Operations

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.

Company Overview

We are an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploiting, exploring and producing oil and gas properties primarily in the United States. We own oil and gas properties with principal operations in:

• 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, which declined significantly during the fourth quarter of 2008, 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 or gas prices above the maximum fixed 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 7A "Quantitative and Qualitative Disclosures About Market Risk".

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, projected cash settlements from our derivative contracts, our senior revolving credit facility and periodic public offerings of debt. At December 31, 2008, we had approximately $994 million of availability under our senior revolving credit facility. We believe that we have sufficient liquidity through our forecasted cash flow 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 2008, there has been extreme volatility and disruption in the capital and credit markets. During the second half of 2008 and first quarter of 2009, 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 to our commodity price risk management agreements, our insurers and our oil and gas purchasers. See "Liquidity and Capital Resources".

Acquisitions

In July 2008, we acquired from a subsidiary of Chesapeake a 20% interest in Chesapeake's Haynesville Shale leasehold for approximately $1.65 billion in cash. We funded the acquisition with borrowings under our senior revolving credit facility. In connection with the acquisition, we also agreed, over a multi-year period, to fund 50% of Chesapeake's drilling and completion costs associated with future Haynesville Shale wells, up to an additional $1.65 billion. In addition, we will have the option to participate for 20% of any additional leasehold that Chesapeake, or its affiliates, acquires in the Haynesville Shale within a designated area of mutual interest. We currently hold 111,000 net acres in the Haynesville Shale. At the acquisition date, there were no material proved reserves associated with the leasehold interests acquired.

In April 2008, we completed the acquisition of oil and gas producing properties in South Texas from a private company. After the exercise of third party preferential rights, we paid approximately $282 million in cash. We funded the acquisition primarily with proceeds from recently completed divestments through the use of a tax deferred like-kind exchange. We estimate that proved reserves were approximately 93 billion cubic feet of natural gas equivalent as of December 31, 2007. The effective date of the transaction was January 1, 2008.

Divestments

In December 2008, we closed the sale of certain oil and gas properties to a subsidiary of Oxy and certain other companies with contractual preferential purchase rights, with an effective date of December 1, 2008, and received approximately $1.25 billion in gross cash proceeds, and $1.24 billion after preliminary closing adjustments. We sold the remaining 50% of our working interests in oil and gas properties located in the Permian Basin, West Texas and New Mexico, which we acquired in the Pogo acquisition in November 2007. We also sold the remaining 50% of our working interests in oil and gas properties located in the Piceance Basin in Colorado, including a 50% interest in the entity that held our interest in CVGG. We acquired these properties in May 2007. The sale also included our interest in approximately 11,500 net undeveloped acres adjacent to the Piceance Basin assets that we and Oxy jointly acquired from a third party in June 2008.

In February 2008, we closed the sale of certain oil and gas properties to a subsidiary of Oxy and certain other companies with contractual preferential purchase rights, with an effective date of January 1, 2008, and received approximately $1.53 billion in cash proceeds. We sold 50% of our working interests in oil and gas properties located in the Permian Basin, West Texas and New Mexico, which we acquired in the Pogo acquisition in November 2007. We also sold 50% of our working interests in oil and gas properties located in the Piceance Basin in Colorado, including a 50% interest in the entity that held our interest in CVGG. We acquired these properties in May 2007.

In February 2008, we closed the sale to XTO of certain oil and gas properties located in the San Juan Basin in New Mexico and in the Barnett Shale in Texas. This transaction had an effective date of January 1, 2008, and we received $199.0 million in cash proceeds.

Derivatives

In the first quarter of 2009, we monetized our 2009 and 2010 crude oil put option contracts on 40,000 BOPD. As a result, we received $389 million in net proceeds on February 20, 2009 and will

receive approximately $711 million in net proceeds in March 2009, which we will use to reduce the outstanding balance on our senior revolving credit facility. We currently are party to crude oil put option contracts on 32,500 BOPD in 2009 and 40,000 BOPD in 2010. These put options have a strike price of $55 per barrel. Additionally, we are party to natural gas $10 by $20 collars on 150,000 MMbtu in 2009 and natural gas three way collars on 40,000 million British thermal units (MMbtu) per day for 2010. Under the later arrangement, if the index price is below the floor price of $6.25 per MMbtu, we receive the difference between $6.25 and the index price up to a maximum of $1.45 per MMbtu. If the index price is greater than the ceiling price of $8.00 per MMbtu, we pay the difference between the index price and $8.00 per MMbtu.

