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 March 31
                                                                          Increase
                                             2009            2008        (Decrease)
    Total production
    Gas (Mcf)                              200,501,903     155,392,204          29%
    Natural gas liquids (Bbls)               1,647,278       1,453,601          13%
    Oil (Bbls)                               5,906,614       4,690,096          26%
    Mcfe                                   245,825,255     192,254,386          28%

    Average daily production
    Gas (Mcf)                                2,227,799       1,707,607          30%
    Natural gas liquids (Bbls)                  18,303          15,974          15%
    Oil (Bbls)                                  65,629          51,540          27%
    Mcfe                                     2,731,392       2,112,686          29%

    Average sales price
    Gas per Mcf                          $        7.24   $        7.70         (6)%
    Natural gas liquids per Bbl          $       23.84   $       52.98        (55)%
    Oil per Bbl                          $      104.59   $       80.74          30%

    Average sales price before hedging
    Gas per Mcf                          $        4.15   $        7.59        (45)%
    Natural gas liquids per Bbl          $       23.84   $       57.36        (58)%
    Oil per Bbl                          $       36.38   $       94.42        (61)%

    Average NYMEX prices
    Gas per MMBtu                        $        4.89   $        8.03        (39)%
    Oil per Bbl                          $       43.18   $       97.68        (56)%

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 increased from the first quarter of 2008 to 2009 primarily because of development activity and acquisitions, partially offset by natural decline.

Gas prices decreased from first quarter 2008 to first quarter 2009. Natural gas prices are affected by weather, the U.S. economy, the level of North American production, storage levels, crude oil prices 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 $13.00 per MMBtu in July 2008. Due to concerns of oversupply from shale gas development, declining demand due to the U.S. recession, falling oil prices and increased gas in storage, recent gas prices have dropped sharply. Natural gas prices are expected to remain volatile. The NYMEX contract price for April 2009 was $3.63 per MMBtu. At April 30, 2009, the average NYMEX futures price for the following twelve months was $4.61 per MMBtu.

Oil prices before hedging and average NYMEX oil prices decreased from first quarter 2008 to first quarter 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 U.S. recession and slowing global economy, the tightened credit markets and rising crude oil supplies caused oil prices to decline sharply in the second half of 2008. Oil prices are expected to remain volatile. The average NYMEX price for April 2009 was $50.48 per Bbl. At April 30, 2009, the average NYMEX futures price for the following twelve months was $56.55 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 March 31, 2009 Compared with Quarter Ended March 31, 2008

Net income for first quarter 2009 was $486 million compared to $465 million for first quarter 2008. First quarter 2009 earnings include a $79 million ($51 million after tax) non-cash derivative fair value loss and a $9 million ($6 million after tax) gain on extinguishment of debt. First quarter 2008 earnings include a $14 million ($9 million after tax) non-cash derivative fair value gain.

Total revenues for first quarter 2009 were $2.16 billion, a 29% increase from first quarter 2008 revenues of $1.67 billion. Operating income for the quarter was $881 million, a 7% increase from first quarter 2008 operating income of $824 million. Gas and natural gas liquids revenues increased $217 million because of the 29% increase in gas production and the 13% increase in natural gas liquids production, partially offset by the 6% decrease in gas prices and the 55% decrease in natural gas liquids prices. Oil revenue increased $239 million because of the 26% increase in production and the 30% increase in oil prices.

Expenses for first quarter 2009 totaled $1.28 billion, a 51% increase from first quarter 2008 expenses of $849 million. Increased expenses are generally related to increased production from development and acquisitions and related Company growth. Production expense increased $63 million primarily because of increased overall production and increased maintenance costs, partially offset by lower carbon dioxide injection and fuel costs. Taxes, transportation and other increased $7 million from the first quarter of 2008 primarily because of higher property taxes related to 2008 acquisitions, partially offset by lower production taxes and transportation costs due to lower product prices, excluding the effects of hedges. Depreciation, depletion and amortization increased $316 million because of increased production and higher acquisition, development and facility costs. Exploration expense increased $16 million primarily due to a $19 million increase in dry hole expense. General and administrative expense increased $8 million primarily due to higher employee expenses related to Company growth.

