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 June 30                              Six Months Ended June 30
                                                                   Increase                                               Increase
                                  2009              2008          (Decrease)             2009              2008          (Decrease)
Total production
Gas (Mcf)                       214,024,222       163,383,624             31 %         414,526,125       318,775,828             30 %
Natural gas liquids
(Bbls)                            1,885,804         1,417,208             33 %           3,533,082         2,870,809             23 %
Oil (Bbls)                        6,296,297         4,666,351             35 %          12,202,911         9,356,447             30 %
Mcfe                            263,116,828       199,884,978             32 %         508,942,083       392,139,364             30 %

Average daily production
Gas (Mcf)                         2,351,915         1,795,424             31 %           2,290,200         1,751,516             31 %
Natural gas liquids
(Bbls)                               20,723            15,574             33 %              19,520            15,774             24 %
Oil (Bbls)                           69,190            51,279             35 %              67,419            51,409             31 %
Mcfe                              2,891,394         2,196,538             32 %           2,811,835         2,154,612             31 %

Average sales price
Gas per Mcf                   $        7.08     $        8.51            (17 )%      $        7.16     $        8.11            (12 )%
Natural gas liquids per
Bbl                           $       25.52     $       58.87            (57 )%      $       24.74     $       55.88            (56 )%
Oil per Bbl                   $      107.14     $       90.89             18 %       $      105.90     $       85.80             23 %

Average sales price
before hedging
Gas per Mcf                   $        3.24     $       10.20            (68 )%      $        3.68     $        8.93            (59 )%
Natural gas liquids per
Bbl                           $       25.52     $       65.89            (61 )%      $       24.74     $       61.57            (60 )%
Oil per Bbl                   $       56.42     $      121.46            (54 )%      $       46.72     $      107.90            (57 )%

Average NYMEX prices
Gas per MMBtu                 $        3.50     $       10.92            (68 )%      $        4.19     $        9.48            (56 )%
Oil per Bbl                   $       59.83     $      124.28            (52 )%      $       51.51     $      110.98            (54 )%

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 six-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 half 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 July 2009 was $3.95 per MMBtu. At July 31, 2009, the average NYMEX futures price for the following twelve months was $5.27 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 half 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 July 2009 was $64.44 per Bbl. At July 31, 2009, the average NYMEX futures price for the following twelve months was $74.42 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 a portion of our natural gas and oil sales through December 2010; see Note 6 to Consolidated Financial Statements.

Results of Operations

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

Net income for second quarter 2009 was $496 million compared to $575 million for second quarter 2008. Second quarter 2009 earnings include a $28 million ($18 million after tax) non-cash derivative fair value loss and an $8 million ($5 million after tax) gain on extinguishing of debt. Second quarter 2008 earnings include a $35 million ($22 million after tax) non-cash derivative fair value gain.

Total revenues for second quarter 2009 were $2.27 billion, a 17% increase from second quarter 2008 revenues of $1.94 billion. Operating income for the quarter was $898 million, an 11% decrease from second quarter 2008 operating income of $1.01 billion. Gas and natural gas liquids revenues increased $90 million because of the 31% increase in gas production and the 33% increase in natural gas liquids production, partially offset by the 17% decrease in gas prices and the 57% decrease in natural gas liquids prices. Oil revenue increased $251 million because of the 35% increase in production and the 18% increase in oil prices.

Expenses for second quarter 2009 totaled $1.38 billion, a 48% increase from second quarter 2008 expenses of $930 million. Increased expenses are generally related to increased production from development and acquisitions and related Company growth. Production expense increased $32 million primarily because of increased overall production, partially offset by decreased power, fuel and carbon dioxide injection costs. Taxes, transportation and other decreased $27 million from the second 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 $370 million because of increased production and higher acquisition, development and facility costs. Exploration expense increased $6 million primarily because of increased dry hole expense. General and administrative expense increased $9 million primarily because of a $10 million increase in non-cash incentive award compensation.

The derivative fair value loss for second quarter 2009 was $21 million compared to a gain of $26 million in the same 2008 period. The loss in 2009 is primarily related to certain crude oil swap agreements and natural gas basis swap agreements that do not qualify for hedge accounting. See Note 5 to Consolidated Financial Statements.

Interest expense increased $24 million primarily because of a 25% increase in weighted average borrowings incurred primarily to fund our 2008 acquisitions, partially offset by an $8 million gain on extinguishment of debt. The effective income tax rate for second quarter 2009 was 35.8% compared with 36.4% for second quarter 2008. The lower effective income tax rate in 2009 is due to the expected benefits of permanent tax differences.

