The following discussion should be read in conjunction with management's discussion and analysis contained in our 2008 Annual Report on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

Gas, Natural Gas Liquids and Oil Production and Prices



                                     Three Months Ended September 30                         Nine Months Ended September 30
                                                                   Increase                                               Increase
                                  2009              2008          (Decrease)             2009              2008          (Decrease)
Total production
Gas (Mcf)                       222,691,397       179,348,090             24 %         637,217,522       498,123,918             28 %
Natural gas liquids
(Bbls)                            2,024,880         1,427,555             42 %           5,557,962         4,298,364             29 %
Oil (Bbls)                        6,055,593         5,302,631             14 %          18,258,504        14,659,078             25 %
Mcfe                            271,174,235       219,729,206             23 %         780,116,318       611,868,570             27 %

Average daily production
Gas (Mcf)                         2,420,559         1,949,436             24 %           2,334,130         1,817,971             28 %
Natural gas liquids
(Bbls)                               22,010            15,517             42 %              20,359            15,687             30 %
Oil (Bbls)                           65,822            57,637             14 %              66,881            53,500             25 %
Mcfe                              2,947,546         2,388,361             23 %           2,857,569         2,233,097             28 %

Average sales price
Gas per Mcf                   $        6.93     $        8.42            (18 )%      $        7.08     $        8.22            (14 )%
Natural gas liquids per
Bbl                           $       30.59     $       53.65            (43 )%      $       26.87     $       55.14            (51 )%
Oil per Bbl                   $      108.04     $       93.40             16 %       $      106.61     $       88.55             20 %

Average sales price
before hedging
Gas per Mcf                   $        3.22     $        9.31            (65 )%      $        3.52     $        9.07            (61 )%
Natural gas liquids per
Bbl                           $       30.59     $       60.51            (49 )%      $       26.87     $       61.21            (56 )%
Oil per Bbl                   $       63.48     $      113.09            (44 )%      $       52.28     $      109.78            (52 )%

Average NYMEX prices
Gas per MMBtu                 $        3.39     $       10.24            (67 )%      $        3.93     $        9.73            (60 )%
Oil per Bbl                   $       68.25     $      118.52            (42 )%      $       57.09     $      113.49            (50 )%

Bbl-Barrel

Mcf-Thousand cubic feet

Mcfe-Thousand cubic feet of natural gas equivalent (computed on an energy equivalent basis of one Bbl equals six Mcf)

MMBtu-One million British Thermal Units, a common energy measurement

Production increases from 2008 to 2009 for the three- and nine-month periods are primarily because of development activity and acquisitions, partially offset by natural decline.

Gas prices decreased from 2008 to 2009. Natural gas prices are affected by the level of North American production, weather, crude oil prices, the U.S. economy, storage levels and import levels of liquefied natural gas. Natural gas competes with other energy sources as fuel for heating and the generation of electricity. In the first part of 2008, prices for natural gas increased significantly reaching as high as $13 per MMBtu in July 2008. Since that date, prices have dropped due to higher than average gas in storage caused by shale gas development and declining demand due to the U.S. recession. Natural gas prices are expected to remain volatile. The NYMEX contract price for October 2009 was $3.73 per MMBtu. At October 30, 2009, the average NYMEX futures price for the following twelve months was $5.61 per MMBtu.

Oil prices before hedging and average NYMEX oil prices decreased from 2008 to 2009. Crude oil prices are generally determined by global supply and demand. In the first part of 2008, prices for oil increased significantly reaching a record high above $147 per Bbl in July 2008. However, lower demand as a result of the global economic situation caused oil prices to decline to below $40 last winter. Signs of possible economic improvement have resulted in higher recent oil prices. Oil prices are expected to remain volatile. The average NYMEX price for October 2009 was $75.70 per Bbl. At October 30, 2009, the average NYMEX futures price for the following twelve months was $79.91 per Bbl.

We use price hedging arrangements, including fixed-price physical delivery contracts, to reduce price risk on a portion of our production. We have hedged most of our crude oil sales through December 2010 and a portion of our natural gas sales through December 2011; see Note 6 to Consolidated Financial Statements.

