The following information should be read in connection with the information contained in the consolidated financial statements and notes thereto included elsewhere in this report and our Form 10-K for the year ended December 31, 2008.

Company Overview

We are an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploring and producing oil and gas properties in the United States. Our core areas of operations are:

• Onshore California;

• Offshore California;

• the Gulf of Mexico;

• the Gulf Coast Region;

• the Mid-Continent Region; and

• the Rocky Mountains.

We also have an interest in an exploration prospect offshore Vietnam.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum amount specified in the derivative agreement and subjects us to the credit risk of the counterparties to such agreements. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on derivative contracts on our income statement as changes occur in the NYMEX price indices. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. See Item 3 - Quantitative and Qualitative Disclosures About Market Risks.

Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. Our primary sources of liquidity are cash generated from our operations, our cash balances, cash settlements from our derivative contracts, our senior revolving credit facility and periodic public offerings of debt and equity. At March 31, 2009, we had approximately $1.4 billion available for future secured borrowings under our senior revolving credit facility. We believe that we have sufficient liquidity through our forecasted cash flows from operations, cash balances, projected cash settlements from our derivatives and borrowing capacity under our senior revolving credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies and anticipated capital expenditures. In addition, we could curtail the portion of our capital expenditures which is discretionary if our cash flows declined from expected levels.

Capital and Credit Markets

During the first quarter of 2009, the extreme volatility and disruption in the capital and credit markets continued to exist. The volatility and disruption have created conditions that may adversely affect the financial condition of the lenders in our senior revolving credit facility, the counterparties in our commodity price risk management agreements, our insurers and our oil and gas purchasers. See Liquidity and Capital Resources.

Recent Developments

Derivatives

In the first quarter of 2009, we monetized our 2009 and 2010 crude oil put option contracts on 40,000 BOPD with weighted average strike prices of $106.16 per barrel and $111.49 per barrel, respectively. In addition, we also terminated our crude oil swaps on 20,000 BOPD in 2009. As a result of this monetization, we received approximately $1.1 billion in net proceeds, which we used to reduce the outstanding balance on our senior revolving credit facility and for other general corporate purposes.

General

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, and development activities are capitalized. Our revenues are derived from the sale of oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SEC's full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter to determine a ceiling value of our properties. The rules require an impairment if our capitalized costs exceed the allowed "ceiling." During the fourth quarter of 2008, oil and gas prices declined significantly, and we recorded an impairment of our oil and gas properties related to our year-end ceiling test. At March 31, 2009, the ceiling with respect to our oil and gas properties exceeded the net capitalized costs of those properties by approximately 4%. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. If oil and gas prices decline in the future, even if only by a small amount, impairment of our oil and gas properties could occur. Impairment charges required by these rules do not directly impact our cash flows from operating activities.

Our oil and gas production expenses include salaries and benefits of personnel involved in production activities (including stock based compensation), steam gas costs, electricity costs, maintenance costs, production, ad valorem and severance taxes, and other costs necessary to operate our producing properties. Depletion of capitalized costs of producing oil and gas properties is provided using the units of production method based upon estimated proved reserves. For the purposes of computing depletion, estimated proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary.

General and administrative expenses ("G&A") consist primarily of salaries and related benefits of administrative personnel (including stock based compensation), office rent, systems costs and other administrative costs.

Results Overview

In the first quarter of 2009, we reported net income of $5.2 million, or $0.05 per diluted share, compared to net income of $163.5 million, or $1.43 per diluted share, in the first quarter of 2008. The decrease reflects lower commodity prices and the divestment of our interest in the Permian, Piceance and San Juan Basins in 2008.

Results of Operations

The following table reflects the components of our oil and gas production and
sales prices and sets forth our operating revenues and costs and expenses on a
BOE basis:



                                                  Three Months Ended March 31,
                                                  2009 (1)             2008
    Sales Volumes
    Oil and liquids sales (MBbls)                        4,445              5,246
    Gas (MMcf)
    Production                                          17,635             21,366
    Used as fuel                                           646                588
    Sales                                               16,989             20,778
    MBOE
    Production                                           7,385              8,807
    Sales                                                7,277              8,709
    Daily Average Volumes
    Oil and liquids sales (Bbls)                        49,394             57,646
    Gas (Mcf)
    Production                                         195,943            234,788
    Used as fuel                                         7,175              6,457
    Sales                                              188,768            228,331
    BOE
    Production                                          82,052             96,777
    Sales                                               80,856             95,701
    Unit Economics (in dollars)
    Average NYMEX Prices
    Oil                                        $         43.31    $         97.82
    Gas                                                   4.87               8.02
    Average Realized Sales Price Before
    Derivative Transactions
    Oil (per Bbl)                              $         35.23    $         87.03
    Gas (per Mcf)                                         4.19               7.90
    Per BOE                                              31.31              71.27
    Costs and Expenses per BOE
    Production costs
    Lease operating expenses                   $          9.74    $          8.56
    Steam gas costs                                       2.14               3.69
    Electricity                                           1.50               1.34
    Production and ad valorem taxes                       1.60               3.01
    Gathering and transportation                          0.91               0.97
    Depreciation, depletion and amortization
    of oil and gas properties ("DD&A")                   11.49              15.76

(1) Reflects the divestiture of our interest in the Piceance, Permian and San Juan Basins in 2008.