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." 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 fluctuate in the near term. During the fourth quarter of 2008, oil and gas prices declined significantly and we recorded a $3.6 billion non-cash pre-tax impairment charge of our oil and gas properties related to our year-end ceiling test. If prices continue to decline, additional 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. Decreases in oil and gas prices have had, and will likely have in the future, an adverse effect on the carrying value of our estimated proved reserves, our reserve volumes and our revenues, profitability and cash flow.

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 addition to fluctuations as a result of operating in the oil and gas industry, our earnings are subject to volatility due to: (i) gains and losses on derivative contracts subject to mark-to-market accounting as changes occur in the NYMEX price indexes; and (ii) stock appreciation rights ("SARs"),

which are accounted for as liability awards under SFAS 123R and are remeasured to fair value each reporting period. The fair value of SARs is related to the market price of our common stock and will fluctuate with movements in our stock price.

In 2008, we reported a net loss of $709.1 million, or $6.52 per share. The net loss for the period includes a $1.6 billion non-cash pre-tax derivative mark-to-market gain and a $3.6 billion non-cash pre-tax impairment of our oil and gas properties. Our results reflect (1) the divestment of 50% of our working interest in the Piceance and Permian Basin properties to Oxy, on February 29, 2008, and all of our working interest in the San Juan Basin and Barnett Shale to XTO on February 15, 2008, (2) the acquisition of the South Texas oil and gas properties on April 17, 2008 and (3) the divestment of our remaining interest in the Piceance and Permian Basin properties to Oxy on December 1, 2008.

In 2007, we reported net income of $158.8 million, or $1.99 per diluted share. Net income for the period includes an $88.5 million pre-tax derivative mark-to-market loss. Our results reflect the acquisitions of the Piceance Basin properties effective May 31, 2007 and Pogo effective November 6, 2007.

In 2006, we reported net income of $597.5 million, or $7.64 per diluted share. Net income for the period includes a $983.0 million pre-tax gain on sales of oil and gas properties, a $297.5 million pre-tax derivative mark-to-market loss, debt extinguishment costs of $45.1 million, a $37.9 million gain on the termination of a merger agreement, and a non-cash, after-tax expense related to the adoption of SFAS 123R of $2.2 million, or $0.03 per share.

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:

                                                        Year Ended December 31,
                                            2008 (1)           2007 (2)            2006 (3)
Sales Volumes
Oil and liquids sales (MBbls)                  20,294             18,124              18,975
Gas (MMcf)
Production                                     79,254             29,312              20,629
Used as fuel                                    2,223              2,302               4,823
Sales                                          77,031             27,010              15,806
MBOE
Production                                     33,503             23,010              22,413
Sales                                          33,133             22,625              21,609
Daily Average Volumes
Oil and liquids sales (Bbls)                   55,449             49,655              51,985
Gas (Mcf)
Production                                    216,540             80,307              56,519
Used as fuel                                    6,073              6,307              13,214
Sales                                         210,467             74,000              43,305
BOE
Production                                     91,539             63,041              61,405
Sales                                          90,527             61,986              59,202
Unit Economics (in dollars)
Average NYMEX Prices
Oil                                       $     99.75         $    72.36          $    66.23
Gas                                              9.06               6.86                7.21
Average Realized Sales Price
Before Derivative Transactions
Oil (per Bbl)                             $     87.05         $    61.60          $    55.62
Gas (per Mcf)                                    8.05               5.68                6.73
Per BOE                                         72.03              56.12               53.76
Costs and Expenses per BOE
Production costs
Lease operating expenses                  $      9.88         $     9.98          $     8.32
Steam gas costs                                  3.96               4.57                2.95
Electricity                                      1.59               1.76                1.76
Production and ad valorem taxes                  2.84               1.44                1.15
Gathering and transportation                     0.64               0.50                0.31
DD&A (oil and gas properties)                   17.69              12.92                8.96

(1) Reflects the February 2008 divestiture of 50% of our working interest in the Piceance and Permian Basins to Oxy and the San Juan Basin and Barnett Shale to XTO, the April 2008 acquisition of the South Texas properties and the divestiture of the remainder of our interest in the Piceance and Permian Basins effective December 1, 2008.

(2) Reflects the acquisition of Pogo effective November 6, 2007 and the Piceance Basin properties effective May 31, 2007.

(3) Reflects the sale of oil and gas properties to subsidiaries of Oxy effective October 1, 2006.

