PXP Announces 2009 Fourth Quarter & Full-Year Results
HOUSTON, Feb. 25 /PRNewswire-FirstCall/ -- Plains Exploration & Production Company (NYSE: PXP) ("PXP" or the "Company") announces 2009 fourth quarter and full-year financial and operating results, and updates its 2010 full-year guidance.
FINANCIAL HIGHLIGHTS
- For the fourth quarter, revenues of $367.7 million generated $48.1 million of net income, or $0.34 per diluted share. These results include certain items affecting comparability of operating results. Those items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts and other items. When considering these items, net income was $192.6 million, or $1.37 per diluted share (a non-GAAP measure). Net cash provided by operating activities was $189.2 million while operating cash flow was $465.5 million (a non-GAAP measure).
- For the year, revenues of $1.2 billion generated $136.3 million of net income, or $1.09 per diluted share. These results include certain items affecting comparability of operating results. Those items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts and other items. When considering these items, net income was $676.0 million, or $5.40 per diluted share (a non-GAAP measure). Net cash provided by operating activities was $499.0 million while operating cash flow was $1.6 billion (a non-GAAP measure).
A reconciliation of non-GAAP financial measures used in this release to comparable GAAP financial measures is included with the financial tables.
OPERATIONAL HIGHLIGHTS
- Proved reserves increased 23% during 2009 to 359.5 million barrels of oil equivalent (BOE); reserve replacement was 320%.
- Finding and development costs, excluding acquisition costs, which are primarily related to the Haynesville Shale drilling carry pre-payment, and our Haynesville Shale promoted well costs, were $12.61 per BOE (a non-GAAP measure).
- Full-year average daily sales volumes of 82.7 thousand BOE increased 8% during 2009, excluding the impact of our 2008 divestments, and exceeded published targets.
- Total production costs per BOE decreased 32% to $12.89 compared to the fourth quarter 2008. For the year, total production costs per BOE were $14.03, well below published targets.
- PXP announced Friesian delineation drilling success and participated in discoveries at Davy Jones, Lucius, and Blueberry Hill. For Friesian, early stage commercialization initiatives for production are under study. The Lucius discovery announced in December 2009 was followed by a successful appraisal well in late January 2010 which confirmed a major oil discovery. Appraisal and further drilling will continue in 2010 at Lucius, Davy Jones and Blueberry Hill. These projects have the potential to provide significant incremental future production and reserve growth.
- The Flatrock development contributed meaningful sales volume growth during 2009. During the year a planned facility expansion was completed, and at year-end 2009, production averaged over 62 million cubic feet equivalent (MMCFE) per day net to PXP.
- The Haynesville Shale drilling results have been outstanding and finding and development and full-cycle costs are some of the most attractive in the industry. The fourth quarter average daily production of approximately 75 MMCFE net to PXP represents a 436% increase from the first quarter 2009. Production is expected to continue to increase to approximately 125 MMCFE net per day by year-end 2010.
James C. Flores, Chairman, President and CEO of PXP commented, "As our industry faced commodity price volatility and significant economic uncertainty throughout the year, we applied our experience, remained focused on our long-term growth platform, and executed our strategic plans. The quality of our people and portfolio continue to standout as we reported significant progress in growing production and reserves, lowering costs, strengthening liquidity and expanding our resource potential during today's challenging environment.
"During 2009, sales volumes increased 8% over 2008, excluding the impact of our 2008 divestments, and exceeded published targets. Proved reserves increased 23% to 359.5 million BOE, reserve replacement was 320% and finding and development costs, excluding acquisition costs, which are primarily related to the Haynesville Shale drilling carry pre-payment, and Haynesville Shale promoted well costs, were $12.61 per BOE. Our Gulf of Mexico exploration program yielded a number of discoveries adding to our future development project inventory and increasing our average annual production growth target to 15%, up from 10%, through 2014. Our average annual reserve growth target is 20% over the next several years.
"We are mindful of our need to protect our balance sheet, liquidity and operating efficiencies as we continue to pursue our balanced operational strategy. During 2009, PXP monetized $1.1 billion in commodity derivative gains, which accelerated cash receipts, entered into 2010 crude oil derivative positions and acquired natural gas collars for 2010 to maintain the Company's strong derivative position, issued senior notes and common stock, pre-paid the Haynesville Shale drilling carry in order to unlock potential capital for PXP's other high-quality assets, and reduced general and administrative costs and lease operating expenses in excess of our stated targets. PXP ended the year with no near-term debt maturities and nearly $990 million available under its revolving credit facility.