Results of Operations

Quarter Ended September 30, 2009 Compared with Quarter Ended September 30, 2008

Net income for third quarter 2009 was $500 million compared to $521 million for third quarter 2008. Third quarter 2009 earnings include a $15 million ($9 million after tax) non-cash derivative fair value loss. Third quarter 2008 earnings include a $38 million ($24 million after tax) non-cash derivative fair value loss. Operating income for the quarter was $919 million, a 5% decrease from third quarter 2008 operating income of $969 million.

Total revenues for third quarter 2009 were $2.29 billion, an 8% increase from third quarter 2008 revenues of $2.13 billion. Gas and natural gas liquids revenues increased $19 million because of the 24% increase in gas production and the 42% increase in natural gas liquids production, partially offset by the 18% decrease in gas prices and the 43% decrease in natural gas liquids prices. Oil revenue increased $159 million because of the 14% increase in production and the 16% increase in oil prices.

Expenses for third quarter 2009 totaled $1.37 billion, an 18% increase from third quarter 2008 expenses of $1.16 billion. Increased expenses are generally related to increased production from development and acquisitions and related Company growth. Production expense decreased $14 million primarily because of lower power, fuel, compression, workovers and water disposable costs, partially offset by increased overall production and increased maintenance costs. Taxes, transportation and other decreased $32 million from the third quarter of 2008 primarily because of lower production taxes and transportation costs due to lower product prices before hedging, partially offset by higher property taxes related to development and the 2008 acquisitions. Depreciation, depletion and amortization increased $313 million because of higher acquisition, development and facility costs and increased production. Exploration expense decreased $20 million primarily because of decreased seismic costs in the Gulf of Mexico. General and administrative expense decreased $3 million because of a $10 million decrease in non-cash incentive compensation, partially offset by increased other general and administrative expense primarily due to higher employee expenses related to Company growth.

The derivative fair value loss for third quarter 2009 was $2 million compared to $45 million in the same 2008 period. The loss in 2009 is primarily related to natural gas basis swaps that do not qualify for hedge accounting, partially offset by certain crude oil swap agreements that do not qualify for hedge accounting. See Note 5 to Consolidated Financial Statements.

Interest expense increased $4 million primarily because of a decrease in interest income. The effective income tax rate for third quarter 2009 was 36.1% compared with 37.8% for third quarter 2008. The lower 2009 rate is due to the expected benefits of permanent tax differences.

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

Net income for the nine months ended September 30, 2008 was $1.48 billion, compared to $1.56 billion for the same 2008 period. Earnings for the first nine months of 2009 include a $122 million ($78 million after tax) non-cash derivative fair value loss and a $17 million ($11 million after tax) gain on extinguishment of debt. Earnings for the first nine months of 2008 include an $11 million ($7 million after tax) non-cash derivative fair value gain. Operating income for the first nine months of 2009 was $2.70 billion, a 4% decrease from operating income of $2.80 billion for the comparable 2008 period.

Total revenues for the first nine months of 2009 were $6.72 billion, 17% higher than revenues of $5.73 billion for the first nine months of 2008. Gas and natural gas liquids revenues increased $326 million primarily because of the 28% increase in gas production and the 29% increase in natural gas liquids production, partially offset by the 14% decrease in gas prices and the 51% decrease in natural gas liquids prices. Oil revenue increased $649 million because of the 25% increase in production and the 20% increase in prices.

Expenses for the first nine months of 2009 totaled $4.02 billion, a 37% increase from total expenses for the first nine months of 2008 of $2.94 billion. Increased expenses are generally related to increased production from development and acquisitions and related Company growth. Production expense increased $81 million primarily because of increased overall production and increased maintenance costs, partially offset by decreased power, fuel and carbon dioxide injection costs. Taxes, transportation and other decreased $52 million primarily because of lower production taxes and transportation costs due to lower product prices before hedging, partially offset by higher property taxes related to development and the 2008 acquisitions. Depreciation, depletion and amortization increased $999 million because of higher acquisition, development and facility costs and increased production. Exploration expense increased $2 million primarily because of increased dry hole expense, partially offset by decreased seismic costs. General and administrative expense increased $14 million because of increased other general and administrative expense primarily due to higher employee expenses related to Company growth.