The following table reflects cash (payments)/receipts made with respect to derivative contracts that settled during the periods presented (in thousands):

                                                       Three Months Ended
                                                           March 31,
                                                       2009          2008
         Mark-to-market contracts
         Oil sales
         Settlements                                $   156,876   $  (22,264 )
         Monetization of crude oil puts and swaps     1,074,361           -
         Gas sales                                       64,312          427

Comparison of Three Months Ended March 31, 2009 to Three Months Ended March 31, 2008

Oil and gas revenues. Oil and gas revenues decreased $392.8 million, to $227.9 million for 2009 from $620.7 million for 2008 primarily due a decrease in realized prices of $39.96 per BOE and the divestment of our interest in the Permian, Piceance and San Juan Basins in 2008.

Oil revenues decreased $300.0 million to $156.6 million for 2009 from $456.6 million for 2008 reflecting lower average realized prices ($271.8 million) and lower sales volumes ($28.2 million). Our average realized price for oil decreased $51.80 to $35.23 per Bbl for 2009 from $87.03 per Bbl for 2008. The decrease is primarily attributable to a decrease in the NYMEX oil price, which averaged $43.31 per Bbl in 2009 versus $97.82 per Bbl in 2008. Oil sales volumes decreased 8.2 MBbls per day to 49.4 MBbls per day in 2009 from
57.6 MBbls per day in 2008, primarily reflecting the divestments in 2008 (10.1 MBbls per day), partially offset by increased production from our Flatrock properties in the Gulf of Mexico.

Gas revenues decreased $92.8 million to $71.3 million in 2009 from $164.1 million in 2008 due to a decrease in realized prices ($76.9 million) and decreased sales volumes ($15.9 million). Our average realized price for gas was $4.19 per Mcf in 2009 compared to $7.90 per Mcf in 2008. Our realized price for gas decreased primarily due to a decrease in the NYMEX natural gas price, which averaged $4.87 per MMBtu in 2009 versus $8.02 per MMBtu in 2008. Gas sales volumes decreased from 228.3 MMcf per day in 2008 to 188.8 MMcf per day in 2009, primarily reflecting the divestments in 2008 (82.6 MMcf per day), partially offset by production from our Flatrock properties (30.4 MMcf per day) and our Haynesville Shale properties (13.8 MMcf per day).

Lease operating expenses. Lease operating expenses decreased $3.6 million, to $70.9 million in 2009 from $74.5 million in 2008, primarily reflecting the sale and acquisition of properties in 2008. Excluding costs associated with the sold and purchased properties, lease operating expenses increased by $7.7 million as costs in the first quarter do not fully reflect decreased costs in the industry resulting from the significant decline in oil and gas prices or the program that we have implemented to reduce costs. We expect to reduce costs in future quarters. On a per unit basis, lease operating expenses increased to $9.74 per BOE in 2009 versus $8.56 per BOE in 2008 due primarily to the divestment of the Permian and Piceance Basin properties which had lower per unit costs than the majority of our remaining properties.

Steam gas costs. Steam gas costs decreased $16.6 million, to $15.6 million in 2009 from $32.2 million in 2008, primarily reflecting lower cost of gas used in steam generation. In 2009, we burned approximately 3.9 billion cubic feet ("Bcf") of natural gas at a cost of approximately $4.01 per MMBtu compared to
4.2 Bcf at a cost of approximately $7.71 per MMBtu in 2008.

Production and ad valorem taxes. Production and ad valorem taxes decreased $14.6 million, to $11.6 million in 2009 from $26.2 million in 2008, primarily reflecting the divestments in 2008 and lower commodity prices.

Gathering and transportation expense. Gathering and transportation expenses decreased $1.8 million, to $6.6 million in 2009 from $8.5 million in 2008, primarily reflecting the divestments in 2008, partially offset by an increase from our Haynesville Shale properties.

General and administrative expense. G&A expense decreased $2.8 million, to $37.1 million in 2009 from $39.9 million in 2008. The net decrease reflects lower cash G&A (G&A other than stock based compensation, $4.3 million) and an increase in capitalized G&A ($1.3 million), partially offset by higher stock based compensation ($2.8 million).