"Our 2010 $1.2 billion capital spending plan leverages on PXP's 2009 accomplishments and the contribution from multiple assets. Our resources will be primarily directed to the Haynesville Shale, continued development activities in California, South Texas and the Panhandle, and our exploration and development projects in the Gulf Coast and Gulf of Mexico.
- In California, we continue our strategy of maintaining our strong production volumes while simultaneously developing our incremental diatomite, non-diatomite and Miocene projects. California onshore is PXP's largest asset area with approximately 204 million BOE of proved reserves at year-end 2009. With a multi-year inventory identified in the San Joaquin Valley, the Arroyo Grande Field, and the Los Angeles Basin, these asset areas will sustain multi-year drilling programs providing future reserves, production and free cash flow.
- In the Haynesville Shale, we continue to see outstanding drilling results. The fourth quarter average daily production was approximately 75 MMCFE net to PXP, and production is expected to continue to increase to approximately 125 MMCFE net per day by year-end 2010. During 2010, Chesapeake is expected to operate an average of approximately 40 rigs and other operators are expected to operate 15 or more rigs on our acreage.
- In the Gulf of Mexico, we viewed 2009 as a year of identification and look to 2010 as the year of confirmation. We are planning follow-up drilling at our Davy Jones and Lucius discoveries and new drilling at our Blackbeard East and Phobos exploratory opportunities in which PXP has a 26.25% and 50% working interest, respectively. Our highly successful Flatrock development contributed meaningful sales volume growth during 2009. We are drilling Blueberry Hill to expand upon our Flatrock success.
- In the Texas Panhandle, we look forward to drilling our Granite and Atoka Wash positions in which PXP holds approximately 19,500 net acres. We recently spud our first horizontal test well and expect to spud a second test well in early second quarter 2010. A total of 14 wells are planned in 2010 out of the approximately 58 primary Granite Wash locations.
- In the Gulf Coast, we are planning to test our Big Mac project in Southeast Texas during the second quarter of this year. We have documented about 30 to 40 leads, all amplitude driven.
"We have a balanced, geographically diverse, lower-risk portfolio of producing properties that underpin our long-term growth strategy, an attractive portfolio of other longer term value-enhancing projects, a total resource potential of over 2 billion BOE, financial liquidity, and a talented and dedicated workforce.
"Our Corporate goal is to double production and reserves by 2014, remain balanced between oil and gas, and continue reducing total production costs per BOE. We begin 2010 positioned to continue efficiently growing production and reserves per share with contribution from multiple asset areas over the next several years. Our base production will continue to benefit from stable California production and Haynesville Shale growth. Our Granite Wash, Blueberry Hill and Big Mac opportunities support near-term incremental growth targets while our Friesian, Davy Jones and Lucius projects support our longer-term growth targets. Our current business model incorporates production contribution from three Gulf of Mexico projects, one per year for three years starting in 2012, which have the potential to increase the corporate target growth rate to 15% through 2014. We believe our balanced portfolio of assets, our 2009 deleveraging transactions, and ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities."
PROVED RESERVES
Year-end estimated proved reserves of 359.5 million BOE were 60% oil and 64% proved developed. We have a total proved reserve life of approximately 11 years and a proved developed reserve life of approximately 7 years.
In December 2008, the SEC issued new guidelines which are effective for reporting 2009 reserve information. The primary impacts of the SEC's final rule on our reserve estimates are as follows:
- The use of the twelve-month average first-day-of-the-month reference prices (prior to adjustment for location and quality differentials) of $61.18 per Bbl for oil and $3.87 per MMBtu for natural gas compared to the year-end reference prices (prior to adjustment for location and quality differentials) of $79.36 per Bbl for oil and $5.79 per MMBtu for natural gas.
- The new guidelines limit the booking of proved undeveloped reserves that are scheduled to be developed beyond five years. Certain of PXP's undeveloped locations are not scheduled to be developed within five years and were excluded from our proved reserves, resulting in a negative revision of 25 million BOE.
- The new guidelines expanded the definition of proved undeveloped reserves that can be booked from a proved developed well location. PXP was able to support with reasonable certainty proved undeveloped reserves for certain horizontal locations in the Haynesville Shale, more than the two parallel offsets from a proved developed well location allowed under the previous guidelines. The impact increased our proved undeveloped reserves by 11 million BOE.
In 2009, PXP had approximately 57 million BOE of extensions and discoveries, including approximately 53 million BOE in the Haynesville Shale resulting from successful drilling during 2009 that extended and developed the proved acreage and approximately 2 million BOE of extensions and discoveries in the Gulf of Mexico, primarily attributable to continued success in the Flatrock area.
