Plains Exploration & Production Company

700 Milam, Suite 3100, Houston, TX 77002

www.pxp.com

Revenues of $430.3 million and net income of $71.0 million, or $0.49 per diluted share.

Adjusted net income of $52.4 million, or $0.37 per diluted share (a non-GAAP measure).

Income from operations of $133.8 million.

Net cash provided by operating activities of $290.0 million.

Operating cash flow of $243.0 million (a non-GAAP measure).

Average daily sales volumes for the quarter of approximately 88 thousand barrels of oil equivalent (BOE), a 3% increase over first-quarter 2010 or 19% increase pro-forma for the 2010 asset sale.

Average daily sales volumes for March of approximately 93.6 thousand BOE; California offshore scheduled maintenance completed during the quarter.

Crude oil price realizations of 88%.

Total production costs per BOE of $15.41.

Gross margin per BOE was $22.45 and cash margin per BOE was $36.95 (a non-GAAP measure).

In the Eagle Ford Shale asset area, PXP has 5 drilling rigs operating. First-quarter daily sales volumes averaged approximately 2,240 BOE per day net to PXP and were in excess of 3,000 BOE per day net to PXP at the end of the quarter. The 2011 planned 3 net rig program sales volumes exit rate is expected to be above 5,000 BOE per day net at year-end 2011. However, if the current 6 net rig program continues, PXP expects to exit the year above 10,000 BOE net per day. Currently there are 18 wells waiting on completion or connection to pipelines.

In the California asset area, PXP has 4 drilling rigs operating onshore where PXP continues its active development program in the Los Angeles and San Joaquin Basins. Daily sales volumes onshore were just over 31,310 BOE per day net to PXP, flat compared to fourth-quarter 2010. Offshore volumes are back to pre-Platform Irene maintenance levels of approximately 9,000 BOE per day net to PXP. With a large resource inventory identified for this asset area, it will sustain multi-year drilling programs providing future reserves, production and free cash flow. Average daily sales volumes are expected to be above 41,000 BOE net per day by year-end 2011.

In the Texas Panhandle asset area, PXP has 5 drilling rigs operating in the Granite Wash trend and expects to continue this level of activity through 2011. First-quarter daily sales volumes averaged approximately 8,940 BOE per day net to PXP, or 12% higher than fourth-quarter 2010. Average daily sales volumes are expected to increase to approximately 17,000 BOE net per day by year-end 2011. There are 4 wells waiting on completion or connection to pipelines.

In the Haynesville Shale asset area, PXP’s primary operator is currently operating 33 rigs and expects to reduce the rig count to an average of 25 rigs in 2011, plus PXP expects 15 or more rigs by other operators on its acreage. First-quarter daily sales volumes averaged approximately 162 million cubic feet equivalent (MMcfe) per day net to PXP, or 11% higher than fourth-quarter 2010. The rate of

increase in sales volumes is anticipated to slow as the rig count decreases. Average daily sales volumes are expected to be above 170 MMcfe net per day at year-end 2011.

In the other asset areas, including the Madden Field in Wyoming and other Texas assets, average daily sales volumes are expected to be above 11,000 BOE net per day by year-end 2011.

PXP is making progress on several additional projects. In Wyoming, PXP drilled an initial well on its Mowry Shale position and plans to complete and announce well results in the third quarter. Drilling operations are currently underway on a second well in the Mowry Shale. In California, PXP continues to evaluate the potential resource opportunity of its Miocene shale position; and in the Gulf of Mexico Deepwater, PXP continues to evaluate financing options for its deepwater business.

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.

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

Accretion

Legal recovery

Other operating income

Income from Operations

Other (Expense) Income

Interest expense

Debt extinguishment costs

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

Gain on investment measured at fair value

Other income

Income Before Income Taxes

Income tax expense

Current

Deferred

Net Income

Earnings 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 losses on derivative instruments

Cash margin (Non-GAAP)

Oil and gas capital expenditures accrued ($ in thousands) ⁽²⁾

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 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.

