 | | | | 621,484 | | | | 316,078 | |
Impairment of oil and gas properties | | | 3,629,666 | | | | — | | | | 3,629,666 | | | | — | |
Deferred income tax expense (benefit) | | | (878,381 | ) | | | 57,231 | | | | (675,350 | ) | | | 114,425 | |
Debt extinguishment costs | | | 4,855 | | | | — | | | | 18,256 | | | | — | |
Commodity derivative contracts | | | (1,165,742 | ) | | | 12,967 | | | | (1,555,917 | ) | | | 88,549 | |
Noncash compensation | | | 11,470 | | | | 25,278 | | | | 50,401 | | | | 52,019 | |
Other noncash items | | | 2,316 | | | | 487 | | | | 6,546 | | | | 707 | |
Change in assets and liabilities from operating activities | | | 19,917 | | | | (1,929 | ) | | | 51,106 | | | | (142,417 | ) |
| | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | | 224,470 | | | | 302,351 | | | | 1,371,409 | | | | 588,112 | |
| | | | | | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | | | | | | | | | |
Additions to oil and gas properties | | | (428,510 | ) | | | (294,095 | ) | | | (1,116,715 | ) | | | (770,409 | ) |
Acquisition of oil and gas properties | | | 6,842 | | | | — | | | | (2,006,127 | ) | | | (975,407 | ) |
Acquisition of Pogo Producing Company, net of cash acquired | | | (1,041 | ) | | | (298,031 | ) | | | (77,686 | ) | | | (298,031 | ) |
Decrease (increase) in restricted cash | | | — | | | | (59,092 | ) | | | 59,092 | | | | (59,092 | ) |
Proceeds from sales of oil and gas properties and related assets, net of costs and expenses | | | 1,233,886 | | | | — | | | | 2,969,945 | | | | — | |
Derivative settlements | | | 27,606 | | | | (25,102 | ) | | | (8,606 | ) | | | (99,861 | ) |
Additions to other property and equipment | | | (9,988 | ) | | | (7,588 | ) | | | (44,436 | ) | | | (36,176 | ) |
Other, net | | | (1,586 | ) | | | 6,708 | | | | (3,257 | ) | | | (4,161 | ) |
| | | | | | | | | | | | | | | | |
Net cash (used in) provided by investing activities | | | 827,209 | | | | (677,200 | ) | | | (227,790 | ) | | | (2,243,137 | ) |
| | | | | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | | | | | | | | | |
Revolving credit facilities | | | | | | | | | | | | | | | | |
Borrowings | | | 2,829,694 | | | | 2,755,535 | | | | 14,331,046 | | | | 4,745,100 | |
Repayments | | | (3,558,825 | ) | | | (1,030,535 | ) | | | (15,231,046 | ) | | | (2,775,600 | ) |
Proceeds from issuance of Senior Notes | | | — | | | | — | | | | 400,000 | | | | 1,100,000 | |
Redemption of long-term debt | | | — | | | | (1,291,926 | ) | | | — | | | | (1,291,926 | ) |
Costs incurred in connection with financing arrangements | | | (2,079 | ) | | | (29,151 | ) | | | (27,527 | ) | | | (47,333 | ) |
Derivative settlements | | | (1,581 | ) | | | (3,688 | ) | | | (25,678 | ) | | | (3,688 | ) |
Purchase of treasury stock | | | — | | | | — | | | | (304,192 | ) | | | (47,485 | ) |
Other | | | (9,440 | ) | | | (4,537 | ) | | | 207 | | | | 504 | |
| | | | | | | | | | | | | | | | |
Net cash (used in) provided by financing activities | | | (742,231 | ) | | | 395,698 | | | | (857,190 | ) | | | 1,679,572 | |
| | | | | | | | | | | | | | | | |
Net increase in cash and cash equivalents | | | 309,448 | | | | 20,849 | | | | 286,429 | | | | 24,547 | |
Cash and cash equivalents, beginning of period | | | 2,427 | | | | 4,597 | | | | 25,446 | | | | 899 | |
| | | | | | | | | | | | | | | | |
Cash and cash equivalents, end of period | | $ | 311,875 | | | $ | 25,446 | | | $ | 311,875 | | | $ | 25,446 | |
| | | | | | | | | | | | | | | | |
—MORE—
Page 13
Plains Exploration & Production Company
Summary of Open Derivative Positions
| | | | | | | | | | | | |
Period | | Instrument Type | | Daily Volumes | | Average Price | | Deferred Premium | | Index | | Settlement |
Sales of Crude Oil Production | | | | | | | | | | |
2009 | | | | | | | | | | | | |
Jan - Dec | | Put options | | 32,500 Bbls | | $55.00 Strike price | | $3.38 per Bbl | | WTI | | Monthly |
| | | | | | |
2010 | | | | | | | | | | | | |