PXP had a total of 2 million BOE of proved reserves additions related to interests acquired in the Haynesville Shale and had net positive revisions of approximately 39 million BOE. Positive revisions of 77 million BOE were primarily related to higher oil prices principally at PXP's California properties and negative revisions of 13 million BOE mostly related to lower gas prices. Under the SEC's final rule, prior period reserves were not restated. A summary of the proved reserve reconciliation and costs incurred for 2009 is included with the financial tables.
2010 FULL-YEAR GUIDANCE
PXP updates its 2010 full-year financial and operational guidance originally filed with the SEC in a Form 8-K on November 5, 2009. The complete guidance table is included at the end of this release. The updates include:
- Depreciation, depletion and amortization expense is expected to be $16.00 to $18.00 per BOE for 2010.
- Capital spending is estimated to be approximately $1.2 billion, including capitalized interest expense and general and administrative expense. The budget reflects additional spending on our Gulf of Mexico discoveries, Davy Jones and Lucius, and our Phobos and Blackbeard East exploration prospects.
CONFERENCE CALL
PXP will host a conference call today, Thursday, February 25, 2010 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: 50568720. The replay will be available through Thursday, March 11, 2010 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.
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 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 as required by law, we do not intend to update these forward-looking statements and information.
Plains Exploration & Production Company
Consolidated Statements of Income
(amounts in thousands, except per share data)
Three Months Ended Twelve Months Ended
December 31, December 31,
------------ ------------
2009 2008 2009 2008
---- ---- ---- ----
(Unaudited)
Revenues
Oil sales $277,324 $235,539 $903,146 $1,766,677
Gas sales 89,745 91,512 281,978 619,886
Other operating
revenues 680 1,103 2,006 16,908
--- ----- ----- ------
367,749 328,154 1,187,130 2,403,471
------- ------- --------- ---------
Costs and Expenses
Lease operating
expenses 56,352 90,713 250,916 327,412
Steam gas costs 16,376 20,981 53,801 131,156
Electricity 9,996 16,070 43,891 52,735
Production and ad
valorem taxes 8,713 16,231 38,708 93,988
Gathering and
transportation
expenses 10,984 5,781 36,651 21,137
General and
administrative 33,520 38,801 144,586 153,306
Depreciation,
depletion and
amortization 126,557 196,890 407,248 608,448
Impairment of oil
and gas
properties - 3,629,666 - 3,629,666
Accretion 3,704 3,168 14,332 13,036
Legal recovery - - (87,272) -
Other operating
expense 583 - 2,136 -
--- --- ----- ---
266,785 4,018,301 904,997 5,030,884
------- --------- ------- ---------
Income (Loss) from
Operations 100,964 (3,690,147) 282,133 (2,627,413)
Other Income (Expense)
Gain on sale of
assets - 31,031 - 65,689
Interest expense (19,524) (29,877) (73,811) (116,991)
Debt
extinguishment
costs - (4,855) (12,093) (18,256)
(Loss) gain on
mark-to-market
derivative
contracts (20,234) 1,165,742 (7,017) 1,555,917
Other income
(expense) 27,207 (394) 27,968 (12,575)
------ ---- ------ -------
Income (Loss)
Before Income Taxes 88,413 (2,528,500) 217,180 (1,153,629)
Income tax (expense)
benefit
Current (11,334) 81,461 (45,091) (230,815)
Deferred (28,947) 878,381 (35,784) 675,350
------- ------- ------- -------
Net Income (Loss) $48,132 $(1,568,658) $136,305 $(709,094)
======= =========== ======== =========
Earnings (Loss) Per
Share
Basic $0.34 $(14.56) $1.10 $(6.52)
Diluted $0.34 $(14.56) $1.09 $(6.52)
Weighted Average
Shares Outstanding
Basic 139,587 107,733 124,405 108,828
======= ======= ======= =======
Diluted 140,973 107,733 125,288 108,828
======= ======= ======= =======
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Plains Exploration & Production Company
Operating Data (Unaudited)
Three Months Ended Twelve Months Ended
December 31, December 31,
------------ ------------
2009 2008 2009 2008
---- ---- ---- ----
Daily Average Volumes
Oil and liquids sales
(Bbls) 46,890 53,215 48,110 55,449
Gas (Mcf)