The derivative fair value loss for the first nine months of 2009 was $17 million compared to a $3 million loss in the same 2008 period. The 2009 loss is primarily related to natural gas basis swaps and crude oil swap agreements that do not qualify for hedge accounting, partially offset by the ineffective portion of hedge derivatives.

Interest expense increased $63 million primarily because of a 23% increase in the weighted average borrowings incurred primarily to fund acquisitions, partially offset by a $17 million gain on extinguishment of debt. The 2009 year-to-date effective income tax rate was 35.8% compared with a 36.9% effective rate for the nine-month 2008 period. The lower 2009 rate is due to the expected benefits of permanent tax differences.

Comparative Expenses per Mcf Equivalent Production

The following are expenses on an Mcf equivalent (Mcfe) produced basis:



                                        Three Months Ended                        Nine Months Ended
                                           September 30                              September 30
                                                         Increase                                  Increase
                                  2009        2008      (Decrease)          2009        2008      (Decrease)
Production                      $   0.92    $   1.19           (23 )%     $   0.96    $   1.10           (13 )%
Taxes, transportation and
other                               0.64        0.94           (32 )%         0.64        0.90           (29 )%
Depreciation, depletion and
amortization (DD&A)                 2.99        2.27            32 %          2.94        2.12            39 %
General and administrative
(G&A):
Non-cash incentive
compensation                        0.10        0.17           (41 )%         0.14        0.18           (22 )%
All other G&A                       0.19        0.21           (10 )%         0.21        0.25           (16 )%
Interest                            0.50        0.60           (17 )%         0.50        0.53            (6 )%

The following are explanations of expense variances on an Mcfe basis:

Production expenses-Decreased production expense is primarily because of decreased power, fuel, compression, carbon dioxide injection and water disposal costs. Power, fuel and carbon dioxide injection costs vary with product prices. Additionally, third quarter 2009 benefited from decreased workover costs.

Taxes, transportation and other-A portion of these expenses vary with product prices. Decreased taxes, transportation and other expense is primarily because of lower product prices, before hedging, partially offset by higher property taxes primarily due to development and the 2008 acquisitions.

DD&A-Increased DD&A is primarily because of higher acquisition, development and infrastructure costs per Mcfe as well as the effect of net downward revisions to proved oil and gas reserves due to lower commodity prices.

G&A-Decreased non-cash incentive compensation and decreased all other G&A expense is due to increased production outpacing personnel and other expenses related to Company growth.

Interest-Decreased interest expense for the third quarter is due to increased production. Interest expense decreased for the nine months because of increased production and a gain on extinguishment of debt of $17 million, which was partially offset by the 23% increase in weighted average borrowings to fund our 2008 acquisitions.

Liquidity and Capital Resources

Cash Flow and Working Capital

Cash provided by operating activities was $5.24 billion for the first nine months of 2009, compared with $3.75 billion for the same 2008 period. Increased cash provided by operating activities is due in part to production from development activity and acquisitions. Also, 2009 benefited from the early settlement and reset arrangements with seven of our financial counterparties. In January 2009, we entered into early settlement and reset arrangements with seven financial counterparties covering a portion of our 2009 natural gas and crude oil hedge volumes. As a result of these early settlements, we received approximately $2.2 billion which was used primarily to reduce outstanding debt. This has been partially offset by the amortization of these early settlements to oil and gas revenue. Cash provided by operating activities was increased by changes in operating assets and liabilities of $708 million in first nine months 2009 and decreased by $2 million in first nine months 2008. Changes in operating assets and liabilities are primarily the result of the timing of cash receipts and disbursements. Cash flow from operating activities was also reduced by exploration expense, excluding dry hole expense, of $29 million in first nine months 2009 and $55 million in first nine months 2008.

During the nine months ended September 30, 2009, cash provided by operating activities of $5.24 billion was used to fund development costs, net property acquisitions and other net capital additions of $3.25 billion, dividends of $215 million and to pay down $1.56 billion of debt. The resulting decrease in cash and cash equivalents for the period was $1 million.

