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 agreements 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 senior revolving credit facility and periodic public offerings of debt and equity. At September 30, 2009, we had approximately $1.14 billion available for future secured borrowings under our senior revolving credit facility. We believe that we have sufficient liquidity through our forecasted cash flow from operations, projected cash settlements from our derivative contracts 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.

Capital and Credit Markets

While there are signs that the economy may be improving, the potential remains for further volatility and disruption in the capital and credit markets. The recent volatility and disruption have created conditions that may adversely affect the financial condition of lenders in our senior revolving credit facility, the counterparties to our commodity price risk management agreements, our insurers and our oil and natural gas purchasers. These market conditions may adversely affect our liquidity by limiting our ability to access the capital and credit markets (See Liquidity and Capital Resources).

Recent Developments

Haynesville Shale Joint Venture

In August 2009, we amended the joint venture agreement with Chesapeake to accelerate the payment of the remaining Haynesville Carry. We agreed to pay $1.1 billion for the remaining Haynesville Carry balance due Chesapeake as of September 30, 2009, which we estimated to be $1.25 billion, an approximate 12% reduction. On September 29, 2009, we paid $1.1 billion to Chesapeake and we recorded the payment as an addition to oil and natural gas properties. Additionally, Chesapeake committed to drill at least 150 wells per year under the participation agreement for the three-year period starting October 1, 2009. Further, we agreed to terminate our one-time option exercisable in June 2010 which would have relieved us of our obligation to pay the last $800 million of the Haynesville Carry in exchange for an assignment to Chesapeake of 50% of our interest in our Haynesville acreage.

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 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. 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, additional impairment of our oil and gas properties could occur. Impairment charges required by these rules do not 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, 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 purpose 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

For the nine months ended September 30, 2009, we reported net income of $88.2 million, or $0.73 per diluted share, compared to net income of $859.6 million, or $7.72 per diluted share, for the nine months ended September 30, 2008. The decrease primarily reflects lower commodity prices in 2009 and a reduction in the pre-tax gain on mark-to-market derivative contracts.

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               Nine Months Ended
                                                 September 30,                   September 30,
                                             2009            2008            2009            2008

Sales Volumes
Oil and liquids sales (MBbls)                  4,360           5,134          13,246          15,399
Gas (MMcf)
Production                                    20,250          20,722          55,857          60,320
Used as fuel                                     593             524           1,823           1,659
Sales                                         19,657          20,198          54,034          58,661
MBOE
Production                                     7,736           8,588          22,556          25,452
Sales                                          7,637           8,500          22,252          25,175
Daily Average Volumes
Oil and liquids sales (Bbls)                  47,399          55,803          48,521          56,199
Gas (Mcf)
Production                                   220,103         225,232         204,605         220,145
Used as fuel                                   6,443           5,691           6,678           6,053
Sales                                        213,660         219,541         197,927         214,092
BOE
Production                                    84,083          93,342          82,622          92,890
Sales                                         83,009          92,393          81,509          91,881
Unit Economics (in dollars)
Average NYMEX Prices
Oil                                        $   68.24       $  118.22       $   57.32       $  113.52
Gas                                             3.40           10.28            3.91            9.76
Average Realized Sales Price Before
Derivative Transactions
Oil (per Bbl)                              $   57.26       $  103.00       $   47.24       $   99.43
Gas (per Mcf)                                   3.18            9.01            3.56            9.00
Per BOE                                        40.86           83.62           36.76           81.81
Costs and Expenses per BOE
Production costs
Lease operating expenses                   $    7.89       $    9.06       $    8.75       $    9.40
Steam gas costs                                 1.43            4.40            1.68            4.38
Electricity                                     1.39            1.69            1.52            1.46
Production and ad valorem taxes                 1.04            3.22            1.35            3.09
Gathering and transportation                    1.36            0.52            1.15            0.61
Depreciation, depletion and
amortization of oil and gas
properties ("DD&A")                        $   12.66       $   15.71       $   11.89       $   15.72