Production 242,687 205,804 214,203 216,540
Used as fuel 5,819 6,130 6,461 6,073
Sales 236,868 199,674 207,742 210,467
BOE
Production 87,338 87,511 83,811 91,539
Sales 86,368 86,500 82,734 90,527
Unit Economics (in dollars)
Average NYMEX Prices
Oil $76.13 $59.08 $62.09 $99.75
Gas 4.16 6.97 3.97 9.06
Average Realized Sales
Price Before
Derivative Transactions
Oil (per Bbl) $64.28 $48.12 $51.43 $87.05
Gas (per Mcf) 4.12 4.98 3.72 8.05
Per BOE 46.20 41.10 39.25 72.03
Cash Margin per BOE (1)
Oil and gas revenues $46.20 $41.10 $39.25 $72.03
Costs and expenses
Lease operating
expenses (7.09) (11.40) (8.31) (9.88)
Steam gas costs (2.06) (2.64) (1.78) (3.96)
Electricity (1.26) (2.02) (1.45) (1.59)
Production and ad
valorem taxes (1.10) (2.04) (1.28) (2.84)
Gathering and
transportation (1.38) (0.73) (1.21) (0.64)
Oil and gas
related DD&A (15.33) (23.89) (12.79) (17.69)
------ ------ ------ ------
Gross margin (GAAP) 17.98 (1.62) 12.43 35.43
Oil and gas
related DD&A 15.33 23.89 12.79 17.69
Realized gains
(losses) on
derivative
instruments 8.19 5.77 14.32 (0.26)
Amortization of
monetized
derivatives (2) 21.37 - 18.70 -
----- --- ----- ---
Cash margin (Non-GAAP) $62.87 $28.04 $58.24 $52.86
====== ====== ====== ======
Oil and gas costs
incurred ($ in
thousands) (3) $333,168 $358,916 $1,582,216 $1,097,365
(1) Cash margin per BOE (a non-GAAP measure) is calculated by adjusting
gross margin per BOE (a GAAP measure) to include realized gains and
losses on derivative instruments and amortization of monetized
derivatives and to exclude DD&A. 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 for comparative
purposes within the industry. This measure is not intended to
replace the GAAP statistic but rather to provide additional
information that may be helpful in evaluating trends and performance.
(2) Represents amounts attributable to these production periods for the
$1.1 billion of derivative gains that we monetized in the first
quarter of 2009.
(3) Additions to oil and gas properties reported in our consolidated
statement of cash flows differ from the accrual basis amounts
reflected above due to the timing of cash payments. Excludes
acquisitions.
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Plains Exploration & Production Company
Reconciliation of GAAP to Non-GAAP Measure
Three Months Ended December 31, 2009
------------------------------------
Oil (per Bbl) Gas (per Mcf) BOE
------------- ------------- ---
Average Realized Sales Price
Average realized price
before derivative
instruments (GAAP) (1) $64.28 $4.12 $46.20
Realized (losses)
gains on derivative
instruments (2.13) 3.41 8.19
Amortization of
monetized
derivatives (2) 39.36 - 21.37
----- --- -----
Realized cash price
including derivative
settlements (non-GAAP) $101.51 $7.53 $75.76
======= ===== ======
Three Months Ended December 31, 2008
------------------------------------
Oil (per Bbl) Gas (per Mcf) BOE
------------- ------------- ---
Average Realized Sales Price
Average realized
price before derivative
instruments (GAAP) (1) $48.12 $4.98 $41.10
Realized gains on
derivative instruments 1.13 2.20 5.77
---- ---- ----
Realized cash price
including derivative
settlements (non-GAAP) $49.25 $7.18 $46.87
====== ===== ======
Twelve Months Ended December 31, 2009
-------------------------------------
Oil (per Bbl) Gas (per Mcf) BOE
------------- ------------- ---
Average Realized Sales Price
Average realized
price before derivative
instruments (GAAP) (1) $51.43 $3.72 $39.25
Realized gains on
derivative instruments 7.08 4.06 14.32
Amortization of
monetized derivatives (2) 32.16 - 18.70
----- --- -----
Realized cash price
including derivative
settlements (non-GAAP) $90.67 $7.78 $72.27
====== ===== ======
Twelve Months Ended December 31, 2008
-------------------------------------
Oil (per Bbl) Gas (per Mcf) BOE
------------- ------------- ---
Average Realized Sales Price
Average realized
price before derivative
instruments (GAAP) (1) $87.05 $8.05 $72.03
Realized (losses)
gains on derivative
instruments (2.75) 0.61 (0.26)
----- ---- -----
Realized cash price
including derivative
settlements (non-GAAP) $84.30 $8.66 $71.77
====== ===== ======
(1) Excludes the impact of production costs and expenses and DD&A.