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

                                                  Year Ended December 31,
                                         2008              2007               2006
  Mark-to-market contracts
  Oil sales                           $   (81,447 )     $   (103,784 )     $    (89,596 )
  Gas sales                                47,163                235               -
  Gas purchases                              -                  -               (11,425 )
  Elimination of crude oil collars           -                  -              (593,283 )

Comparison of Year Ended December 31, 2008 to Year Ended December 31, 2007

Oil and gas revenues. Oil and gas revenues increased $1.1 billion, or 88%, to $2.4 billion for 2008 from $1.3 billion for 2007 primarily due to a 46% increase in sales volumes and a $15.91 per BOE increase in average realized prices. Oil and gas prices declined significantly during the fourth quarter of 2008. Based on our forecasted production, if oil and gas prices remain at current levels or decline our revenues in 2009 will be significantly lower than the amounts reported in 2008.

Oil revenues increased $650.3 million to $1.8 billion for 2008 from $1.1 billion for 2007 reflecting higher average realized prices ($461.4 million) and higher sales volumes ($188.9 million). Our average realized price for oil increased $25.45 to $87.05 per Bbl for 2008 from $61.60 per Bbl for 2007. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $99.75 per Bbl in 2008 versus $72.36 per Bbl in 2007. Oil sales volumes increased 5.7 MBbls per day to 55.4 MBbls per day in 2008 from 49.7 MBbls per day in 2007 due to production from the properties acquired in the Pogo acquisition (6.6 incremental MBbls per day), partially offset by a decrease in our onshore and offshore California properties. Oil production for 2008 includes
6.1 MBbls per day for properties sold during 2008.

Gas revenues increased $466.5 million to $619.9 million in 2008 from $153.4 million in 2007 due to increased sales volumes ($402.6 million) and higher average realized prices ($63.9 million). Our average realized price for gas was $8.05 per Mcf in 2008 compared to $5.68 per Mcf in 2007. Our realized price for gas increased primarily due to an increase in the index price for natural gas ($2.20 per Mcf). Gas sales volumes increased from 74.0 MMcf per day in 2007 to 210.5 MMcf per day in 2008, primarily reflecting sales from the properties acquired in the Pogo acquisition in November 2007 (119.9 MMcf per day), the Piceance Basin properties (5.9 MMcf per day) and the Flatrock project in the Gulf of Mexico (16.4 MMcf per day), partially offset by a reduction in the California onshore gas sales. Gas production for 2008 includes 50.9 MMcf per day for properties sold during 2008.

Lease operating expenses. Lease operating expenses increased $101.6 million, to $327.4 million in 2008 from $225.8 million in 2007. Lease operating expenses for 2008 includes $85.7 million incremental lease operating expense attributable to the Pogo and Piceance Basin acquisitions. Excluding these incremental costs, lease operating expenses increased $15.9 million due primarily to higher expenditures for well workovers, repairs and maintenance and increases from service providers. On a per unit basis, lease operating expenses decreased to $9.88 per BOE in 2008 versus $9.98 per BOE in 2007 due to increased volumes. Increased service costs were reflective of the higher oil and gas prices during the first nine months of the year; however, due to the significant decrease in oil and gas prices in the fourth quarter of 2008 and the expected reduced spending in the industry in 2009, we expect that service costs will decline in 2009. In addition, due to the significant oil and gas price decline we have implemented a program under which we expect to reduce lease operating expense during 2009.

Steam gas costs. Steam gas costs increased $27.7 million, to $131.2 million in 2008 from $103.5 million in 2007, primarily reflecting the higher cost of gas used in steam generation. In 2008 we burned approximately 16.9 Bcf of natural gas at a cost of approximately $7.78 per MMbtu compared to 16.8 Bcf at a cost of approximately $6.17 per MMbtu in 2007. Our average cost to purchase natural gas used in steam operations was approximately $5.27 per MMbtu at December 31, 2008. If gas prices remain at current levels, our steam costs are expected to decline in 2009.

Electricity. Electricity increased $12.9 million, to $52.7 million in 2008 from $39.8 million in 2007, primarily reflecting higher cost for purchased electricity and an increase in usage. On a per unit basis, electricity was $1.59 per BOE in 2008 and $1.76 per BOE in 2007.

Production and ad valorem taxes. Production and ad valorem taxes increased $61.4 million, to $94.0 million in 2008 from $32.6 million in 2007 primarily reflecting increased volumes from the Pogo and Piceance Basin acquisitions and increased tax basis due to higher commodity prices during the first half of 2008.

Gathering and transportation expenses. Gathering and transportation expenses increased $9.7 million, to $21.1 million in 2008 from $11.4 million in 2007, primarily reflecting the Pogo and Piceance Basin acquisitions.