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

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.

CASH FLOWS FROM OPERATING ACTIVITIES

Net income

Items not affecting cash flows from operating activities

Depreciation, depletion, amortization and accretion

Deferred income tax expense

Debt extinguishment costs

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

Gain on investment measured at fair value

Non-cash compensation

Other non-cash items

Change in assets and liabilities from operating activities

Net cash provided by operating activities

CASH FLOWS FROM INVESTING ACTIVITIES

Additions to oil and gas properties

Acquisition of oil and gas properties ⁽¹⁾

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

Derivative settlements

Additions to other property and equipment

Net cash used in 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

Other

Net cash provided by financing activities

Net (decrease) increase in cash and cash equivalents

Cash and cash equivalents, beginning of period

Cash and cash equivalents, end of period

Cash inflow in 2010 is associated with an adjustment to the final settlement of the $1.1 billion payment in September 2009 related to the prepayment of the Haynesville drilling carry.

Current Assets

Cash and cash equivalents

Accounts receivable

Inventories

Deferred income taxes

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

Investment

Other Assets

Current Liabilities

Accounts payable

Commodity derivative contracts

Royalties and revenues payable

Interest payable

Other current liabilities

Long-Term Debt

Other Long-Term Liabilities

Asset retirement obligation

Commodity derivative contracts

Other

Deferred Income Taxes

Stockholders’ Equity

Common stock

Additional paid-in capital

Retained earnings

Treasury stock, at cost

Period ⁽¹⁾

Instrument

Type

Average

Price ⁽²⁾

Sales of Crude Oil Production

2011

Apr - Dec

Apr - Dec

2012

Jan - Dec

Sales of Natural Gas Production

2011

Apr - Dec

$4.00 Floor with a $3.00 Limit

$4.92 Ceiling

2012

Jan - Dec

All of our derivatives are settled monthly.

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

If the index price is less than the $80 per barrel floor, we receive the difference between the $80 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 $80 per barrel, we pay only the option premium.

If the index price is less than the $80 per barrel floor, we receive the difference between the $80 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. We pay the difference between the index price and $110 per barrel plus the option premium if the index price is greater than the $110 per barrel ceiling. If the index price is at or above $80 per barrel but at or below $110 per barrel, we pay only the option premium.

If the index price is less than the $4.00 per MMBtu floor, we receive the difference between the $4.00 per MMBtu floor and the index price up to a maximum of $1.00 per MMBtu. We pay the difference between the index price and $4.92 per MMBtu if the index price is greater than the $4.92 per MMBtu ceiling. If the index price is at or above $4.00 per MMBtu but at or below $4.92 per MMBtu, no cash settlement is required.

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.

Oil sales

Natural gas sales

Net income (GAAP)

Unrealized losses (gains) on mark-to-market derivative contracts

Realized losses on mark-to-market derivative contracts ⁽¹⁾

Unrealized gain on investment measured at fair value

Legal recovery

Adjust income taxes ⁽²⁾

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.

Tax rates assumed based upon adjusted earnings are 40% and 44% for the three months ended March 31, 2011 and 2010, respectively. Tax rates exclude the effects of nonrecurring tax related expenses and benefits.

Net income

Items not affecting operating cash flows

Depreciation, depletion, amortization and accretion

Deferred income tax expense

Debt extinguishment costs

Unrealized losses (gains) on mark-to-market derivative contracts

Gain on investment measured at fair value

Non-cash compensation

Other non-cash items

Realized losses on mark-to-market derivative contracts

Legal recovery

Current income taxes attributable to derivative contracts

Operating cash flow (non-GAAP)

Reconciliation of non-GAAP to GAAP measure

Operating cash flow (non-GAAP)

Legal recovery and other

Changes in assets and liabilities from operating activities

Realized losses on mark-to-market derivative contracts

Current income taxes attributable to derivative contracts

Net cash provided by operating activities (GAAP)