Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - PLAINS EXPLORATION & PRODUCTION CO | d294466d8k.htm |
| EX-99.2 - PRESENTATION - PLAINS EXPLORATION & PRODUCTION CO | d294466dex992.htm |
Exhibit 99.1
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Plains Exploration & Production Company 700 Milam, Suite 3100, Houston, TX 77002 www.pxp.com |
NEWS RELEASE
FOR IMMEDIATE RELEASE
PXP PROVIDES PRELIMINARY 2011 FULL-YEAR OPERATIONAL RESULTS
ACHIEVES RECORD SALES VOLUMES ON
CONTINUED EXPANSION OF THE EAGLE FORD SHALE DEVELOPMENT
REPORTS SUBSTANTIAL INCREASE IN PROVED RESERVE VALUE
DELIVERS SOLID PROVED RESERVE REPLACEMENT ON
TOTAL RESERVES AND OIL/LIQUIDS RESERVES
STRENGTHENS FUTURE CASH FLOW BY ACQUIRING
ADDITIONAL 2013 AND NEW 2014 CRUDE OIL DERIVATIVES
2011 Fourth-Quarter Average Daily Sales Volumes:
| • | Daily sales increased 13% to 105,396 barrels of oil equivalent (BOE) per day, or 26% pro forma for asset sales, compared to fourth-quarter 2010 |
| • | Oil/liquids volumes increased 12% to 52,262 barrels per day, or 16% pro forma for asset sales, compared to fourth-quarter 2010 |
2011 Full-Year Average Daily Sales Volumes:
| • | Daily sales increased 12% to 98,950 BOE per day, or 23% pro forma for asset sales, compared to 2010 |
| • | Oil/liquids volumes increased 7% to 48,964 barrels per day, or 8% pro forma for asset sales, compared to 2010 |
2011 Total Proved Reserves:
| • | Total proved reserves, pro forma for asset sales, increased 16% to 410.9 million BOE |
| • | Standardized measure of discounted net cash flows increased 66% to $5.1 billion from $3.1 billion in 2010 |
| • | PV-10 value increased 58% to $7.9 billion from $5.0 billion in 2010 |
| • | Reserve replacement is 222% or 290% pro forma for asset sales |
2011 Oil/Liquids Proved Reserves:
| • | Oil/liquids reserves, pro forma for asset sales, increased 18% to 244.0 million barrels |
| • | Oil/liquids are 59% of total proved, up from 54% in 2010 |
| • | Oil/liquids reserve replacement is 280% |
| • | Oil/liquids reserve-to-pro forma production ratio is 14 years |
Houston, Texas, February 7, 2012 - Plains Exploration & Production Company (NYSE:PXP) (“PXP” or the “Company”) today reported preliminary 2011 operational results and an update to its derivative position.
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DAILY SALES VOLUMES
PXP’s 2011 fourth-quarter daily sales volumes averaged 105,396 BOE per day, a 13% increase over 92,994 BOE per day in the fourth-quarter of 2010. Adjusting for the 2010 and 2011 asset divestments, the 13% sales volume increase would have been 26% and 2011 fourth-quarter daily sales volumes would have averaged 90,349 BOE per day.
PXP’s 2011 fourth-quarter oil/liquids daily sales volumes averaged 52,262 barrels per day, a 12% increase over 46,658 barrels per day in the fourth-quarter 2010. Adjusting for the 2010 and 2011 asset divestments, the 12% sales volume increase would have been 16% and 2011 fourth-quarter daily sales volumes would have averaged 47,464 barrels per day.
The robust volume growth is driven primarily by strong performance in the Eagle Ford Shale and Haynesville Shale asset areas combined with steady, consistent performance in California.
In the Eagle Ford Shale, fourth-quarter daily sales volumes averaged approximately 9,123 BOE per day net to PXP, compared to approximately 1,500 BOE per day net to PXP from November acquisition to end of the fourth-quarter 2010. January 2012 volumes averaged approximately 13,700 BOE per day compared to approximately 1,970 BOE per day net to PXP in January 2011. The Company had 6.9 net rigs operating on its acreage at the end of January.