The derivative fair value gain for first quarter 2009 was $6 million compared to $16 million for first quarter 2008. The gain in first quarter 2009 is primarily related to the ineffective portion of hedge derivatives partially offset by the change in fair value of natural gas basis swap agreements that do not qualify for hedge accounting. See Note 5 to Consolidated Financial Statements.

Interest expense increased $35 million primarily because of a 53% increase in weighted average borrowings incurred primarily to fund acquisitions, partially offset by a $9 million gain on extinguishment of debt and a 3% decrease in the weighted average interest rate. The effective income tax rate for first quarter 2009 was 35.6%, as compared with 36.6% for first quarter 2008. 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:



                                                         Quarter Ended March 31
                                                                         Increase
                                                       2009     2008    (Decrease)
    Production                                        $ 1.04   $ 1.00            4 %
    Taxes, transportation and other                   $ 0.65   $ 0.80          (19 )%
    Depreciation, depletion and amortization (DD&A)   $ 2.84   $ 1.99           43 %
    General and administrative (G&A):
    Non-cash stock incentive compensation             $ 0.16   $ 0.21          (24 )%
    All other G&A                                     $ 0.23   $ 0.25           (8 )%
    Interest                                          $ 0.51   $ 0.47            9 %

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

Production expenses-Increased production expense is primarily because of increased maintenance costs, partially offset by lower carbon dioxide injection and fuel 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, excluding hedging, partially offset by higher property taxes primarily due to 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 is related to a decrease of $1 million in non-cash incentive award compensation and increased production. All other G&A expense decreased because of increased production outpacing personnel and other expenses related to Company growth.

Interest-Increased interest expense is primarily because of an increase in weighted average borrowings to fund recent acquisitions partially offset by increased production and a $9 million gain on extinguishment of debt.

Liquidity and Capital Resources

Cash Flow and Working Capital

Cash provided by operating activities was $3.4 billion for first quarter 2009, compared with $957 million for the same 2008 period. Increased first quarter 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. Cash provided by operating activities was increased by changes in operating assets and liabilities of $2.0 billion in first quarter 2009 and decreased by $83 million in first quarter 2008. Changes in operating assets and liabilities are primarily the result of timing of cash receipts and disbursements. Cash flow from operating activities was also reduced by exploration expense, excluding dry hole expense, of $14 million in first quarter 2009 and $17 million in first quarter 2008.

During the quarter ended March 31, 2009, cash provided by operating activities of $3.4 billion was used to fund net property acquisitions, development costs and other net capital additions of $1.4 billion, dividends of $69 million and to pay down $1.9 billion of debt. The resulting decrease in cash and cash equivalents for the period was $16 million.

Total current assets decreased $1.7 billion during the first quarter of 2009 primarily because of a $1.3 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 $148 million during the first quarter of 2009 primarily because of decreased accounts payable and accrued liabilities due to lower commodity prices, excluding hedges, and lower drilling activity, partially offset by higher deferred and current income tax payables.

Working capital decreased from a positive position of $1.3 billion at December 31, 2008 to a negative position of $211 million at March 31, 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 $489 million at March 31, 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 three months of 2009 were $1.1 billion compared with $784 million for the first three months of 2008. We have budgeted $2.75 billion for the 2009 development and exploration program and an additional $450 million for construction of pipeline infrastructure and compression and processing facilities. 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 the significant changes in oil and gas prices.

In first quarter 2009, we completed acquisitions of both producing and unproved properties for $94 million compared to $1.3 billion for first quarter 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, we plan to actively 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 three months of 2009, we participated in drilling approximately 283 gas wells and 16 oil wells and performed 37 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

On March 31, 2009, we had no borrowings under our revolving credit agreement with commercial banks, and we had available borrowing capacity of $2.71 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 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 March 31, 2009, borrowings were $135 million at a weighted average interest rate of 1.4%.