Comparisons between the periods are affected by the February 2008 divestiture of 50% of our working interest in the Piceance and Permian Basins, all of the San Juan Basin and Barnett Shale, the April 2008 acquisition of South Texas properties, the 20% interest in Chesapeake's Haynesville Shale leasehold acquired July 7, 2008 and the divestiture of the remainder of our interest in the Piceance and Permian Basins effective December 1, 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            Nine Months Ended
                                                 September 30,                September 30,
                                              2009          2008            2009           2008

Mark-to-market derivative contracts
Oil sales
Settlements                                 $  (9,198)    $ (23,953)    $    150,394     $ (67,061)
Monetization of crude oil puts and swaps          -             -          1,074,361           -
Natural gas sales                              86,108         6,325          233,869         6,752

                                            $  76,910     $ (17,628)    $  1,458,624     $ (60,309)

Comparison of Three Months Ended September 30, 2009 to Three Months Ended September 30, 2008

Oil and gas revenues. Oil and gas revenues decreased $398.8 million, to $312.0 million for 2009 from $710.8 million for 2008 primarily due to a decrease in realized prices of $42.76 per BOE and a 10% decrease in sales volumes primarily associated with the 2008 property divestments. Excluding the impact of our divestments, increased production from the Haynesville Shale and Flatrock properties is responsible for a 4% increase in sales volumes for the three months ended September 30, 2009 compared to the same period a year ago.

Oil revenues decreased $279.2 million to $249.6 million for 2009 from $528.8 million for 2008 reflecting lower average realized prices ($234.9 million) and lower sales volumes ($44.3 million). Our average realized price for oil decreased $45.74 to $57.26 per Bbl for 2009 from $103.00 per Bbl for 2008. Oil sales volumes decreased 8.4 MBbls per day to 47.4 MBbls per day in 2009 from
55.8 MBbls per day in 2008, primarily reflecting the impact of our divestments in 2008 (5.5 MBbls per day).

Gas revenues decreased $119.6 million to $62.4 million in 2009 from $182.0 million in 2008 due to a decrease in realized prices ($117.8 million) and decreased sales volumes ($1.8 million). Our average realized price for gas was $3.18 per Mcf in 2009 compared to $9.01 per Mcf in 2008. Gas sales volumes decreased from 219.5 MMcf per day in 2008 to 213.7 MMcf per day in 2009, primarily reflecting the impact of our divestments in 2008 (43.1 MMcf per day). Excluding the impact of our divestments, increased production from the Haynesville Shale and Flatrock properties is responsible for a 21% increase in sales volumes for the three months ended September 30, 2009 compared to the same period a year ago.

Lease operating expenses. Lease operating expenses decreased $16.7 million, to $60.3 million in 2009 from $77.0 million in 2008. Excluding costs associated with the properties sold in 2008, lease operating expenses decreased by $4.9 million, primarily reflecting the implementation of our program to reduce expenses. On a per unit basis, lease operating expenses decreased to $7.89 per BOE in 2009 versus $9.06 per BOE in 2008 due primarily to the implementation of our cost reduction program.

Steam gas costs. Steam gas costs decreased $26.4 million, to $11.0 million in 2009 from $37.4 million in 2008, primarily reflecting the lower cost of gas used in steam generation. In 2009, we burned approximately 3.7 billion cubic feet ("Bcf") of natural gas at a cost of approximately $2.95 per MMBtu compared to
4.2 Bcf at a cost of approximately $8.99 per MMBtu in 2008.

Electricity. Electricity decreased $3.8 million, to $10.6 million in 2009 from $14.4 million in 2008, reflecting a decrease in rates, primarily in California. On a per unit basis, electricity was $1.39 per BOE in 2009 compared to $1.69 per BOE in 2008.

Production and ad valorem taxes. Production and ad valorem taxes decreased $19.4 million, to $7.9 million in 2009 from $27.3 million in 2008, primarily reflecting lower commodity prices and the divestments in 2008.

Gathering and transportation expense. Gathering and transportation expenses increased $5.9 million, to $10.3 million in 2009 from $4.4 million in 2008, primarily reflecting an increase in production from our Flatrock and Haynesville Shale properties.