Total current assets decreased $1.97 billion during the first nine months of 2009 primarily because of a $1.51 billion decrease in derivative fair value as a result of cash settlements of derivatives during the period and decreased accounts receivable due to lower product prices, excluding hedges. Total current liabilities decreased $562 million during the first nine months of 2009 primarily because of a decrease in deferred income taxes related to derivatives and decreased accounts payable and accrued liabilities due to lower commodity prices, excluding hedges, and lower drilling activity, partially offset by the increase in current maturities of long-term debt.

Working capital decreased from a positive position of $1.33 billion at December 31, 2008 to a negative position of $75 million at September 30, 2009. Excluding the effects of derivative fair value and deferred tax current liabilities, working capital decreased from a negative position of $432 million at December 31, 2008 to a negative position of $672 million at September 30, 2009. Any interim cash needs are funded by borrowings under either our revolving credit agreement, our other unsecured and uncommitted lines of credit, or our commercial paper program.

Acquisitions and Development

Exploration and development expenditures for the first nine months of 2009 were $2.59 billion compared with $2.55 billion for the first nine months of 2008. Our 2009 development and exploration budget is $3.1 billion and our budget for construction of pipeline infrastructure and compression and processing facilities is $500 million. We expect these expenditures to be funded by cash flow from operations. Actual costs may vary significantly due to many factors, including development results and changes in drilling and service costs. We also may reevaluate our budget and drilling programs as a result of significant changes in oil and gas prices.

In the first nine months of 2009, we completed acquisitions of both producing and unproved properties for $199 million compared to $7.62 billion for the first nine months of 2008. These acquisitions were funded by cash provided by operating activities and are subject to typical post-closing adjustments.

While we expect to continue focusing on development activities in the remainder of 2009, as a course of business, we review acquisition opportunities. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, our commercial paper program, issuance of public or private debt or equity, or asset sales. Other than the requirement for us to maintain a debt-to-total capitalization ratio of not more than 65%, there are no restrictions under our revolving credit agreement that would affect our ability to use our remaining borrowing capacity.

Through the first nine months of 2009, we participated in drilling approximately 772 gas wells and 65 oil wells and performed 153 workovers. Our year-to-date gas drilling activity was concentrated in East Texas and the Barnett, Fayetteville and Woodford shales, and our year-to-date oil drilling activity was concentrated in the Permian Basin and Bakken Shale. Workovers have focused on recompletions, artificial lift and wellhead compression. These projects generally have met or exceeded management expectations.

Debt and Equity

On September 30, 2009, we had no borrowings under our revolving credit agreement with commercial banks, and we had available borrowing capacity of $2.32 billion net of our commercial paper borrowings. We use the facility for general corporate purposes and as a backup facility for our commercial paper program. We have the option, with bank approval, to increase the commitment up to an additional $660 million. The interest

rate on any borrowing is generally based on the one-month LIBOR plus 0.40%. When utilization of available commitments is greater than 50%, the interest rate on our borrowings is increased by 0.05%. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. We also incur a commitment fee on unused borrowing commitments, which is 0.09%. The agreement requires us to maintain a debt-to-total capitalization ratio of not more than 65%.

Our commercial paper program availability is $2.84 billion. Borrowings under the commercial paper program reduce our available capacity under the revolving credit facility on a dollar-for-dollar basis. The commercial paper borrowings may have terms up to 397 days and bear interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market. On September 30, 2009, borrowings were $520 million at a weighted average interest rate of 0.4%.

We have unsecured and uncommitted lines of credit with commercial banks totaling $300 million. As of September 30, 2009, there were no borrowings under these lines.