In California, fourth-quarter average daily sales volumes were 40,003 BOE per day, essentially flat compared to the fourth-quarter 2010; and in the Haynesville Shale, fourth-quarter average daily sales volumes were approximately 200 million cubic feet equivalent (MMcfe) net to PXP compared to approximately 146 MMcfe in the fourth-quarter 2010.
PXP’s 2011 full-year daily sales volumes averaged approximately 98,950 BOE per day, a 12% increase over full-year 2010 volumes of 88,451 BOE per day. Adjusting for the 2010 and 2011 asset divestments, the 12% sales volume increase would have been 23% and 2011 full-year daily sales volumes would have averaged 82,197 BOE per day.
PXP’s 2011 full-year oil/liquids daily sales volumes averaged 48,964 barrels per day, a 7% increase over 45,943 barrels per day in 2010. Adjusting for the 2010 and 2011 asset divestments, the 7% sales volume increase would have been 8% and 2011 fourth-quarter daily sales volumes would have averaged 43,858 barrels per day.
PROVED RESERVES
Year-end estimated proved reserves of 410.9 million BOE, net of asset sales, were 59% oil, 55% developed and had a pre-tax PV-10 value of $7.9 billion, a 58% increase over 2010 PV-10 value. The robust increase in the PV-10 value is primarily attributable to a greater concentration of oil/liquids reserves, higher oil/liquids reference prices and stronger marketing contract terms for oil sales. Pro forma for asset sales, proved reserves increased 16% over 2010 proved reserves.
In 2011, PXP added total proved reserves of 81.0 million BOE. The Company reported a total of 75.2 million BOE of extensions and discoveries, including 22.5 million BOE in the Eagle Ford Shale, 19.3 million BOE in the Gulf of Mexico, and 25.5 million BOE in the Haynesville Shale, 4.3 million BOE of acquisitions and 1.5 million BOE of revisions. These additions replaced 222% of 2011 production. Pro forma for asset sales, PXP replaced 290% of 2011 production.
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Oil/liquids proved reserves increased 9%, or 18% pro forma for asset sales, due primarily to the rapidly expanding Eagle Ford Shale asset area, project sanctioning of the Lucius development located in the Gulf of Mexico, and a higher oil reference price compared to 2010 resulting in positive price related revisions in California.
Natural gas proved reserves decreased 13% due primarily to the 2011 asset sales. With persistent low natural gas prices and a corresponding assumed reduction in the pace of development in the Haynesville Shale, PXP classified 44 million BOE of its Haynesville undeveloped reserves as probable undeveloped. These reserves meet the reasonable certainty, economic and other conditions needed to be classified as proved undeveloped reserves but the slower pace of drilling extends the development of these reserves past five years.
PXP’s reserve estimate, the Standardized Measure and PV-10 calculations are based on the twelve-month average of first-day-of-the-month West Texas Intermediate spot oil price of $95.99 per barrel and Henry Hub spot natural gas price of $4.12 per million British thermal unit. All prices were adjusted for energy content, quality and basis differentials by area and were held constant through the lives of the properties, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A detailed breakdown of reserves and costs incurred for 2011 will be provided when PXP reports full-year results on February 23, 2012. The following tables provide summary reconciliations.