Jan - Dec | | Put options(1) | | 40,000 Bbls | | $55.00 Strike price | | $5.00 per Bbl | | WTI | | Monthly |
| | | | | |
Sales of Natural Gas Production | | | | | | | | | | |
2009 | | | | | | | | | | | | |
Jan - Dec | | Collar | | 150,000 MMBtu | | $10.00 Floor - $20.00 Ceiling | | $0.346 per MMBtu | | Henry Hub | | Monthly |
| | | | | | |
2010 | | | | | | | | | | | | |
Jan - Dec | | Put/Call(2) | | 40,000 MMBtu | | $6.25 Floor -$4.80 | | No premium | | Henry Hub | | Monthly |
| | | | | | Floor by $8.00 Ceiling | | | | | | |
(1) | An upfront payment of $3.86 per barrel was paid upon entering into these derivative contracts. |
(2) | The Company receives the difference between the floor of $6.25 per MMBtu less NYMEX up to a maximum of $1.45 per MMBtu. The Company pays if NYMEX is greater than the $8.00 ceiling. |
—MORE—
Page 14
Plains Exploration & Production Company
GAAP to Non-GAAP Reconciliation
The following chart reconciles Net Cash Provided by Operating Activities (GAAP) to Operating Cash Flow (non-GAAP) for the periods highlighted below. 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 gain on the sales of oil and gas properties and changes in operating assets and liabilities and include derivative cash flows that are classified as a financing or investing activity in the statement of cash flows. Pursuant to accounting rules certain cash payments with respect to our derivative instruments are required to be reflected as financing or investing activities.
| | | | | | | | | | | | | | | | | | | | |
| | | 2008 | |
| (in millions of dollars) | | Total | | | 4Q | | | 3Q | | | 2Q | | | 1Q | |
Net cash provided by operating activities (GAAP) | | $ | 1,371.4 | | | $ | 224.5 | | | $ | 537.6 | | | $ | 324.6 | | | $ | 284.8 | |
Changes in operating assets and liabilities | | | (51.1 | ) | | | (19.9 | ) | | | (264.9 | ) | | | 146.5 | | | | 87.2 | |
Current income taxes on the tax gain on sale of oil and gas properties | | | 230.8 | | | | 62.2 | | | | 168.6 | | | | — | | | | — | |
Cash receipts (payments) for commodity derivatives contracts that settled during the period that are reflected as investing or financing cash flows in the statement of cash flows | | | (34.3 | ) | | $ | 26.0 | | | | (17.6 | ) | | | (20.8 | ) | | | (21.8 | ) |
| | | | | | | | | | | | | | | | | | | | |
Operating cash flow (Non-GAAP) | | $ | 1,516.8 | | | $ | 292.8 | | | $ | 423.7 | | | $ | 450.3 | | | $ | 350.2 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
| | | Full Year | | | Full Year | | | | | | 4th Qtr | | | 4th Qtr | |
| (in millions of dollars) | | 2008 | | | 2007 | | | | | | 2008 | | | 2007 | |
Net cash provided by operating activities (GAAP) | | $ | 1,371.4 | | | $ | 588.1 | | | | | | | $ | 224.5 | | | $ | 302.3 | |
Changes in operating assets and liabilities | | | (51.1 | ) | | | 142.4 | | | | | | | | (19.9 | ) | | | 1.9 | |
Current income taxes on the tax gain on sale of oil and gas properties | | | 230.8 | | | | — | | | | | | | | 62.2 | | | | — | |
Cash receipts (payments) for commodity derivatives contracts that settled during the period that are reflected as investing or financing cash flows in the statement of cash flows | | | (34.3 | ) | | | (103.5 | ) | | | | | | | 26.0 | | | | (28.8 | ) |
| | | | | | | | | | | | | | | | | | | | |
Operating cash flow (Non-GAAP) | | $ | 1,516.8 | | | $ | 627.0 | | | | | | | $ | 292.8 | | | $ | 275.4 | |
| | | | | | | | | | | | | | | | | | | | |
—MORE—
Page 15
Plains Exploration & Production Company
Reconciliation of GAAP to Non-GAAP Measure
The following table reconciles net income (loss) (GAAP) to net income (loss) excluding certain items (Non-GAAP) for the three months and twelve months ended December 31, 2008 and 2007. 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 or are nonrecurring. Management believes this presentation may be helpful to investors. 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.