General and administrative expense. G&A expense increased $7.0 million, to $36.4 million in 2009 from $29.4 million in 2008. The increase is primarily due to an increase in stock-based compensation expense ($6.9 million), which offset a decrease in cash costs between the two periods due to our cost reduction program. In 2009, our increased stock price resulted in a larger compensation expense compared to 2008 where we recognized a negative expense from declining stock prices during the second half of 2008.

Depreciation, depletion and amortization, or DD&A. DD&A expense decreased $38.2 million, to $101.8 million in 2009 from $140.0 million in 2008. The decrease is attributable to our oil and gas depletion, primarily due to a lower per unit rate ($26.2 million) and decreased production ($10.8 million). Our oil and gas unit of production rate decreased to $12.66 per BOE in 2009 compared to $15.71 per BOE in 2008. The decrease primarily reflects the 2008 year-end impairment of our oil and gas properties, which reduced our DD&A rate in subsequent periods.

Other operating (income) expense. Other operating income in 2009 consists primarily of a reduction in preacquisition operating expense accruals related to our acquisition of Pogo Producing Company in 2007, partially offset by idle drilling equipment costs resulting from unused contract commitments.

Interest expense. The following table reflects our interest expense and capitalized interest for the three months ended September 30, 2009 and 2008 (in thousands):

                                                      Three Months Ended
                                                         September 30,
                                                      2009          2008

          Interest expense before capitalization    $  47,805     $  52,225
          Capitalized interest                        (31,450)      (19,231)

          Total interest expense                    $  16,355     $  32,994

Net interest expense decreased due to an increase in capitalized interest of $12.2 million and a decrease in interest expense before capitalization of $4.4 million. The increase in capitalized interest is attributable to a higher average interest rate during 2009. The decrease in interest before capitalization is attributable to lower outstanding debt in 2009, which more than offset the effect of higher interest rates.

Gain 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 our making a payment to or receiving a payment from the counterparty.

We recognized a $14.8 million mark-to-market derivative gain in the third quarter of 2009, which was primarily associated with an increase in the fair value of our 2010 crude oil puts and 2009 natural gas collars due to lower crude oil and natural gas prices. In the third quarter of 2008, we recognized a $451.1 million mark-to-market derivative gain primarily associated with the crude oil puts which we monetized in the first quarter of 2009 (See Recent Developments - Derivatives).

Income taxes. During interim periods income tax expense is based on the estimated annual effective income tax rate plus any significant unusual or infrequently occurring items 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 related to domestic production, and
(3) state income taxes.

For the third quarter of 2009, our income tax expense was approximately 46% of pre-tax income. The effective tax rate of 46% for the quarter results primarily from changes in the relationship of 2009 estimated pre-tax income relative to estimated permanent differences. For the third quarter of 2008, income tax expense was approximately 37% of pre-tax income.

Comparison of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2008

Oil and gas revenues. Oil and gas revenues decreased $1.3 billion, to $818.1 million for 2009 from $2.1 billion for 2008 primarily due to a decrease in realized prices of $45.05 per BOE and a 12% decrease in sales volumes primarily associated with our 2008 property divestments. Excluding the impact of our divestments, increased production from the Haynesville Shale and Flatrock properties is responsible for an 8% increase in sales volumes in the first nine months of 2009 compared to the same period a year ago.

Oil revenues decreased $905.3 million to $625.8 million for 2009 from $1.5 billion for 2008 reflecting lower average realized prices ($803.6 million) and lower sales volumes ($101.7 million). Our average realized price for oil decreased $52.19 to $47.24 per Bbl for 2009 from $99.43 per Bbl for 2008. Oil sales volumes decreased 7.7 MBbls per day to 48.5 MBbls per day in 2009 from
56.2 MBbls per day in 2008, primarily reflecting the impact of our divestments in 2008 (7.1 MBbls per day).

Gas revenues decreased $336.2 million to $192.2 million in 2009 from $528.4 million in 2008 due to a decrease in realized prices ($319.7 million) and decreased sales volumes ($16.5 million). Our average realized price for gas was $3.56 per Mcf in 2009 compared to $9.00 per Mcf in 2008. Gas sales volumes decreased from 214.1 MMcf per day in 2008 to 197.9 MMcf per day in 2009, primarily reflecting the impact of our divestments in 2008 (57.5 MMcf per day). Excluding the impact of our divestments, increased production from the Haynesville Shale and Flatrock properties is responsible for a 26% increase in sales volumes in the first nine months of 2009 compared to the same period a year ago.

Lease operating expenses. Lease operating expenses decreased $42.1 million, to $194.6 million in 2009 from $236.7 million in 2008. Excluding costs associated with the properties sold in 2008, lease operating expenses decreased by $11.9 million, primarily reflecting the implementation of our program to reduce expenses. On a per unit basis, lease operating expenses decreased to $8.75 per BOE in 2009 versus $9.40 per BOE in 2008 due primarily to the implementation of our cost reduction program in 2009.

Steam gas costs. Steam gas costs decreased $72.8 million, to $37.4 million in 2009 from $110.2 million in 2008, primarily reflecting lower cost of gas used in steam generation. In 2009, we burned approximately 11.3 Bcf of natural gas at a cost of approximately $3.31 per MMBtu compared to 12.5 Bcf at a cost of approximately $8.80 per MMBtu in 2008.

Electricity. Electricity decreased $2.8 million, to $33.9 million in 2009 from $36.7 million in 2008, primarily reflecting a decrease in rates, primarily in California. On a per unit basis, electricity was $1.52 per BOE in 2009 compared to $1.46 per BOE in 2008.

Production and ad valorem taxes. Production and ad valorem taxes decreased $47.8 million, to $30.0 million in 2009 from $77.8 million in 2008, primarily reflecting lower commodity prices and the divestments in 2008.

Gathering and transportation expense. Gathering and transportation expenses increased $10.3 million, to $25.7 million in 2009 from $15.4 million in 2008, primarily reflecting an increase in production from our Haynesville Shale and Flatrock properties.

General and administrative expense. G&A expense decreased $3.4 million, to $111.1 million in 2009 from $114.5 million in 2008. The decrease is primarily due to cost reductions in 2009, partially offset by higher stock based compensation expense. In 2009, our increased stock price resulted in a larger compensation expense compared to 2008 where we recognized a negative expense from declining stock prices during the second half of 2008.

Depreciation, depletion and amortization, or DD&A. DD&A expense decreased $130.9 million, to $280.7 million in 2009 from $411.6 million in 2008. The decrease is attributable to our oil and gas DD&A, primarily due to a lower per unit rate ($97.5 million) and decreased production ($34.4 million). Our oil and gas unit of production rate decreased to $11.89 per BOE in 2009 compared to $15.72 per BOE in 2008. The decrease primarily reflects the 2008 year-end impairment of our oil and gas properties, which has reduced our depletion rate in subsequent periods.

Legal recovery. In the second quarter, we received a net recovery of $87.3 million as our share of the $1 billion judgment for all lessees of the 35 leases involved in the lawsuit Amber Resources Company et al. v. United States.

Other operating (income) expense. Other operating income/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 partially offset by a reduction in preacquisition operating expense accruals related to our acquisition of Pogo Producing Company in 2007.

Gain on sale of assets. In February 2008, we completed the sale to a subsidiary of 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. The following table reflects our interest expense and capitalized interest for the nine months ended September 30, 2009 and 2008 (in thousands):

                                                       Nine Months Ended
                                                         September 30,
                                                      2009           2008
         Interest expense before capitalization    $  134,969     $  136,044
         Capitalized interest                         (80,682)       (48,930)

         Total interest expense                    $   54,287     $   87,114

Net interest expense decreased primarily due to an increase in capitalized interest of $31.8 million. The increase in capitalized interest is attributable to a higher average interest rate and higher unevaluated property balances associated with our Haynesville Shale properties.

Debt extinguishment costs. In connection with reductions of the commitments on our senior revolving credit facility, we recorded $12.1 million and $13.4 million of debt extinguishment costs in the nine months ended September 30, 2009 and 2008, respectively.

Gain 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 a $13.2 million gain related to mark-to-market derivative contracts in the nine months ended September 30, 2009, which was primarily associated with an increase in the fair value of our 2009 natural gas collars due to lower natural gas prices. In the nine months ended September 30, 2008, we . . .