Estimated Proved Reserves (MMBOE)
| 2010 Year-end proved reserves |
416.1 | |||
| 2011 Extensions, discoveries, revisions and other additions |
81.0 | |||
| 2011 Divestments |
(49.7 | ) | ||
| 2011 Production |
(36.5 | ) | ||
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|||
| 2011 Year-end proved reserves |
410.9 | |||
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| Reserve replacement ratio (1) |
222 | % |
Estimated Pro Forma Proved Reserves (MMBOE) (2)
| 2010 Year-end proved reserves |
355.0 | |||
| 2011 Extensions, discoveries, revisions and other additions |
88.1 | |||
| 2011 Divestments |
(1.8 | ) | ||
| 2011 Pro forma production |
(30.4 | ) | ||
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|
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|||
| 2011 Year-end proved reserves |
410.9 | |||
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| Pro forma reserve replacement ratio (1) |
290 | % |
| (1) | Calculation: reserve extensions, discoveries, revisions, and other additions divided by production. The Reserve Replacement Ratio is an indicator of PXP’s ability to replace annual production volume and grow reserves. It is important to economically find and develop new reserves that offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced. This statistical indicator has limitations, including its predictive and comparative value. As such, this metric should not be considered in isolation or as a substitute for an analysis of PXP’s performance as reported under GAAP. Furthermore, this metric may not be comparable to similarly titled measurements used by other companies. |
| (2) | Reflects the impact of the fourth-quarter property divestments. |
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PV-10 to Standardized Measure Reconciliation (in millions)
| Estimated undiscounted future net cash flows before income taxes |
$ | 15,942.2 | ||
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| Present value of estimated future net cash flows before income taxes (PV-10) (1) (2) |
$ | 7,884.5 | ||
| Discounted future income taxes |
(2,750.3 | ) | ||
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| Standardized measure of discounted net cash flows |
$ | 5,134.2 | ||
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| (1) | PV-10 is PXP’s estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. PV-10 is a non-GAAP, financial measure and generally differs from the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the Standardized Measure as computed under GAAP. |
| (2) | PXP believes PV-10 to be an important measure for evaluating the relative significance of its oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, PXP believes the use of a pre-tax measure is valuable for evaluating its company. PXP believes that most other companies in the oil and gas industry calculate PV-10 on the same basis. |
DEPRECIATION, DEPLETION AND AMORTIZATION
2011 fourth-quarter depreciation, depletion and amortization (DD&A) is expected to be $21.79 per BOE. For the full-year 2011, DD&A is expected to be $18.40 per BOE.
DERIVATIVE UPDATE
PXP converted 5,000 of the 22,000 barrels of oil per day (BOPD) of Brent crude oil put option contracts in 2013 to three-way collars. These modified three-way collars have a floor price of $90 per barrel with a limit of $70 per barrel and a weighted average ceiling price of $126.08 and eliminates approximately $11 million of deferred premiums. PXP will continue to lower the deferred premiums by converting put option spread contracts into three-way collars.
Additionally, the Company entered into the following Brent oil derivatives for 2013 and 2014:
| • | Brent crude oil put option spread contracts on 13,000 BOPD for 2013 with a floor price of $100 per barrel and a limit of $80 per barrel. |
| • | Brent three-way collars on 25,000 BOPD for 2013 that have a floor price of $100 per barrel with a limit of $80 per barrel and a weighted average ceiling price of $124.29 per barrel. |
| • | Brent crude oil put option spread contracts on 20,000 BOPD for 2014 with a floor price of $90 per barrel and a limit of $70 per barrel. |
PXP has elected not to use hedge accounting for these derivatives and consequently the derivatives will be marked-to-market with fair value gains and losses recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement.