General and administrative expense. G&A expense increased $29.3 million, to $153.3 million in 2008 from $124.0 million in 2007. The increase is primarily due to increased personnel and other costs due to the acquisitions in 2007 ($41.1 million). These expenses were partially offset by an increase in amounts capitalized as part of our acquisition, exploration and development activities. Capitalized costs were $60.6 million in 2008 compared to $44.6 million in 2007, primarily reflecting increased costs and our acquisition, exploration and development activities.

Depreciation, depletion and amortization, or DD&A. DD&A expense increased $302.2 million, to $608.4 million in 2008 from $306.3 million in 2007. The increase was attributable to our oil and gas DD&A, primarily due to a higher per unit rate ($185.6 million) and increased production ($109.8 million). Our 2008 DD&A rate was $17.69 compared to $12.92 in 2007. The increase primarily reflects the reduction in our oil and gas reserves due to lower oil and gas prices, our acquisitions, higher cost reserve additions and exploration costs. Our oil and gas DD&A rate for 2009 after the effect of the impairment of oil and gas properties is expected to be $11.49 per BOE.

Impairment of oil and gas properties. Due to the significant decrease in oil prices in the fourth quarter 2008, the carrying value of our oil and gas properties exceeded our ceiling, equal to the present value of estimated future net cash flows from proved oil and gas reserves, net of estimated future income taxes plus the lower of cost or estimated fair value of unproved properties not included in the costs being amortized. As a result, we recorded a non-cash pre-tax impairment charge of $3.6 billion. The net realized oil and gas prices used in the ceiling tests were $31.75 and $5.50, respectively, at December 31, 2008 compared to $88.91 and $6.94 respectively, at September 30, 2008. If oil and gas prices decline further in 2009, additional impairments of our oil and gas properties could occur.

Accretion expense. Accretion expense increased $3.2 million, to $13.0 million in 2008 from $9.8 million in 2007. Accretion expense for 2008 included $2.6 million attributable to an increase in our asset retirement obligation associated with the Pogo and Piceance Basin properties acquired in November and May 2007, respectively.

Gain on the sale of assets. We completed sales to Oxy of the entity which held our investment in CVGG and recorded gains totaling $65.7 million.

Interest expense. Interest expense increased $48.1 million, to $117.0 million in 2008 from $68.9 million in 2007 primarily due to higher outstanding debt related to the Pogo and Haynesville Shale acquisitions. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization. We capitalized $71.8 million and $34.6 million of interest in 2008 and 2007, respectively. The increase in capitalized interest is primarily due to a higher unevaluated property balance related to the Pogo and Haynesville Shale acquisitions.

Debt extinguishment costs. In connection with our asset divestments, reductions of the commitments under our senior revolving credit facility occurred in February and December 2008, and we recorded $18.3 million of debt extinguishment costs.

Gain (loss) on mark-to-market derivative contracts. We do not 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 or receiving a payment from the counterparty.

As a result of the significant decrease in oil prices in the third and fourth quarters of 2008, we recognized gains related to mark-to-market derivative contracts of $1.6 billion in 2008 as compared to a loss of $88.5 million in 2007.

Income tax (benefit) expense. Our 2008 income tax benefit was $444.5 million, reflecting an annual effective tax rate of 39%, as compared with income tax expense of $109.7 million and an effective tax rate of 41% for 2007. Variances in our annual effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes and permanent differences which include (1) the special deduction for domestic production activities and
(2) expenses that are not deductible because of Internal Revenue Service limitations.

Our 2008 current tax expense of $230.8 million primarily results from the recognition of tax in excess of book gains attributable to our 2008 asset sales plus the non-deductibility for tax purposes of the 2008 oil and gas properties impairment. Our 2007 current benefit primarily reflects the effect of tax refunds received in 2007.

Comparison of Year Ended December 31, 2007 to Year Ended December 31, 2006

Oil and gas revenues. Oil and gas revenues increased $253.7 million, or 25%, to $1.3 billion for 2007 from $1.0 billion for 2006 primarily due to the absence of an oil revenue hedging loss in 2007 and higher realized prices.

Oil revenues, excluding the effects of hedging, increased $60.9 million to $1.1 billion for 2007 from $1.0 billion for 2006 reflecting higher realized prices ($113.3 million) partially offset by lower sales volumes ($52.4 million). Our average realized price for oil increased $5.98 to $61.60 per Bbl for 2007 from $55.62 per Bbl for 2006. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $72.36 per Bbl in 2007 versus $66.23 per Bbl in 2006. Oil sales volumes decreased 2.3 MBbls per day to 49.7 MBbls per day in 2007 from 52.0 MBbls per day in 2006 due to the property . . .