Depreciation, depletion and amortization, or DD&A. DD&A expense decreased $52.8 million, to $88.1 million in 2008 from $140.9 million in 2008. The decrease is attributable to our oil and gas DD&A, primarily due to a lower per unit rate ($37.6 million) and decreased production ($16.3 million). Our oil and gas unit of production rate decreased to $11.49 per BOE in 2009 compared to $15.76 per BOE in 2008. The decrease primarily reflects the 2008 year-end impairment of oil and gas properties, which reduced our DD&A rate in subsequent periods.

Other Operating Expense. Other operating expense in 2009 consists primarily of a restocking fee related to a cancelled purchase order, a valuation adjustment for materials and supplies inventory and idle drilling equipment costs resulting from unused contract commitments.

Gain on sale of assets. In February 2008, we completed the sale to Occidental Petroleum Corporation of 50% of the entity that held our investment in Collbran Valley Gas Gathering System and recorded a gain on the sale of $34.7 million.

Interest expense. Interest expense decreased $8.6 million, to $22.0 million in 2009 from $30.6 million in 2008 due to the lower outstanding balance on our senior revolving credit facility, partially offset by an increase in the balance of our senior notes. Interest expense is reduced by interest capitalized on oil and gas properties not subject to amortization. We capitalized $19.7 million and $17.6 million of interest in the first quarter of 2009 and 2008, respectively. The increase in capitalized interest is due primarily to the higher unevaluated property balance associated with our Haynesville Shale properties.

Debt extinguishment costs. In connection with reductions of the borrowing base on our senior revolving credit facility we recorded $10.2 million and $10.3 million of debt extinguishment costs in the first quarter of 2009 and 2008, respectively.

Gain (loss) on mark-to-market derivative contracts. We do not currently use hedge accounting for our derivative instruments. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

We recognized an $88.1 million gain related to mark-to-market derivative contracts in the first quarter of 2009, which was primarily associated with an increase in fair value of our natural gas collars due to lower natural gas prices. In the first quarter of 2008, we recognized a $9.5 million loss related to mark-to-market derivative contracts.

Income taxes. During interim periods income tax expense is based on the estimated effective income tax rate that is expected for the entire year plus any significant unusual or infrequently occurring items which are recorded in the period that the specific item occurs. As income before income taxes changes in future quarters, our effective tax rate may increase or decrease. The variance in our estimated annual effective tax rate from the 35% federal statutory rate primarily results from the tax effects of estimated annual permanent differences, including (1) expenses that are not deductible because of Internal Revenue Service limitations, (2) the special deduction for domestic production and (3) state income taxes.

For the first quarter of 2009, income tax expense was approximately 85% of pre-tax income. The effective tax rate of 85% for the quarter ended March 31, 2009 results from the relationship of 2009 estimated pre-tax income relative to the estimated permanent differences used in our annual effective tax rate computation. Specific items affecting income tax expense for the first quarter included adjustments to deferred taxes for differences in certain expenses between our consolidated financial statements and tax and changes to our balance of unrecognized tax positions. For the first quarter of 2009, current tax expense was approximately 160% of pre-tax income. This unusual rate is a result of timing differences between the book and tax recognition of income attributable to our oil and gas derivative positions. For the first quarter of 2008, income tax expense was approximately 39% of pre-tax income.

Liquidity and Capital Resources

Liquidity is important to our operations. Our liquidity may be affected by declines in oil and gas prices, an inability to access the capital and credit markets and the success of our commodity price risk management activities, which may subject us to the credit risk of the counterparties to such agreements. This situation may arise due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions that cause substantial or extended declines in oil and gas prices.

During the first quarter of 2009, the extreme volatility and disruption in the capital and credit markets continued to exist. The volatility and disruption have created conditions that may adversely affect the financial condition of lenders in our senior revolving credit facility and the counterparties to our commodity price risk management agreements, as well as our insurers and our oil and natural gas purchasers. While these market conditions persist, our liquidity may be adversely affected by limitations on our ability to access the capital and credit markets.

Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity. In March 2009, we amended our senior revolving credit facility to reduce the aggregate borrowing base and commitments of the lenders to $1.4 billion (See Financing Activities), which took into account the derivative monetization (See Item 3 - Quantitative and Qualitative Disclosures about Market Risks) and the March 2009 issuance of $365 million in Senior Notes. At March 31, 2009, we had approximately $1.4 billion available for future secured borrowings under our senior revolving credit facility. The borrowing base was reduced to $1.34 billion in April 2009 effective with our offering of $200 million in Senior Notes (See Financing Activities). Under the terms of the senior revolving credit facility, the borrowing base will be redetermined on an annual basis, with PXP

and the lenders each having the right to one annual interim unscheduled redetermination. Further declines in oil and gas prices from our March 2009 redetermination may adversely affect our liquidity by lowering the amount of the borrowing base that the lenders are willing to extend.