| | | | | | | | |
| | | Three Months Ended
December 31, | |
| | | 2008 | | | 2007 | |
| | | (millions of dollars) | |
Net income (loss) (GAAP) | | $ | (1,568.7 | ) | | $ | 80.0 | |
Impairment of oil and gas properties | | | 3,629.7 | | | | — | |
Gain (loss) on mark-to-market derivative contracts | | | (1,165.7 | ) | | | 13.0 | |
Cash receipts (payments) on mark-to-market derivative contracts | | | 26.0 | | | | (28.8 | ) |
Gain on sale of assets | | | (31.0 | ) | | | — | |
Adjust income taxes | | | (923.4 | ) | | | 6.0 | |
| | | | | | | | |
Net income (loss) excluding certain items (Non-GAAP) | | $ | (33.1 | ) | | $ | 70.2 | |
| | | | | | | | |
| |
| | | Year Ended
December 31, | |
| | | 2008 | | | 2007 | |
| | | (millions of dollars) | |
Net income (loss) (GAAP) | | $ | (709.1 | ) | | $ | 158.8 | |
Impairment of oil and gas properties | | | 3,629.7 | | | | — | |
Gain (loss) on mark-to-market derivative contracts | | | (1,555.9 | ) | | | 88.5 | |
Cash receipts (payments) on mark-to-market derivative contracts | | | (34.3 | ) | | | (103.5 | ) |
Gain on sale of assets | | | (65.7 | ) | | | — | |
Adjust income taxes | | | (741.2 | ) | | | 5.7 | |
| | | | | | | | |
Net income excluding certain items (Non-GAAP) | | $ | 523.5 | | | $ | 149.5 | |
| | | | | | | | |
—MORE—
Page 16
Plains Exploration & Production Company
Full-Year 2009 Operating and Financial Guidance
| | |
| | | Year Ended
December 31, 2009 |
Production Volumes (MBOE/day) | | |
Production volumes sold | | 78.0 – 82.0 |
% Oil | | 55% |
% Gas | | 45% |
Price Realization % Index (Unhedged) | | |
Oil - NYMEX | | 80% – 82% |
Gas - Henry Hub | | 87% – 90% |
| |
Production Costs per BOE | | |
Lease operating expense | | $9.20 – $9.55 |
Steam gas costs (1) | | $2.20 – $2.45 |
Electricity | | $1.45 – $1.65 |
Production and ad valorem taxes | | $1.70 – $1.90 |
Gathering and transportation | | $0.85 – $0.95 |
| |
Depreciation, Depletion and Amortization per BOE(2) | | $12.00 – $14.00 |
| |
General and Administrative Expenses ($/millions) | | |
Cash | | $87 – $92 |
Stock based compensation (3) | | $54 – $59 |
Interest Expense | | |
Average revolver balance | | 30 Day LIBOR+1.75% |
$400 Million Senior Notes | | 7.625% |
$500 Million Senior Notes | | 7.000% |
$600 Million Senior Notes | | 7.750% |
| |
Effective Tax Rate | | 35% – 40% |
| |
Weighted Average Equivalent Shares Outstanding (in thousands) | | |
Basic | | 108,000 |
Diluted | | 110,000 |
| |
Capital Expenditures ($/millions) | | $1,050 |
| |
Derivative Instruments | | |
Crude Oil Put Options | | |
Bbls / day | | 32,500 |
Floor | | $55.00 |
Option premium and interest ($/Bbl) | | $3.38 |
Natural Gas Collars | | |
MMbtu / day | | 150,000 |
Ceiling | | $20.00 |
Floor | | $10.00 |
Option premium and interest ($/MMbtu) | | $0.346 |
(1) | Steam gas costs assume a base SoCal Border index price of $4.50 per MMBtu. |
| | The purchased volumes are anticipated to be 40,000—46,000 MMBtu per day. |
(3) | Based on current outstanding and projected awards and current stock price. |
###
