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 cash balances, our senior revolving credit facility and periodic public offerings of debt and equity. At June 30, 2009, we had approximately $1.34 billion available for future secured borrowings under our senior revolving credit facility and $455.8 million in cash and cash equivalents. We believe that we have sufficient liquidity through our forecasted cash flow from operations, cash balances, 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

During the first half 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 to our commodity price risk management agreements, our insurers and our oil and gas purchasers. See Liquidity and Capital Resources.

Recent Developments

Haynesville Shale Joint Venture

On August 6, 2009, we announced an amendment to the joint venture agreement with Chesapeake that accelerates the payment of our remaining commitment to fund 50% of Chesapeake's share of drilling and completion costs for future Haynesville Shale wells, which we refer to as the Haynesville Carry. In an amendment to the Haynesville Shale participation agreement, we agree to pay $1.1 billion for the remaining Haynesville Carry balance due to Chesapeake as of September 30, 2009, estimated at $1.25 billion. This payment represents an approximate 12% reduction in the total amount due. Additionally, Chesapeake has committed to drill at least 150 wells per year under the participation agreement for the three year period starting October 1, 2009. Further, we have agreed to terminate our one-time option exercisable in June of 2010 to avoid paying the last $800 million of the Haynesville Carry in exchange for an assignment to Chesapeake of 50% of our interest in our Haynesville acreage. Closing of the transaction is expected to occur September 29, 2009.

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.

Legal Settlement Recovery

On May 11, 2009, the United States Government certified payment of the $1 billion judgment in full to all lessees of the 35 leases involved in the lawsuit Amber Resources Company et al. v. United States, Case No. 02-30c. In the second quarter, we received a net recovery of $87.3 million as our share of the $1 billion award.

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 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 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

In the first half of 2009, we reported net income of $48.8 million, or $0.43 per diluted share, compared to net income of $366.4 million, or $3.27 per diluted share, in the first half of 2008. The decrease primarily reflects lower commodity prices.

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           Six Months Ended
                                                     June 30,                    June 30,
                                                2009          2008          2009          2008
Sales Volumes
Oil and liquids sales (MBbls)                     4,441         5,019         8,886        10,265
Gas (MMcf)
Production                                       17,972        18,232        35,607        39,598
Used as fuel                                        584           547         1,230         1,135
Sales                                            17,388        17,685        34,377        38,463
MBOE
Production                                        7,435         8,057        14,820        16,864
Sales                                             7,338         7,966        14,615        16,675
Daily Average Volumes
Oil and liquids sales (Bbls)                     48,792        55,153        49,092        56,399
Gas (Mcf)
Production                                      197,500       200,358       196,727       217,573
Used as fuel                                      6,422         6,015         6,797         6,236
Sales                                           191,078       194,343       189,930       211,337
BOE
Production                                       81,710        88,546        81,880        92,662
Sales                                            80,638        87,543        80,747        91,622
Unit Economics (in dollars)
Average NYMEX Prices
Oil                                          $    59.79     $  123.80     $   51.68     $  111.12
Gas                                                3.50         10.90          4.17          9.50
Average Realized Sales Price Before
Derivative Transactions
Oil (per Bbl)                                $    49.44     $  108.74     $   42.33     $   97.65
Gas (per Mcf)                                      3.37         10.31          3.77          9.01
Per BOE                                           37.90         91.40         34.62         80.89
Costs and Expenses per BOE
Production costs
Lease operating expenses                     $     8.64     $   10.70     $    9.19     $    9.58
Steam gas costs                                    1.49          5.10          1.81          4.36
Electricity                                        1.69          1.34          1.59          1.34
Production and ad valorem taxes                    1.43          3.04          1.51          3.02
Gathering and transportation                       1.18          0.31          1.05          0.66
Depreciation, depletion and amortization
of oil and gas properties ("DD&A")           $    11.49     $   15.70     $   11.49     $   15.73

Comparisons between the periods are affected by the February 2008 divestiture of 50% of our working interest in the Piceance and Permian Basins, the San Juan Basin and Barnett Shale, the April 2008 acquisition of South Texas properties 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               Six Months Ended
                                                     June 30,                        June 30,
                                                2009          2008              2009           2008
Mark-to-market derivative contracts
Oil sales
Settlements                                  $    2,716     $ (20,844 )      $   159,592     $ (43,108 )
Monetization of crude oil puts and swaps             -             -           1,074,361            -
Gas sales                                        83,449            -             147,761           427

                                             $   86,165     $ (20,844 )      $ 1,381,714     $ (42,681 )

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

Oil and gas revenues. Oil and gas revenues decreased $450.0 million, to $278.1 million for 2009 from $728.1 million for 2008 primarily due to a decrease in realized prices of $53.50 per BOE and an 8% decrease in sales volumes.