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As of February 7, 2012, PXP had the following outstanding commodity derivative contracts, all of which settle monthly:
| Period |
Instrument Type |
Daily Volumes |
Average Price (1) |
Average Deferred Premium |
Index | |||||
| Sales of Crude Oil Production |
||||||||||
| 2012 |
||||||||||
| Feb - Dec |
Three-way collars (2) | 40,000 Bbls | $100.00 Floor with a $80.00 Limit $120.00 Ceiling |
— | Brent | |||||
| 2013 |
||||||||||
| Jan - Dec |
Put options (3) | 17,000 Bbls | $90.00 Floor with a $70.00 Limit | $6.253 per Bbl | Brent | |||||
| Jan - Dec |
Put options (4) | 13,000 Bbls | $100.00 Floor with a $80.00 Limit | $6.800 per Bbl | Brent | |||||
| Jan - Dec |
Three-way collars (5) | 25,000 Bbls | $100.00 Floor with a $80.00 Limit $124.29 Ceiling |
— | Brent | |||||
| Jan - Dec |
Three-way collars (6) | 5,000 Bbls | $90.00 Floor with a $70.00 Limit $126.08 Ceiling |
— | Brent | |||||
| 2014 |
||||||||||
| Jan - Dec |
Put options (7) | 20,000 Bbls | $90.00 Floor with a $70.00 Limit | $6.555 per Bbl | Brent | |||||
| Sales of Natural Gas Production |
||||||||||
| 2012 |
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| Feb - Dec |
Put options (8) | 120,000 MMBtu | $4.30 Floor with a $3.00 Limit | $0.298 per MMBtu | Henry Hub | |||||
| Feb - Dec |
Three-way collars (9) | 40,000 MMBtu | $4.30 Floor with a $3.00 Limit $4.86 Ceiling |
— | Henry Hub | |||||
| 2013 |
||||||||||
| Jan - Dec |
Swap contracts (10) | 110,000 MMBtu | $4.27 | — | Henry Hub | |||||
| (1) | The average strike prices do not reflect any premiums to purchase the put options. |
| (2) | If the index price is less than the $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $120 per barrel if the index price is greater than the $120 per barrel ceiling. If the index price is at or above $100 per barrel but at or below $120 per barrel, no cash settlement is required. |
| (3) | If the index price is less than the $90 per barrel floor, we receive the difference between the $90 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. If the index price is at or above $90 per barrel, we pay only the option premium. |
| (4) | If the index price is less than the $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. If the index price is at or above $100 per barrel, we pay only the option premium. |
| (5) | If the index price is less than the $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $124.29 per barrel if the index price is greater than the $124.29 per barrel ceiling. If the index price is at or above $100 per barrel but at or below $124.29 per barrel, no cash settlement is required. |
| (6) | If the index price is less than the $90 per barrel floor, we receive the difference between the $90 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $126.08 per barrel if the index price is greater than the $126.08 per barrel ceiling. If the index price is at or above $100 per barrel but at or below $126.08 per barrel, no cash settlement is required. |
| (7) | If the index price is less than the $90 per barrel floor, we receive the difference between the $90 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. If the index price is at or above $90 per barrel, we pay only the option premium. |
| (8) | If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium. If the index price is at or above $4.30 per MMBtu, we pay only the option premium. |
| (9) | If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu. We pay the difference between the index price and $4.86 per MMBtu if the index price is greater than the $4.86 per MMBtu ceiling. If the index price is at or above $4.30 per MMBtu but at or below $4.86 per MMBtu, no cash settlement is required. |
| (10) | If the index price is less than the $4.27 per MMBtu fixed price, we receive the difference between the $4.27 per MMBtu fixed price and the index price. We pay the difference between the index price and the fixed price if the index price is greater than the fixed price. |
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CREDIT SUISSE ENERGY SUMMIT
PXP is scheduled to present at the 2012 Credit Suisse Energy Summit on Tuesday, February 7, 2012 at 8:45 a.m. Mountain time. A live webcast and a copy of the presentation will be available in the Investor Information section of PXP’s website at www.pxp.com.
EARNINGS CONFERENCE CALL
PXP is scheduled to release 2011 fourth-quarter and year-end results on Thursday, February 23, 2012 before the market opens and will host its quarterly conference call that same day 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 conference call and replay ID is: 42174570. The replay can be accessed by dialing 1-855-859-2056 or 1-404-537-3406. A live webcast of the conference call and a slide presentation will be available in the Investor Information section of PXP’s website at 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 statement. 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,
* 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 a discussion of these risks.
References to quantities of oil or natural gas may include amounts that the Company believes will ultimately be produced, but that are not yet classified as “proved reserves” under SEC definitions.
All forward-looking statements in this press release 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 press release 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 as required by law, we do not intend to update these forward-looking statements and information.
Contact: Hance Myers: hmyers@pxp.com; 713.579.6291
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