(2) Represents amounts attributable to these production periods for the
$1.1 billion of derivative gains that we monetized in the first
quarter of 2009.
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Plains Exploration & Production Company
Consolidated Statements of Cash Flows
(in thousands of dollars)
Three Months Ended Twelve Months Ended
December 31, December 31,
------------ ------------
2009 2008 2009 2008
---- ---- ---- ----
(Unaudited)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income (loss) $48,132 $(1,568,658) $136,305 $(709,094)
Items not affecting cash
flows from operating
activities
Gain on sale of assets - (31,031) - (65,689)
Depreciation,
depletion,
amortization and
accretion 130,261 200,058 421,580 621,484
Impairment of oil
and gas properties - 3,629,666 - 3,629,666
Deferred income tax
expense (benefit) 28,947 (878,381) 35,784 (675,350)
Debt extinguishment
costs - 4,855 12,093 18,256
Loss (gain) on mark-
to-market
derivative
contracts 20,234 (1,165,742) 7,017 (1,555,917)
Noncash compensation 12,674 11,470 60,490 50,401
Other noncash items 2,471 2,316 6,950 6,546
Change in assets and
liabilities from
operating activities,
net of effect of
acquisitions (53,559) 19,917 (181,173) 51,106
------- ------ -------- ------
Net cash provided by
operating activities 189,160 224,470 499,046 1,371,409
------- ------- ------- ---------
CASH FLOWS FROM INVESTING
ACTIVITIES
Additions to oil and
gas properties (385,659) (428,510) (1,628,357) (1,116,715)
Acquisition of oil
and gas properties (22,797) 6,842 (1,159,939) (2,006,127)
Acquisition of Pogo
Producing Company,
net of cash acquired - (1,041) - (77,686)
Proceeds from sales
of oil and gas
properties and
related assets, net
of costs and expenses - 1,233,886 - 2,969,945
Derivative settlements 65,180 27,606 1,522,412 (8,606)
Decrease in
restricted cash - - - 59,092
Additions to other
property and
equipment (2,510) (9,988) (14,677) (44,436)
Other - (1,586) 162 (3,257)
--- ------ --- ------
Net cash (used in)
provided by investing
activities (345,786) 827,209 (1,280,399) (227,790)
-------- ------- ---------- --------
CASH FLOWS FROM FINANCING
ACTIVITIES
Borrowings from
revolving credit
facilities 1,198,235 2,829,694 3,513,325 14,331,046
Repayments of
revolving credit
facilities (1,043,235) (3,558,825) (4,588,325)(15,231,046)
Proceeds from
issuance of Senior
Notes - - 916,439 400,000
Costs incurred in
connection with
financing
arrangements (115) (2,079) (19,556) (27,527)
Derivative settlements - (1,581) 1,392 (25,678)
Issuance of common
stock (30) - 648,005 -
Purchase of treasury
stock - - - (304,192)
Other 29 (9,440) 57 207
--- ------ --- ---
Net cash provided by
(used in) financing
activities 154,884 (742,231) 471,337 (857,190)
------- -------- ------- --------
Net (decrease)
increase in cash and
cash equivalents (1,742) 309,448 (310,016) 286,429
Cash and cash
equivalents,
beginning of period 3,601 2,427 311,875 25,446
----- ----- ------- ------
Cash and cash
equivalents, end of
period $1,859 $311,875 $1,859 $311,875
====== ======== ====== ========
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Plains Exploration & Production Company
Consolidated Balance Sheets
(in thousands of dollars)
December 31,
------------
2009 2008
---- ----
ASSETS
Current Assets
Cash and cash equivalents $1,859 $311,875
Accounts receivable 258,585 175,896
Commodity derivative contracts 11,952 945,838
Inventories 19,934 23,368
Prepaid expenses and other current assets 14,305 19,464
------ ------
306,635 1,476,441
------- ---------
Property and Equipment, at cost
Oil and natural gas properties -
full cost method
Subject to amortization 9,044,146 7,106,785
Not subject to amortization 3,279,537 2,513,424
Other property and equipment 125,667 110,990
------- -------
12,449,350 9,731,199
Less allowance for depreciation,
depletion, amortization and impairment (5,616,628) (5,217,803)
---------- ----------
6,832,722 4,513,396
--------- ---------
Goodwill 535,237 535,265
------- -------
Commodity Derivative Contracts - 530,181
--- -------
Other Assets 60,137 56,632
------ ------
$7,734,731 $7,111,915
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable $248,454 $363,713
Commodity derivative contracts 59,176 -
Royalties and revenues payable 78,590 87,874
Interest payable 45,743 20,843
Income taxes payable - 102,948
Deferred income taxes 153,473 285,426