Oil revenues decreased $326.2 million to $219.6 million for 2009 from $545.8 million for 2008 reflecting lower average realized prices ($297.6 million) and lower sales volumes ($28.6 million). Our average realized price for oil decreased $59.30 to $49.44 per Bbl for 2009 from $108.74 per Bbl for 2008. The decrease is primarily attributable to a decline in the NYMEX oil price, which averaged $59.79 per Bbl in 2009 versus $123.80 per Bbl in 2008. Oil sales volumes decreased 6.4 MBbls per day to 48.8 MBbls per day in 2009 from
55.2 MBbls per day in 2008, primarily reflecting the divestments in 2008 (5.9 MBbls per day), partially offset by increased production from our Flatrock and South Texas properties.

Gas revenues decreased $123.8 million to $58.5 million in 2009 from $182.3 million in 2008 due to a decrease in realized prices ($122.8 million) and decreased sales volumes ($1.0 million). Our average realized price for gas was $3.37 per Mcf in 2009 compared to $10.31 per Mcf in 2008. Our realized price for gas decreased primarily due to a decrease in the NYMEX natural gas price, which averaged $3.50 per MMBtu in 2009 versus $10.90 per MMBtu in 2008. Gas sales volumes decreased from 194.3 MMcf per day in 2008 to 191.1 MMcf per day in 2009, primarily reflecting the divestments in 2008 (47.1 MMcf per day), partially offset by increased production from our Flatrock and Haynesville Shale properties.

Lease operating expenses. Lease operating expenses decreased $21.8 million, to $63.4 million in 2009 from $85.2 million in 2008. Excluding costs associated with the properties sold in 2008, lease operating expenses decreased by $15.9 million, primarily reflecting the implementation of our program to reduce expenses, as well as a decrease in stock-based compensation expense. On a per unit basis, lease operating expenses decreased to $8.64 per BOE in 2009 versus $10.70 per BOE in 2008 due primarily to the implementation of our cost reduction program.

Steam gas costs. Steam gas costs decreased $29.7 million, to $10.9 million in 2009 from $40.6 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 $2.94 per MMBtu compared to
4.2 Bcf at a cost of approximately $9.70 per MMBtu in 2008.

Electricity. Electricity increased $1.7 million, to $12.4 million in 2009 from $10.7 million in 2008, primarily reflecting an increase in usage. On a per unit basis, electricity was $1.69 per BOE in 2009 compared to $1.34 per BOE in 2008.

Production and ad valorem taxes. Production and ad valorem taxes decreased $13.7 million, to $10.5 million in 2009 from $24.2 million in 2008, primarily reflecting the divestments in 2008 and lower commodity prices.

Gathering and transportation expense. Gathering and transportation expenses increased $6.2 million, to $8.7 million in 2009 from $2.5 million in 2008, primarily reflecting an increase in production from our Haynesville Shale and Flatrock properties.

General and administrative expense. G&A expense decreased $7.6 million, to $37.6 million in 2009 from $45.2 million in 2008. The decrease is primarily due to a decrease in stock-based compensation and the implementation of a cost reduction program.

Depreciation, depletion and amortization, or DD&A. DD&A expense decreased $39.9 million, to $90.8 million in 2009 from $130.7 million in 2008. The decrease is attributable to our oil and gas depletion, primarily due to a lower per unit rate ($33.9 million) and decreased production ($7.1 million). Our oil and gas unit of production rate decreased to $11.49 per BOE in 2009 compared to $15.70 per BOE in 2008. The decrease primarily reflects the 2008 year-end impairment of our oil and gas properties, which has reduced our DD&A rate in subsequent periods.

Legal Settlement 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, Case No. 02-30c.

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

                                              Three Months Ended
                                                   June 30,
                                             2009           2008
                  Interest expense         $  45,464      $  35,561
                  Capitalized interest       (29,529 )      (12,050 )

                  Total interest expense   $  15,935      $  23,511

Interest expense decreased due to an increase in capitalized interest of $17.5 million offset by an increase in interest expense before capitalization of $9.9 million. The increase in interest expense before capitalization is attributable to a higher average interest rate associated with the 75/8% Senior Notes issued in May 2008 and the 10% Senior Notes issued in 2009. The increase in capitalized interest is attributable to higher unevaluated property balances associated with our Haynesville Shale properties and a higher average interest rate.

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

We recognized an $89.7 million loss related to mark-to-market derivative contracts in the second quarter of 2009, which was primarily associated with a decrease in the fair value of our crude oil puts due to higher crude oil prices. In the second quarter of 2008, we recognized a $51.4 million loss related to mark-to-market derivative contracts.

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 for domestic production, and (3) state income taxes.

For the second quarter of 2009, our income tax benefit was approximately negative 105% of pre-tax income. The effective tax rate of negative 105% for the quarter results primarily from changes in the relationship of 2009 estimated pre-tax income relative to estimated permanent differences together with specific items affecting income tax expense for the quarter which included a significant reduction in our balance of unrecognized tax positions. For the second quarter of 2008, income tax expense was approximately 36% of pre-tax income.

For the second quarter of 2009, our current tax benefit was approximately negative 205% of pre-tax income. This unusual rate is primarily the result of a significant increase in our estimated tax deductions associated with oil and gas drilling expenditures for 2009 together with the effects of temporary differences between the book and tax recognition of income attributable to our oil and gas derivative positions.