Repurchase of Senior Notes

In the first and second quarters of 2009, we repurchased $200 million total face amount of senior notes, including $2 million of our 5.0% senior notes due 2015, $15 million of our 6.25% senior notes due 2017, $27 million of our 5.5% senior notes due 2018, $9 million of our 6.1% senior notes due 2036, $51 million of our 6.75% senior notes due 2037 and $96 million of our 6.375% senior notes due 2038. In connection with these repurchases, we recognized a $17 million gain on extinguishment of debt in the first nine months of 2009, net of unamortized discounts and the write-off of deferred debt offering costs. These gains were netted against interest expense in the consolidated income statements. There were no repurchases of senior notes in third quarter 2009.

Common Stock Dividends

In August 2009, the Board of Directors declared a third quarter 2009 dividend of $0.125 per share that was paid in October to stockholders of record on September 30, 2009.

Contractual Obligations and Commitments

The following summarizes our significant obligations and commitments to make
future contractual payments as of September 30, 2009. We have not guaranteed the
debt or obligations of any other party, nor do we have any other arrangements or
relationships with other entities that could potentially result in
unconsolidated debt or losses.



                                                                  Payments Due by Year
(in millions)                     Total       2009     2010     2011       2012        2013      After 2013
Debt                            $   10,420   $    -    $ 250   $    -    $    900   $    2,420   $     6,850
Operating leases                        86         8      29        23         14            8             4
Drilling contracts                     163        48      91        22          2           -             -
Purchase commitments                    32        14      18        -          -            -             -
Transportation contracts             1,486        41     173       185        185          179           723
Derivative contract
liabilities at September 30,
2009 fair value
                                       238       128     106         2          2           -             -

Total                           $   12,425   $   239   $ 667   $   232   $  1,103   $    2,607   $     7,577

Debt. Debt amounts represent scheduled maturities of our debt obligations at September 30, 2009, excluding $35 million of net discounts on our senior notes included in the carrying value of debt. At September 30, 2009,

borrowings were $520 million under our commercial paper program. Because we had the intent and ability to refinance the balance due with borrowings under our credit facility due in April 2013, the $520 million outstanding under the commercial paper program is reflected in the table above as due in 2013. Borrowings of $600 million under our term loans are due in 2013, and our senior notes, totaling $9.3 billion are due 2010 through 2038. For further information regarding debt, see Note 3 to Consolidated Financial Statements.

Drilling Contracts. We have contracts with various drilling contractors to use 45 drilling rigs with terms of up to three years. Early termination of these contracts at September 30, 2009 would have required us to pay maximum penalties of $89 million. Based upon our planned drilling activities, we do not expect to pay significant early termination penalties.

Transportation Contracts. We have entered firm transportation contracts with various pipelines for various terms through 2022. Under these contracts we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. We have generally delivered at least minimum volumes under these firm transportation contracts, therefore avoiding payment for deficiencies.

In November 2008, we completed an agreement to enter into a twelve-year firm transportation contract, contingent upon obtaining regulatory approvals and completion of a new pipeline that connects the Fayetteville Shale to ANR Pipeline and Trunkline Pipeline in Quitman County, Mississippi. Upon the pipeline's completion, currently expected in fourth quarter 2010, we will transport gas volumes for a transportation fee of up to $1.25 million per month plus fuel, currently expected to be 0.86% of the sales price. The potential effect of this agreement is not included in the above summary of our transportation contract commitments since our commitment is contingent upon completion of the pipeline.

Derivative Contracts. We have entered into futures contracts and swaps to hedge our exposure to oil and natural gas price fluctuations. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of September 30, 2009, the current liability related to such contracts was $186 million and the noncurrent liability was $52 million. While such payments generally will be funded by higher prices received from the sale of our production, production receipts are received as much as 55 days after payment to counterparties and can result in draws on our revolving credit facility, our other unsecured and uncommitted lines of credit or our commercial paper program. See Note 5 to Consolidated Financial Statements.

Accounting Pronouncements

In May 2009, the Financial Accounting Standards Board established general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The new rule sets forth the period after the balance sheet date during which management should evaluate any events or transactions for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize such events or transactions in its financial statements, and the disclosures that an entity should make about such events or transactions. We have evaluated subsequent events through November 4, 2009.

In December 2008, the Securities and Exchange Commission (SEC) released Final Rule, Modernization of Oil and Gas Reporting. The new disclosure requirements . . .