Six Months Ended June 30, 2009 Compared with Six Months Ended June 30, 2008

Net income for the six months ended June 30, 2009 was $982 million, compared to $1.04 billion for the same 2008 period. Earnings for the first half of 2009 include a $107 million ($69 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 six months of 2008 include a $49 million ($31 million after tax) non-cash derivative fair value gain.

Total revenues for the first half of 2009 were $4.43 billion, 23% higher than revenues of $3.61 billion for the first half of 2008. Operating income for the first half of 2009 was $1.78 billion, a 3% decrease from operating income of $1.83 billion for the comparable 2008 period. Gas and natural gas liquids revenues increased $307 million primarily because of the 30% increase in gas production and the 23% increase in natural gas liquids production, partially offset by the 12% decrease in gas prices and the 56% decrease in natural gas liquids prices. Oil revenue increased $490 million because of the 30% increase in production and the 23% increase in oil prices.

Expenses for the first half of 2009 totaled $2.66 billion, a 49% increase from total expenses for the first half of 2008 of $1.78 billion. Increased expenses are generally related to increased production from development and acquisitions and related Company growth. Production expense increased $95 million primarily because of increased production and increased maintenance costs, partially offset by lower power, fuel and decreased carbon dioxide injection costs. Taxes, transportation and other decreased $20 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 $686 million because of increased production and higher acquisition, development and facility costs. General and administrative expense increased $17 million because of a $9 million increase in non-cash incentive award compensation and increased other general and administrative expense primarily due to higher employee expenses related to Company growth.

The derivative fair value loss for the first six months of 2009 was $15 million compared to a gain of $42 million in the same 2008 period. The loss in 2009 is primarily related to the loss on certain crude oil swap agreements that do not qualify for hedge accounting. See Note 5 to Consolidated Financial Statements.

Interest expense increased $59 million primarily because of a 38% increase in the weighted average borrowings incurred primarily to fund our 2008 acquisitions, partially offset by a $17 million gain on extinguishment of debt. The 2009 year-to-date effective income tax rate was 35.7% compared with a 36.4% effective rate for the six-month 2008 period. The lower effective income tax rate in 2009 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 June 30             Six Months Ended June 30
                                                              Increase                             Increase
                                         2009       2008     (Decrease)         2009      2008    (Decrease)
Production                             $   0.94    $  1.08          (13 )%    $   0.99   $ 1.04           (5 )%
Taxes, transportation and other            0.64       0.97          (34 )%        0.65     0.89          (27 )%
Depreciation, depletion and
amortization (DD&A)                        2.98       2.07           44 %         2.91     2.03           43 %
General and administrative (G&A):
Non-cash stock incentive
compensation                               0.16       0.16           -  %         0.16     0.19          (16 )%
All other G&A                              0.21       0.29          (28 )%        0.22     0.27          (19 )%
Interest                                   0.48       0.51           (6 )%        0.50     0.49            2 %

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

Production expenses-Decreased production expense is primarily because of decreased power, fuel, carbon dioxide injection and water disposal costs. In the first half of 2009, these decreases were partially offset by higher maintenance 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 stock incentive compensation for the six-month period is due to increased production outpacing non-cash incentive compensation. All other G&A expense decreased because of increased production outpacing personnel and other expenses related to Company growth.

Interest-Interest expense decreased slightly for the quarter and increased slightly for the six months because the increase in weighted average borrowings to fund our 2008 acquisitions was offset by increased production and a gain on extinguishment of debt of $8 million in second quarter 2009 and $17 million in the first half of 2009.

Liquidity and Capital Resources

Cash Flow and Working Capital

Cash provided by operating activities was $4.31 billion for the first six months of 2009, compared with $2.10 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 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 $1.34 billion in first half 2009 and decreased by $161 million in first half 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 $24 million in first half 2009 and $30 million in first half 2008.

During the six months ended June 30, 2009, cash provided by operating activities of $4.31 billion was used to fund net property acquisitions, development costs and other net capital additions of $2.43 billion, dividends of $142 million and to pay down $1.58 billion of debt. The resulting decrease in cash and cash equivalents for the period was $18 million.

Total current assets decreased $1.91 billion during the first half of 2009 primarily because of a $1.42 billion decrease in derivative fair value as a result of early cash settlements of derivatives during the period and decreased accounts receivable due to lower product prices, excluding hedges. Total current liabilities decreased $517 million during the first half of 2009 primarily because of decreased accounts payable and accrued liabilities due to lower commodity prices, excluding hedges, and lower drilling activity.