The commitments of each lender to make loans to us are several and not joint under our senior revolving credit facility. Accordingly, if any lender fails to make loans to us, our available liquidity could be reduced by an amount up to the aggregate amount of such lender's commitments under the credit facility. The commitments are from a diverse syndicate of 22 lenders with no single lender's commitment representing more than 7% of the total commitments.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisitions and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil or gas prices above the maximum fixed amount specified in the derivative agreement. Further, we become subject to the credit risk of the counterparties to such agreements when the price of oil and natural gas decreases below the floor specified in the derivative agreement. We consider the credit quality of our counterparties when we value our commodity derivatives (See Item 3 - Quantitative and Qualitative Disclosures About Market Risk). The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy.

In the first and second quarters of 2009, we continued to strengthen our liquidity by monetizing derivatives and issuing new senior notes and shares of our common stock (See Financing Activities).

We monetized our 2009 and 2010 crude oil put option contracts on 40,000 BOPD with weighted average strike prices of $106.16 per barrel and $111.49 per barrel, respectively. As a result of this monetization, we received approximately $1.1 billion in net proceeds, which we used to reduce the outstanding balance on our senior revolving credit facility and other corporate purposes. In connection with this monetization, we have also entered into crude oil put option contracts on 40,000 BOPD in 2010. These put options have a strike price of $55 per barrel. Additionally, in a separate transaction, we acquired natural gas three-way collars on 40,000 MMBtu per day for 2010. The monetization and reset arrangements accelerated cash receipts, while maintaining a hedge position that helps protect against further declines in oil and natural gas prices during 2009 and 2010 (See Item 3 - Quantitative and Qualitative Disclosures About Market Risk).

Our $1.05 billion 2009 capital budget is focused on our major development areas. Approximately 37% of the capital investment is allocated to development activities, 43% to the Haynesville Shale project and 20% for exploration projects. Our resources will be primarily directed to the Haynesville Shale, the California long-life oil resource base, the Flatrock, Friesian, Salida and our remaining high-impact exploration projects in the Gulf of Mexico. To maximize economic returns, we plan to reduce operating expenses in all of our field locations and reduce general and administrative costs throughout 2009. We continue to aggressively manage our inventory, our cost structure and our financial flexibility.

We believe that we have sufficient liquidity through our forecasted cash flow from operations, cash balances, projected cash settlements from our commodity derivative positions and borrowing capacity under our senior revolving credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies and anticipated capital expenditures. In addition, we could curtail the portion of our capital expenditures which is discretionary if our cash flows declined from expected levels. We have no near-term debt maturities. Our senior revolving credit facility has no amounts outstanding, and the next maturity of our senior notes will occur on June 15, 2015.

Working Capital

At March 31, 2009, we had a working capital deficit of approximately $73.6 million, primarily as a result of reducing our senior revolving credit facility with the proceeds from the monetization of our $106.16 per barrel 2009 crude oil puts and $111.49 per barrel 2010 crude oil puts. We generally have a working capital deficit because we use excess cash to pay down borrowings under our senior revolving credit facility; however, as a result of the current volatility and disruption in the capital and credit markets, we changed our cash management strategy to maintain larger cash and cash equivalents balances. Significant cash balances are invested in highly liquid money market mutual funds that consist of U.S. government securities. Our working capital is affected by fluctuations in the fair value of our commodity derivative instruments and stock appreciation rights.

Financing Activities

Amended Credit Agreement. On March 13, 2009, we entered into an amendment to our senior revolving credit facility. The amendment reduced the borrowing base and commitments from $2.7 billion and $2.3 billion, respectively, to $1.5 billion. This reduction gives consideration to our derivative monetization (See Liquidity and Capital Resources), and the borrowing base and commitments were immediately further reduced to $1.4 billion in recognition of the issuance of our $365 million of 10% Senior Notes due 2016, which closed March 6, 2009. The borrowing base was reduced to $1.34 billion in April 2009 effective with our offering of $200 million of 10% Senior Notes.

In addition, the amendment increased the cost of borrowings under the facility. Amounts borrowed under our senior revolving credit facility bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 2.00% to 2.75%;
(ii) the greater of (1) the prime rate, as determined by JPMorgan Chase Bank,
(2) the federal funds rate, plus 1/2 of 1%, and (3) the adjusted LIBOR rate plus 1%; or (iii) the over-night federal funds rate plus an additional variable amount ranging from 2.00% to 2.75% for swingline loans. The additional variable amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under our senior revolving credit facility to the conforming borrowing base and (2) our long-term debt ratings. Commitment fees and letter of credit fees under our senior revolving credit facility are based on the utilization rate and our . . .