Comparison of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2008

Oil and gas revenues. Oil and gas revenues decreased $842.7 million, to $506.0 million for 2009 from $1.3 billion for 2008 primarily due to a decrease in realized prices of $46.27 per BOE and a 12% decrease in volumes primarily associated with our 2008 property sales.

Oil revenues decreased $626.1 million to $376.2 million for 2009 from $1.0 billion for 2008 reflecting lower average realized prices ($567.7 million) and lower sales volumes ($58.4 million). Our average realized price for oil decreased $55.32 to $42.33 per Bbl for 2009 from $97.65 per Bbl for 2008. The decrease is primarily attributable to a decrease in the NYMEX oil price, which averaged $51.68 per Bbl in 2009 versus $111.12 per Bbl in 2008. Oil sales volumes decreased 7.3 MBbls per day to 49.1 MBbls per day in 2009 from
56.4 MBbls per day in 2008, primarily reflecting the divestments in 2008 (8.0 MBbls per day), partially offset by increased production from our Flatrock and South Texas properties.

Gas revenues decreased $216.6 million to $129.8 million in 2009 from $346.4 million in 2008 due to a decrease in realized prices ($201.2 million) and decreased sales volumes ($15.4 million). Our average realized price for gas was $3.77 per Mcf in 2009 compared to $9.01 per Mcf in 2008. Our realized price for gas decreased primarily due to a decrease in the NYMEX natural gas price, which averaged $4.17 per MMBtu in 2009 versus $9.50 per MMBtu in 2008. Gas sales volumes decreased from 211.3 MMcf per day in 2008 to 189.9 MMcf per day in 2009, primarily reflecting the divestments in 2008 (65.2 MMcf per day), partially offset by increased production from our Flatrock and Haynesville Shale properties.

Lease operating expenses. Lease operating expenses decreased $25.5 million, to $134.3 million in 2009 from $159.8 million in 2008. Excluding costs associated with the properties sold in 2008, lease operating expenses decreased by $7.0 million due to lower stock-based compensation and our cost reduction program. On a per unit basis, lease operating expenses decreased to $9.19 per BOE in 2009 versus $9.58 per BOE in 2008 due primarily to lower costs in 2009.

Steam gas costs. Steam gas costs decreased $46.3 million, to $26.5 million in 2009 from $72.8 million in 2008, primarily reflecting lower cost of gas used in steam generation. In 2009, we burned approximately 7.6 Bcf of natural gas at a cost of approximately $3.49 per MMBtu compared to 8.4 Bcf at a cost of approximately $8.70 per MMBtu in 2008.

Production and ad valorem taxes. Production and ad valorem taxes decreased $28.3 million, to $22.1 million in 2009 from $50.4 million in 2008, primarily reflecting the divestments in 2008 and lower commodity prices.

Gathering and transportation expense. Gathering and transportation expenses increased $4.3 million, to $15.3 million in 2009 from $11.0 million in 2008, primarily reflecting an increase in production from our Haynesville Shale and Flatrock properties.

General and administrative expense. G&A expense decreased $10.5 million, to $74.6 million in 2009 from $85.1 million in 2008. The decrease is primarily due to a decrease in stock-based compensation and the implementation of a cost reduction program.

Depreciation, depletion and amortization, or DD&A. DD&A expense decreased $92.7 million, to $178.9 million in 2009 from $271.6 million in 2008. The decrease is attributable to our oil and gas DD&A, primarily due to a lower per unit rate ($71.5 million) and decreased production ($23.5 million). Our oil and gas unit of production rate decreased to $11.49 per BOE in 2009 compared to $15.73 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 Settlement 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, Case No. 02-30c.

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 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 six months ended June 30, 2009 and 2008 (in thousands):

                                               Six Months Ended
                                                   June 30,
                                             2009           2008
                  Interest expense         $  87,165      $  83,818
                  Capitalized interest       (49,233 )      (29,698 )

                  Total interest expense   $  37,932      $  54,120

Interest expense decreased due to an increase in capitalized interest of $19.5 million offset by the increase in interest expense before capitalization of $3.4 million. The increase in interest expense before capitalization was attributable to higher interest rates associated with the 75/8% Senior Notes issued in May 2008 and the 10% Senior Notes issued in 2009. The increase in capitalized interest is attributable to higher unevaluated property balances associated with our Haynesville Shale properties and a higher average interest rate.

Debt extinguishment costs. In connection with reductions of the commitments on our senior revolving credit facility, we recorded $10.9 million and $10.3 million of debt extinguishment costs in the six months ended June 30, 2009 and 2008, respectively.

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 a $1.6 million loss related to mark-to-market derivative contracts in the six months ended June 30, 2009, which was primarily associated with a decrease in the fair value of our crude oil puts due to higher crude oil prices, partially offset by higher fair value on our natural gas collars as a result of decreased gas prices. In the six months ended June 30, 2008, we recognized a . . .