We have unsecured and uncommitted lines of credit with commercial banks totaling $300 million. As of March 31, 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, net of unamortized discounts and the write-off of deferred debt offering costs. The gain was netted against interest expense in the consolidated income statements.

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 an additional $82 million of our 6.375% senior notes due 2038. In connection with these additional repurchases, we will recognize 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.

Dividends

In February 2009, the Board of Directors declared a first quarter 2009 dividend of $0.125 per share payable April 15, 2009 to stockholders of record on March 31, 2009.

Contractual Obligations and Commitments

The following summarizes our significant obligations and commitments to make
future contractual payments as of March 31, 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                          $ 10,121   $  -    $ 250   $  -    $   900   $  2,035   $  6,936
Operating leases                              94      23      28      21        12          6          4
Drilling contracts                           266     178      67      20         1         -          -
Purchase commitments                          67      67      -       -         -          -          -
Transportation contracts                   1,328     105     150     161       162        156        594
Derivative contract liabilities at
March 31, 2009 fair value                     66      63       3      -         -          -          -

Total                                   $ 11,942   $ 436     498   $ 202   $ 1,075   $  2,197   $  7,534

Long-Term Debt. Long-term debt amounts represent scheduled maturities of our debt obligations at March 31, 2009, excluding $36 million of net discounts on our senior notes included in the carrying value of debt. At March 31, 2009, borrowings were $135 million under our commercial paper program. Because we had both the intent and ability to refinance the balance due with borrowings under our credit facility due in April 2013, the

$135 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 $9.4 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 62 drilling rigs with terms of up to three years. Early termination of these contracts at March 31, 2009 would have required us to pay maximum penalties of $149 million. Based upon our planned drilling activities, we may incur early termination penalties related to these contracts though the amounts are not expected to be significant.

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, currently expected 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 natural gas and oil 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 March 31, 2009, the current liability related to such contracts was $65 million and the noncurrent liability was $1 million. While such payments generally will be funded by higher prices received from the sale of our production, production receipts may be 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 December 2008, the Securities and Exchange Commission (SEC) released Final Rule, Modernization of Oil and Gas Reporting. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor;
(b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The effect of adopting the SEC rule has not been determined, but is not expected to have a significant effect on our reported financial position or earnings.

Forward-Looking Statements

Certain information included in this quarterly report and other materials filed or to be filed by the Company with the Securities and Exchange Commission, as well as information included in oral statements or other written statements made or to be made by the Company, contain projections and forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the Company's operations and the oil and gas industry. Such forward-looking statements may be or may concern, among other things, capital expenditures, cash flow, drilling activity, drilling locations, acquisition and development activities and funding thereof, adjusted acquisition prices, pricing differentials, production and reserve growth, reserve potential, operating costs, operating margins, production activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof, liquidity, debt repayment, regulatory matters, competition and assumptions related to the expensing of stock options and performance shares. Such forward-looking statements are based on management's current plans, expectations, assumptions, projections and estimates and are identified by words such as "expects," "intends," "plans," "projects," "predicts," "anticipates," "believes," "estimates," "goal," "should," "could," "assume," and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. In particular, the factors discussed below and detailed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2008, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements. The cautionary statements contained in our Annual Report on Form 10-K are incorporated herein by reference in addition to the following cautionary statements.

Among the factors that could cause actual results to differ materially are:

• changes in commodity prices,

• higher than expected costs and expenses, including production, drilling and well equipment costs,

• potential delays or failure to achieve expected production from existing and future exploration and development projects,

• basis risk and counterparty credit risk in executing commodity price risk management activities,

• potential liability resulting from pending or future litigation,

• changes in interest rates,

• competition in the oil and gas industry as well as competition from other sources of energy, and

• general domestic and international economic and political conditions.