Plains Exploration & Production Company

700 Milam, Suite 3100, Houston, TX 77002

www.pxp.com

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).

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.

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.

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.

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.

Revenues

Oil sales

Gas sales

Other operating revenues

Costs and Expenses

Lease operating expenses

Steam gas costs

Electricity

Production and ad valorem taxes

Gathering and transportation expenses

General and administrative

Depreciation, depletion and amortization

Impairment of oil and gas properties

Accretion

Legal recovery

Other operating expense

Income (Loss) from Operations

Other Income (Expense)

Gain on sale of assets

Interest expense

Debt extinguishment costs

(Loss) gain on mark-to-market derivative contracts

Other income (expense)

Income (Loss) Before Income Taxes

Income tax (expense) benefit

Current

Deferred

Net Income (Loss)

Earnings (Loss) Per Share

Basic

Diluted

Weighted Average Shares Outstanding

Basic

Diluted

Daily Average Volumes

Oil and liquids sales (Bbls)

Gas (Mcf)

Production

Used as fuel

Sales

BOE

Production

Sales

Unit Economics (in dollars)

Average NYMEX Prices

Oil

Gas

Average Realized Sales Price Before Derivative Transactions

Oil (per Bbl)

Gas (per Mcf)

Per BOE

Cash Margin per BOE ⁽¹⁾

Oil and gas revenues

Costs and expenses

Lease operating expenses

Steam gas costs

Electricity

Production and ad valorem taxes

Gathering and transportation

Oil and gas related DD&A

Gross margin (GAAP)

Oil and gas related DD&A

Realized gains (losses) on derivative instruments

Amortization of monetized derivatives ⁽²⁾

Cash margin (Non-GAAP)

Oil and gas costs incurred ($ in thousands) ⁽³⁾

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.

Represents amounts attributable to these production periods for the $1.1 billion of derivative gains that we monetized in the first quarter of 2009.

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.

Average Realized Sales Price

Average realized price before derivative instruments (GAAP) ⁽¹⁾

Realized (losses) gains on derivative instruments

Amortization of monetized derivatives ⁽²⁾

Realized cash price including derivative settlements (non-GAAP)

Average Realized Sales Price

Average realized price before derivative instruments (GAAP) ⁽¹⁾

Realized gains on derivative instruments

Realized cash price including derivative settlements (non-GAAP)

Average Realized Sales Price

Average realized price before derivative instruments (GAAP) ⁽¹⁾

Realized gains on derivative instruments

Amortization of monetized derivatives ⁽²⁾

Realized cash price including derivative settlements (non-GAAP)

Average Realized Sales Price

Average realized price before derivative instruments (GAAP) ⁽¹⁾

Realized (losses) gains on derivative instruments

Realized cash price including derivative settlements (non-GAAP)

Excludes the impact of production costs and expenses and DD&A.

Represents amounts attributable to these production periods for the $1.1 billion of derivative gains that we monetized in the first quarter of 2009.

CASH FLOWS FROM OPERATING ACTIVITIES

Net income (loss)

Items not affecting cash flows from operating activities

Gain on sale of assets

Depreciation, depletion, amortization and accretion

Impairment of oil and gas properties

Deferred income tax expense (benefit)

Debt extinguishment costs

Loss (gain) on mark-to-market derivative contracts

Noncash compensation

Other noncash items

Change in assets and liabilities from operating activities, net of effect of acquisitions

Net cash provided by operating activities

CASH FLOWS FROM INVESTING ACTIVITIES

Additions to oil and gas properties

Acquisition of oil and gas properties

Acquisition of Pogo Producing Company, net of cash acquired

Proceeds from sales of oil and gas properties and related assets, net of costs and expenses

Derivative settlements

Decrease in restricted cash

Additions to other property and equipment

Other

Net cash (used in) provided by investing activities

CASH FLOWS FROM FINANCING ACTIVITIES

Borrowings from revolving credit facilities

Repayments of revolving credit facilities

Proceeds from issuance of Senior Notes

Costs incurred in connection with financing arrangements

Derivative settlements

Issuance of common stock

Purchase of treasury stock

Other

Net cash provided by (used in) financing activities

Net (decrease) increase in cash and cash equivalents

Cash and cash equivalents, beginning of period

Cash and cash equivalents, end of period

Current Assets

Cash and cash equivalents

Accounts receivable

Commodity derivative contracts

Inventories

Prepaid expenses and other current assets

Property and Equipment, at cost

Oil and natural gas properties - full cost method

Subject to amortization

Not subject to amortization

Other property and equipment

Less allowance for depreciation, depletion, amortization and impairment

Goodwill

Commodity Derivative Contracts

Other Assets

Current Liabilities

Accounts payable

Commodity derivative contracts

Royalties and revenues payable

Interest payable

Income taxes payable

Deferred income taxes

Other current liabilities

Long-Term Debt

Other Long-Term Liabilities

Asset retirement obligation

Other

Deferred Income Taxes

Stockholders’ Equity

Common stock

Additional paid-in capital

Retained earnings (deficit)

Accumulated other comprehensive loss

Treasury stock, at cost

Period ⁽¹⁾

Instrument Type

Sales of Crude Oil Production

2010

Jan - Dec

Sales of Natural Gas Production

2010

Jan -Dec                

$8.00 Ceiling

All of our derivative instruments are settled monthly.

The average strike prices do not reflect the cost to purchase the put options or collars.

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.

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.

Net income (loss) (GAAP)

Impairment of oil and gas properties

Unrealized loss (gain) on mark-to-market derivative contracts

Realized gain (loss) on mark-to-market derivative contracts⁽¹⁾

Amortization of monetized derivatives ⁽²⁾

Gain on sale of assets

Other income items ⁽³⁾

Adjust income taxes ⁽⁴⁾

Adjusted net income (non-GAAP)

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.

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.

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.

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.

Net income

Items not affecting operating cash flows

Gain on sale of assets

Impairment of oil and gas properties

Depreciation, depletion, amortization and accretion

Deferred income tax expense (benefit)

Debt extinguishment costs

Unrealized loss (gain) on mark-to-market derivative contracts

Noncash compensation

Other noncash items

Realized gain (loss) on mark-to-market derivative contracts

Amortization of monetized derivatives ⁽¹⁾

Other income items

Current income taxes attributable to derivative contracts and property sales

Operating cash flow (non-GAAP)