Other current liabilities 97,115 132,841
------ -------
682,551 993,645
------- -------
Long-Term Debt 2,649,689 2,805,000
--------- ---------
Other Long-Term Liabilities
Asset retirement obligation 214,231 159,473
Other 55,531 32,061
------ ------
269,762 191,534
------- -------
Deferred Income Taxes 933,748 744,456
------- -------
Stockholders' Equity
Common stock 1,439 1,129
Additional paid-in capital 3,381,566 2,739,625
Retained earnings (deficit) 51,204 (85,101)
Accumulated other comprehensive loss - (684)
Treasury stock, at cost (235,228) (277,689)
-------- --------
3,198,981 2,377,280
--------- ---------
$7,734,731 $7,111,915
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Plains Exploration & Production Company
Summary of Open Derivative Positions
At January 1, 2010
Average
Instrument Daily Average Deferred
Period (1) Type Volumes Price (2) Premium Index
---------- ---- ------- --------- ------- -----
Sales of Crude Oil Production
2010
Jan - Dec Put options 40,000 Bbls $55.00 Strike $5.00 per WTI
price Bbl (3)
Sales of Natural Gas Production
2010
Jan - Dec Three-way 85,000 MMBtu $6.12 Floor $0.034 MMBtu Henry
collars (4) with a Hub
$4.64 Limit
$8.00 Ceiling
(1) All of our derivative instruments are settled monthly.
(2) The average strike prices do not reflect the cost to purchase the put
options or collars.
(3) In addition to the deferred premium, a premium averaging $3.86 per
barrel was paid from the proceeds of our first quarter 2009
derivative monetization upon entering into these derivative contracts.
(4) If NYMEX is less than the $6.12 per MMBtu floor, we receive the
difference between NYMEX and the $6.12 per MMBtu floor up to a
maximum of $1.48 per MMBtu. We pay the difference between NYMEX and
$8.00 per MMBtu if NYMEX is greater than the $8.00 ceiling.
Plains Exploration & Production Company
Reconciliation of GAAP to Non-GAAP Measure
The following table reconciles net income (GAAP) to adjusted net income
(non-GAAP) for the three and twelve months ended December 31, 2009 and
2008. Adjusted net income excludes certain items affecting comparability
of operating results and the related tax effects. 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 rather to provide additional information that may be helpful
in evaluating the Company's operational trends and performance.
Three Months Ended Twelve Months Ended
December 31, December 31,
------------ ------------
2009 2008 2009 2008
---- ---- ---- ----
(millions of dollars)
Net income (loss) (GAAP) $48.1 $(1,568.7) $136.3 $(709.1)
Impairment of oil and gas
properties - 3,629.7 - 3,629.7
Unrealized loss (gain) on mark-
to-market derivative contracts 20.2 (1,165.7) 7.0 (1,555.9)
Realized gain (loss) on mark-
to-market derivative
contracts (1) 65.1 45.9 432.4 (8.7)
Amortization of monetized
derivatives (2) 169.8 - 564.7 -
Gain on sale of assets - (31.0) - (65.7)
Other income items (3) (23.5) - (110.8) -
Adjust income taxes (4) (87.1) (930.4) (353.6) (757.9)
----- ------ ------ ------
Adjusted net income (non-GAAP) $192.6 $(20.2) $676.0 $532.4
====== ====== ====== ======
(1) The amounts presented in the above table differ from the
adjustments reflected in the calculation of operating cash flow on
the following page due to the accrued amounts reflected in the
income statement versus the actual cash received or paid reflected
in the consolidated statement of cash flows.
(2) Represents amounts attributable to these production periods for the
$1.1 billion of derivative gains that we monetized in the first
quarter of 2009. The remaining proceeds from the monetization are
not included in the above table because they are attributable to
production months subsequent to December 31, 2009.
(3) For the three months ended December 31, 2009, the amount represents
royalty receipts for preacquisition amounts for properties sold by
Pogo Producing Company prior to our acquisition of Pogo. For the
twelve months ended December 31, 2009, the amount includes the
royalty receipts and legal recovery.
(4) Tax rates assumed based upon adjusted earnings are 40% and 59% for
the three months ended December 31, 2009 and 2008, respectively. Tax
rates assumed based upon adjusted earnings are 39% and 37% for the
twelve months ended December 31, 2009 and 2008, respectively. Tax
rates exclude the effects of nonrecurring tax related expenses and
benefits.
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Plains Exploration & Production Company
Reconciliation of GAAP to Non-GAAP Measure
The following tables reconcile Net Cash Provided by Operating Activities
(GAAP) to Operating Cash Flow (non-GAAP) for the three and twelve months
ended December 31, 2009 and 2008. Management believes this presentation
may be useful to investors. 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 rather to
provide additional information that may be helpful in evaluating the
Company's operational trends and performance.
Operating cash flow is calculated by adjusting net income to add back
certain non-cash and non-operating items, including unrealized gains and
losses on mark-to-market derivative contracts, to include derivative cash
settlements for realized gains and losses on mark-to-market derivative
contracts that are classified as either investing or financing activities
for GAAP purposes and to exclude certain items.
Three Months Ended Twelve Months Ended
December 31, December 31,
------------- ------------
2009 2008 2009 2008
---- ---- ---- ----
(millions of dollars)
Net income $48.1 $(1,568.7) $136.3 $(709.1)
Items not affecting operating
cash flows
Gain on sale of assets - (31.0) - (65.7)
Impairment of oil and gas
properties - 3,629.7 - 3,629.7
Depreciation, depletion,
amortization and
accretion 130.3 200.1 421.5 621.5
Deferred income tax expense
(benefit) 28.9 (878.4) 35.8 (675.4)
Debt extinguishment costs - 4.8 12.1 18.3
Unrealized loss (gain) on
mark-to-market
derivative contracts 20.2 (1,165.7) 7.0 (1,555.9)
Noncash compensation 12.7 11.5 60.5 50.4
Other noncash items 2.5 2.3 7.0 6.5
Realized gain (loss) on mark-
to-market derivative contracts 65.2 26.0 449.4 (34.3)
Amortization of monetized
derivatives (1) 169.8 - 564.7 -
Other income items (23.5) - (110.8) -
Current income taxes
attributable to derivative
contracts and property sales 11.3 62.2 45.1 230.8
---- ---- ---- -----
Operating cash flow (non-GAAP) $465.5 $292.8 $1,628.6 $1,516.8
====== ====== ======== ========
Reconciliation of non-GAAP to
GAAP measure
Operating cash flow (non-GAAP) $465.5 $292.8 $1,628.6 $1,516.8
Other income items 23.5 - 110.8 -
Changes in assets and
liabilities from
operating activities (53.5) 19.9 (181.2) 51.1
Realized (gain) loss on mark-
to-market derivative
contracts (65.2) (26.0) (449.4) 34.3
Amortization of monetized
derivatives (1) (169.8) - (564.7) -
Current income taxes
attributable to derivative
contracts and property sales (11.3) (62.2) (45.1) (230.8)
----- ----- ----- ------
Net cash provided by operating
activities (GAAP) $189.2 $224.5 $499.0 $1,371.4
====== ====== ====== ========
(1) Represents amounts attributable to these production periods for the
$1.1 billion of derivative gains that we monetized in the first
quarter of 2009.
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Plains Exploration & Production Company
Derivative Settlements
(in thousands of dollars)
The following tables reflect cash receipts (payments) for derivatives
attributable to the stated production periods.
Three Months Ended Twelve Months Ended
December 31, December 31,
------------ ------------
2009 2008 2009 2008
---- ---- ---- ----
Oil sales $(9,198) $5,510 $124,296 $(55,820)
Natural gas sales 74,275 40,411 308,146 47,163
------- ------- -------- -------
$65,077 $45,921 $432,442 $(8,657)
======= ======= ======== =======
2009 2010
---- ----
Amortization of monetized derivatives (1)
First Quarter $57,211 $123,730
Second Quarter 167,943 125,105
Third Quarter 169,788 126,479
Fourth Quarter 169,788 126,479
------- -------
$564,730 $501,793
======== ========
(1) Represents the net receipts for derivatives monetized in the first
quarter of 2009 attributable to these production periods, net of
accrued interest on our deferred premiums.
Plains Exploration & Production Company
Proved Reserves and Costs Incurred
Proved Reserves (MMBOE):
2008 Year-end estimated proved reserves 292.1
2009 Extensions and discoveries 57.1
2009 Revisions 38.6
2009 Acquisitions 2.3
2009 Production (30.6)
-----
2009 Year-end estimated proved reserves 359.5
=====
Reserve Replacement Ratio: 320%
Calculation: Reserve extensions, discoveries, revisions
and acquisitions divided by production.
Costs Incurred ($ Millions):
Property acquisition costs:
Unproved properties $1,121.6
Proved properties 5.1
Exploration costs (1) 1,309.4
Development costs 272.8
-----
Total Costs Incurred (2) $2,708.9
========
(1) Includes $375.1 million of Haynesville promoted well costs. In July
2008, PXP acquired a 20% interest in Chesapeake Energy's Haynesville
Shale leasehold. In connection with the acquisition, PXP agreed to
fund 50% of Chesapeake's drilling and completion costs associated
with future Haynesville Shale wells which is referred to as the
Haynesville Carry. Well costs paid under this agreement are referred
to as promoted well costs. In August 2009, PXP amended the
participation agreement with Chesapeake to accelerate the payment of
the remaining Haynesville Carry. As a result of the prepayment of the
Haynesville Carry, PXP will not pay promoted well costs attributable
to periods subsequent to the third quarter of 2009.
(2) Includes capitalized interest expense of $113.8 million and
capitalized general and administrative expense of $67.3 million.
Plains Exploration & Production Company
Finding and Development Costs (F&D):
All-In F&D Costs per BOE $27.64
Calculation: Total costs incurred divided by reserve extensions,
discoveries, revisions and acquisitions.
F&D Costs Excluding Acquisition Costs per BOE $16.53
Calculation: Total costs incurred minus unproved and proved
property acquisition costs divided by reserve extensions,
discoveries and revisions.
F&D Costs Excluding Acquisition and Haynesville Promoted
Costs per BOE $12.61
Calculation: Total costs incurred minus unproved and proved
property acquisition costs and Haynesville promoted well costs
divided by reserve extensions, discoveries and revisions.
The Reserve Replacement Ratio is an indicator of our ability to replace annual production volume and grow our reserves. It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced.
Finding and Development Costs per BOE is a non-GAAP metric commonly used in the exploration and production industry. The calculations presented are described above. This calculation does not include the future development costs required for the development of proved undeveloped reserves.
The Reserve Replacement Ratio and Finding and Development Costs per BOE are statistical indicators that have limitations, including their predictive and comparative value. As such, these metrics should not be considered in isolation or as a substitute for an analysis of our performance as reported under GAAP. Furthermore, these metrics may not be comparable to similarly titled measurements used by other companies.
Plains Exploration & Production Company
Full Year 2010 Operating and Financial Guidance
Year Ended
December 31, 2010
-----------------
Production Volumes (MBOE/day)
Production volumes sold 88.0 - 92.0
% Oil 49% - 52%
% Gas 51% - 48%
Price Realization % Index (Unhedged)
Oil - NYMEX 87% - 91%
Gas - Henry Hub 95% - 99%
Production Costs per BOE
Lease operating expense $8.25 - $9.00
Steam gas costs (1) $2.25 - $3.00
Electricity $1.40 - $1.60
Production and ad valorem taxes $1.65 - $2.00
Gathering and transportation $1.40 - $1.60
Depreciation, Depletion and Amortization
per BOE (2) $16.00 - $18.00
General and Administrative Expenses
(in millions)
Cash $89 - $94
Stock based compensation (3) $48 - $53
Interest Expense
Average revolver balance 30 Day LIBOR + 2.00% - 2.75%
$600 Million Senior Notes 7 3/4%
$565 Million Senior Notes 10%
$500 Million Senior Notes 7%
$400 Million Senior Notes 7 5/8%
$400 Million Senior Notes 8 5/8%
Effective Tax Rate 40% - 44%
Weighted Average Equivalent Shares Outstanding
(in thousands)
Basic 140,600
Diluted 142,400
Capital Expenditures (in millions) (4) $1,200
Derivative Instruments
Crude Oil Put Options
Bbls / day 40,000
Floor $55.00
Option premium and interest ($/Bbl) $5.00
Natural Gas Three-way Collars (5)
MMBtu / day 85,000
Ceiling $8.00
Floor $6.12
Floor Limit $4.64
Option premium and interest ($/MMBtu) $0.034
(1) Steam gas costs assume a base SoCal Border index price of $6.30 per
MMBtu. The purchased volumes are anticipated to be 36,000 - 40,000
MMBtu per day.
(2) Includes accretion.
(3) Based on current outstanding and projected awards and current stock
price.
(4) Includes capitalized interest and general and administrative
expenses.
(5) If NYMEX is less than the $6.12 per MMBtu floor, we receive the
difference between NYMEX and the $6.12 per MMBtu floor up to a
maximum of $1.48 per MMBtu. We pay the difference between NYMEX and
the $8.00 per MMBtu if NYMEX is greater than the $8.00 ceiling.
SOURCE Plains Exploration & Production Company
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