Working capital decreased from a positive position of $1.33 billion at December 31, 2008 to a negative position of $66 million at June 30, 2009. Excluding the effects of derivative fair value and deferred tax current liabilities, working capital was effectively flat with a negative position of $432 million at December 31, 2008 and

a negative position of $433 million at June 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 six months of 2009 were $1.93 billion compared with $1.57 billion for the first six months of 2008. Our 2009 development and exploration budget has been increased to $3.1 billion and our budget for construction of pipeline infrastructure and compression and processing facilities has been increased to $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 first half 2009, we completed acquisitions of both producing and unproved properties for $148 million compared to $3.02 billion for first half of 2008. These acquisitions were funded by cash provided by operating activities and are subject to typical post-closing adjustments.

While we expect to focus on development activities in 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 six months of 2009, we participated in drilling approximately 508 gas wells and 35 oil wells and performed 67 workovers. Our year-to-date drilling activity was concentrated in East Texas and the Barnett Shale. Workovers have focused on recompletions, artificial lift and wellhead compression. These projects generally have met or exceeded management expectations.

Debt and Equity

On June 30, 2009, we had no borrowings under our revolving credit agreement with commercial banks, and we had available borrowing capacity of $2.34 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 June 30, 2009, borrowings were $500 million at a weighted average interest rate of 0.6%.

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

Repurchase of Senior Notes

In first quarter 2009, we repurchased $114 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, $5 million of our 6.1% senior notes due 2036, $51 million of our 6.75% senior notes due 2037 and $14 million of our 6.375% senior notes due 2038. In connection with these repurchases, we recognized a $9 million gain on extinguishment of debt in the first quarter 2009, net of unamortized discounts and the write-off of deferred debt offering costs.

In April 2009, we repurchased an additional $86 million total face amount of senior notes, including $4 million of our 6.1% senior notes due 2036 and $82 million of our 6.375% senior notes due 2038. In connection with these additional repurchases, we recognized an $8 million gain on extinguishment of debt in the second quarter 2009, net of unamortized discounts and the write-off of deferred offering costs. These gains were netted against interest expense in the consolidated income statements.

Common Stock Dividends

In May 2009, the Board of Directors declared a second quarter 2009 dividend of $0.125 per share that was paid in July to stockholders of record on June 30, 2009.

Contractual Obligations and Commitments

The following summarizes our significant obligations and commitments to make
future contractual payments as of June 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
                                                                                                 After
(in millions)                            Total     2009    2010    2011     2012       2013       2013
Long-term debt                          $ 10,400   $  -    $ 250   $  -    $   900   $  2,400   $  6,850
Operating leases                              90      16      28      22        13          7          4
Drilling contracts                           213     104      86      22         1         -          -
Purchase commitments                          36      36      -       -         -          -          -
Transportation contracts                   1,293      70     150     161       162        156        594
Derivative contract liabilities at
June 30, 2009 fair value                     245     229      15       1        -          -          -

Total                                   $ 12,277   $ 455   $ 529   $ 206   $ 1,076   $  2,563   $  7,448

Long-Term Debt. Long-term debt amounts represent scheduled maturities of our debt obligations at June 30, 2009, excluding $36 million of net discounts on our senior notes included in the carrying value of debt. At June 30, 2009, borrowings were $500 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 $500 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 long-term debt, see Note 3 to Consolidated Financial Statements.

Drilling Contracts. We have contracts with various drilling contractors to use 53 drilling rigs with terms of up to three years. Early termination of these contracts at June 30, 2009 would have required us to pay maximum penalties of $117 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 December 2006, we entered into a ten-year firm transportation contract that commences upon completion of a new 502-mile pipeline spanning from southeast Oklahoma to east Alabama. Upon the pipeline's completion in third quarter 2009, we will transport gas volumes for a minimum transportation fee of $2 million per month plus fuel not to exceed 1.2% of the sales price, depending on receipt point and other conditions.

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 these agreements is not included in the above summary of our transportation contract commitments since our commitments are contingent upon completion of the pipelines.

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 June 30, 2009, the current liability related to such contracts was $236 million and the noncurrent liability was $9 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, SFAS No. 165, Subsequent Events, was issued. SFAS No. 165 provides guidance to establish 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. SFAS No. 165 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet . . .