Throughout this Form 10-Q, we make statements that may be deemed "forward-looking" statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. These forward-looking statements include, among others, statements concerning our outlook with regard to timing and amount of future production of oil and gas, price realizations, amounts, nature and timing of capital expenditures for exploration and development, plans for funding operations and capital expenditures, drilling of wells, operating costs and other expenses, marketing of oil and gas and other statements of expectations, beliefs, future plans and strategies, anticipated events or trends, and similar expressions concerning matters that are not historical facts. The forward-looking statements in this report are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in or implied by the statements.

These risks and uncertainties include, but are not limited to, fluctuations in the price we receive for our oil and gas production, reductions in the quantity of oil and gas sold due to decreased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated, and increased financing costs due to a significant increase in interest rates. In addition, exploration and development opportunities that we pursue may not result in productive oil and gas properties. There are also numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures. These and other risks and uncertainties affecting us are discussed in greater detail in this report and in our other filings with the Securities and Exchange Commission.

OVERVIEW

We are an independent oil and gas exploration and production company with operations entirely located in the United States. We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed.

We seek to achieve profitable growth in proved reserves and production primarily through exploration and development. We generally fund our growth with cash flow provided by our operating activities. To achieve a consistent rate of growth and mitigate risk, we maintain a blended portfolio of low, moderate, and higher risk exploration and development projects. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. Our oil and gas reserves and operations are mainly located in Texas, Oklahoma, New Mexico, Kansas, Louisiana and Wyoming.

To supplement our growth and to provide for new drilling opportunities, we also consider mergers and acquisitions. In 2005 we acquired Magnum Hunter Resources, Inc, in a stock-for-stock merger with a total transaction value of approximately $2.1 billion. Magnum Hunter was a Dallas-based independent oil and gas exploration and production company with operations concentrated in the Permian Basin of West Texas and New Mexico and in the Gulf of Mexico. During 2007 we purchased $40.9 million of assets, with the largest acquisition being in the Texas Panhandle area. In October 2008 we acquired 38,000 net acres in our western Oklahoma, Anadarko Basin Woodford shale play, at a total cost of $180.9 million. We have increased our position in the play to approximately 98,000 net acres. In first quarter 2009 we had $0.1 million of asset purchases.

From time to time we also consider selling certain assets. In 2007, we sold $177.0 million of non-core properties. The two largest sales were $87.5 million for our West Texas Spraberry oil properties and

$53.5 million for our Gulf of Mexico Main Pass area operated properties. During 2008, we sold 17 Bcfe of proved reserves for $38.1 million. During first quarter 2009 we had $3.8 million of asset sales.

Market Conditions

As of March 31, 2009 we continue to see the credit crisis and related turmoil in the global financial system that existed at December 31, 2008. These factors have led to a continued decline in natural gas prices and instability in oil prices. An extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital.

Please see the discussion of "Risk Factors" in Item 1 of our annual report on Form 10-K for the year ended December 31, 2008 for a discussion of risk factors that affect our business, financial condition and results of operations. This report should be read together with those discussions.

First quarter 2009 financial and operating results:

† First quarter oil and gas production volumes averaged 489.0 million cubic feet equivalent per day (MMcfe/d), up from 476.2 MMcfe/d for first quarter 2008.

† First quarter oil and gas sales totaled $197.2 million.

† First quarter cash flow from operating activities was $96.0 million.

† A continued decline in gas prices led to a $501.8 million after-tax, non-cash full-cost ceiling test write-down of oil and gas properties.

† First quarter drilling totaled 41 gross (24 net) wells, completing 95% as producers.

† We currently have four operated rigs running.

Oil and Gas Prices

While our revenues are a function of both production and prices, wide swings in prices have had the greatest impact on our results of operations. Our average realized gas price decreased from $8.38 per Mcf in first quarter 2008 to $3.83 per Mcf in 2009; realized oil prices decreased from $94.38 per barrel in first quarter 2008 to $35.70 per barrel in 2009. In addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we can neither control nor predict. However, we have made limited use of hedging transactions to somewhat reduce price risk as discussed further below.

                                                                   Three Months
                                                                  Ended March 31,
                                                                  2009       2008
Gas Prices:
Average Henry Hub price ($/Mcf)                                 $    4.07   $  8.03
Average realized sales price - including hedge effect ($/Mcf)   $    3.83   $  8.38
Effect of hedges ($/Mcf)                                        $       -   $  0.03
Oil Prices:
Average WTI Cushing price ($/Bbl)                               $   48.06   $ 97.90
Average realized sales price ($/Bbl)                            $   35.70   $ 94.38

On an energy equivalent basis, 69% of our 2009 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in approximately a $3.0 million

change in our gas revenues. Similarly 31% of our production was crude oil. A $1.00 per barrel change in our average realized crude oil sales price would have resulted in approximately a $2.3 million change in our oil revenues.

To mitigate a portion of our exposure to potentially adverse gas market changes we consider the use of financial derivatives. During the first quarter of 2008 we had 40,000 MMBtu per day of Mid-Continent gas production hedged through the use of collars. As of December 31, 2008 all of our cash flow effective hedge contracts had expired.

In March 2009 we entered into new derivative financial instruments covering the period of April 2009 through December 2009. The price collars set a floor and ceiling price of $3.00 and $5.00 and cover an average of approximately 148,000 MMBtu per day of our Mid-Continent gas production during the contract period. We did not choose to apply hedge accounting treatment so these contracts will not impact our realized gas prices during the year. Instead, any settlements on these contracts will be shown as a component of operating costs and expenses as a realized (gain) loss on derivative instruments. These contracts will cover approximately 38% of our overall 2009 estimated gas production and about 53% of our estimated April through December 2009 gas volumes. See Note 2 to the Consolidated Financial Statements and Item 3 of this report for additional information regarding our derivative instruments.

Production and other operating expenses

The costs associated with finding and producing oil and gas are substantial. Some of these costs vary with oil and gas prices, some trend with production volume and some are a function of the number of wells we own. At the end of 2008, we owned interests in 12,980 wells.

Production expense generally consists of the cost of power and fuel, direct labor, third-party field services, compression, water disposal, and certain maintenance activity necessary to produce oil and gas from existing wells.

Transportation expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which is net of transportation costs, and in other instances we separately pay for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and expenses, respectively.

Depreciation, depletion and amortization (DD&A) of our producing properties is computed using the units-of-production method. Because the economic life of each producing well depends upon the assumed price for future sales of production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense, while lower prices generally have the effect of decreasing reserves, which increases depletion expense. In addition, changes in estimates of reserve quantities and estimates of future development costs or reclassifications from unproved properties to proved properties will impact depletion expense.

General and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices and not directly associated with exploration, development or production activities. While we expect these costs to increase with our growth, we also expect such increases to be proportionately smaller than our production growth.

Production taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include production severance, ad valorem and excise taxes.

Significant expenses that generally do not trend with production

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted stock units to certain employees and the expensing of stock options resulting from the adoption of SFAS No. 123R, Share Based Payment. Net stock compensation expense in the first three months of 2009 was $2.3 million compared to $2.3 million in the first three months of 2008.

The derivative fair value (gain) loss is the net realized and unrealized gain or loss on derivative financial instruments to which we did not apply hedge accounting treatment and fluctuates based on changes in the fair value of underlying commodities. The net derivative fair value gain was $0.1 million in the first quarter of 2009.

RESULTS OF OPERATIONS

Quarter ended March 31, 2009 vs. March 31, 2008

We recognized a net loss for the first quarter of 2009 of $494.1 million, or $6.05 per share. This compares to net income of $149.5 million, or $1.73 per diluted share for the same period in 2008. The net loss is primarily the result of a non-cash full cost ceiling write-down recorded in the first quarter of 2009. The full cost ceiling impairment is discussed further in the operating costs and expenses section below.

                                                                Percent
                                      For the Three Months      Change
Oil and Gas Sales                       Ended March 31,         Between            Price/Volume Analysis
(In thousands or as indicated)          2009         2008      2009/2008      Price       Volume      Variance
Gas sales                           $    116,624   $ 258,955         (55 )% $ (138,616 ) $  (3,715 ) $ (142,331 )
Oil sales                                 80,605     195,450         (59 )%   (132,499 )    17,654     (114,845 )
Total oil and gas sales             $    197,229   $ 454,405                $ (271,115 ) $  13,939   $ (257,176 )

Total gas volume-MMcf                     30,465      30,910          (1 )%
Gas volume-MMcf per day                    338.5       339.7
Average gas price-per Mcf           $       3.83   $    8.38         (54 )%
Effect of hedges-per Mcf            $          -   $    0.03
Total oil volume-thousand barrels          2,258       2,071           9 %
Oil volume-barrels per day                25,086      22,757
Average oil price-per barrel        $      35.70   $   94.38         (62 )%

Oil and gas sales for the first quarter of 2009 totaled $197.2 million, compared to $454.4 million in 2008. The decrease of $257.2 million in sales between the two periods was the result of lower commodity prices which had a negative impact of $271.1 million. These lower prices were slightly offset by an increase in sales of $13.9 million due to higher production volumes during the current quarter.

Compared to the first quarter of 2008, our first quarter 2009 oil production increased by 9% to an average of 25,086 barrels per day in 2009. This increase resulted in $17.6 million of incremental revenues. Gas volumes averaged 338.5 MMcf per day in 2009 compared to 339.7 MMcf per day in the first quarter of 2008, resulting in a decrease in revenues of $3.7 million. Total first quarter 2009 oil and gas production volumes were 489.0 MMcfe per day, up 12.8 MMcfe per day from the same period in 2008.

Average realized gas prices decreased by 54% to $3.83 per Mcf for the three months ended March 31, 2009, compared to $8.38 per Mcf for the first quarter of 2008. This price decrease lowered gas sales by $138.6 million between the two periods. Included in our 2008 realized gas price is $1.0 million of cash receipts (a positive $0.03 per Mcf effect) from settlement of cash flow hedges on 40,000 MMBtu per day of Mid-Continent gas production.

Realized oil prices averaged $35.70 per barrel during the first quarter of 2009, compared to $94.38 per barrel for the same period in 2008. The decrease in oil sales resulting from this 62% decline in oil prices totaled $132.5 million.

Changes in realized gas and oil prices were the result of overall market conditions.

                                                               For the Three Months
                                                                 Ended March 31,
                                                               2009           2008
Gas Gathering, Processing, Marketing and Other (in
thousands):
Gas gathering, processing and other revenues                $    11,070    $    21,838
Gas gathering and processing costs                               (5,106 )      (10,175 )
Gas gathering, processing and other margin                  $     5,964    $    11,663

Gas marketing revenues, net of related costs                $       880    $       967

We sometimes transport, process and market third-party gas that is associated with our gas. In the first quarter of 2009, third-party gas gathering, processing and other contributed $6.0 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $11.7 million in 2008. Our gas marketing margin (revenues less purchases) decreased to $0.9 million in the first quarter of 2009 from $1.0 million in the first quarter of 2008. Decreases in net margins from gas gathering, processing, marketing and other activities are the direct result of decreased commodity prices and overall market conditions.

                                                       For the Three Months        Variance
                                                         Ended March 31,            Between
                                                        2009           2008        2009/2008
Operating costs and expenses (in thousands):
Impairment of oil and gas properties                $    791,137    $        -    $   791,137
Depreciation, depletion and amortization                  89,666       125,556        (35,890 )
Asset retirement obligation                                2,545         1,594            951
Production                                                50,414        52,052         (1,638 )
Transportation                                             8,709         8,309            400
Taxes other than income                                   15,545        30,607        (15,062 )
General and administrative                                 7,762        11,584         (3,822 )
Stock compensation                                         2,257         2,275            (18 )
Unrealized (Gain) Loss on derivative instruments            (102 )           -           (102 )
Other operating, net                                      10,092         1,036          9,056
                                                    $    978,025    $  233,013    $   745,012

Total operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $978.0 million in the first quarter of 2009 compared to $233.0 million in the first quarter of 2008.

The largest component of the increase between periods is the non-cash impairment of oil and gas properties in the amount of $791.1 million ($501.8 million, net of tax) that was recorded as a result of declines in natural gas prices during the first quarter of 2009. Due to the volatility of oil and gas prices and because the ceiling calculation requires that prices in effect as of the last day of the period be held constant in valuing proved reserves, we may be required to record a ceiling test write-down in future periods. The full cost method of accounting is discussed in detail under Note 1 to the Consolidated Financial Statements.

DD&A decreased from $125.6 million in the first quarter of 2008 to $89.7 million in the same period of 2009. On a unit of production basis, DD&A was $2.04 per Mcfe in 2009 compared to $2.90 per Mcfe for 2008. The significant decrease in DD&A is due to the $2.2 billion reduction to the carrying value of oil and gas properties recorded during the last half of 2008. With the recording of an additional impairment in the first quarter of 2009 we expect the DD&A rate to be lower in the second quarter of 2009 in comparison to the first quarter of the current year.

Production costs decreased $1.6 million from $52.0 million ($1.20 per Mcfe) in the first quarter of 2008 to $50.4 million ($1.15 per Mcfe) in the first quarter of 2009. A component of the decrease between

periods is the result of the sale of producing properties in the fourth quarter of 2008 leading to a decrease in production expense in the first quarter of 2009. The remaining change between periods is primarily attributable to a decline in lease operating expenses and insurance premiums related to our offshore properties. Overall, we have started to see a decrease in service costs in comparison to their peak in mid 2008 and expect to see this trend continue through the remainder of the year.

Taxes other than income were $15.1 million lower, decreasing from $30.6 million in 2008 to $15.5 million in 2009. The decrease between periods resulted from decreases in oil and gas sales stemming from significantly lower commodity prices.

General and administrative (G&A) expenses decreased $3.8 million from $11.6 million in the first quarter of 2008 to $7.8 million in the first quarter of 2009. The decrease between periods is due to lower employee-benefit costs due to a decrease in bonus and profit sharing expenses resulting from significant decreases in commodity prices from prior year.

A component of our operating costs and expense for the first quarter of 2009 is unrealized loss (gain) on changes in the fair value of our derivative instruments. We estimate the fair values of our natural gas derivative financial instruments by using internal discounted cash flow calculations. The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves. We did not elect hedge accounting treatment on the derivative contracts that we entered into in March 2009. As a result, we recorded an unrealized gain of $0.1 million during the first quarter. In order to receive the contract pricing terms of a $3.00 floor and $5.00 ceiling, we paid a total premium of $6.6 million (or an average of $0.16 per MMBtu) for these contacts. The derivative asset at March 31, 2009, relating to these contracts, equaled $6.7 million.

The increase in Other operating, net in the first quarter of 2009 to $10.1 million from $1.0 million in the first quarter of 2008 is related to the resolution of and accruals related to various legal matters most of which pertain to title and royalty issues.

Other income and expense

Interest expense decreased from $8.7 million in the first quarter of 2008 to $8.3 million for the same period of 2009. This change resulted from a $1.6 million decrease in interest expense on our convertible notes due to the December 2008 repurchase of $105.6 million of the outstanding $125 million (face value). This decrease was mostly offset by a $1.2 million increase in interest expense on bank debt. We had no borrowings on our credit facility during the first quarter of 2008 and an outstanding balance of $345 million at March 31, 2009.

Other, net decreased from $3.0 million of income in the first quarter of 2008 to $2.4 million of expense in the first quarter of 2009. Components consist of miscellaneous income and expense items that will vary from period to period, including income and loss in equity investees, gain or loss on sale of inventory and interest income. The decrease is primarily the result of an inventory impairment due to a decreased value of drill pipe resulting from the significant slowing of drilling activity across the industry.

Income tax expense

In the first quarter of 2009 total income tax benefit of $285.0 million was recognized, of which $15.2 million is current. This compares with first quarter 2008 current taxes of $27.9 million and total income tax expense of $83.4 million. The combined Federal and state effective income tax rates were 36.6% and 35.8% in the first quarters of 2009 and 2008, respectively. The effective tax rate of 36.6% for the first quarter of 2009 differs from the statutory rate primarily due to state income taxes and non-deductible expenses.

LIQUIDITY AND CAPITAL RESOURCES

Overview

The ongoing economic downturn, credit crisis and slowing demand have continued to negatively impact commodity prices. Sustained low oil and gas prices may reduce the amount of oil and gas that we can economically produce, and can also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. These conditions may also impact third parties with whom we do business which could lead to losses associated with uncollectible receivables.

We have and will continue to focus on maintaining liquidity, promoting operational efficiency, and expanding long-term reserves through focused drilling projects and potential acquisitions. Historically our exploration and development expenditures have generally been funded by cash flow provided by operating activities ("operating cash flow"). With our intent to continue to operate within operating cash flows, we have significantly scaled back our planned 2009 drilling program in comparison to 2008. We are focusing on our highest rate of return projects which are primarily in our Woodford shale position in the Anadarko Basin of Western Oklahoma and our south Texas Yegua and Cook Mountain play.

We continue to search for attractive acquisition opportunities; however, the timing and size of acquisitions are unpredictable. In order to ready ourselves for such an opportunity and to prepare ourselves for the potential of further declines in commodity prices, in April 2009, we entered into a new three-year senior secured revolving credit facility. The new facility increases bank commitments from $500 million to a fully-subscribed $800 million. The borrowing base remains unchanged at $1 billion. In addition to our increased credit facility, we may consider a high-yield bond offering in the future to raise additional capital, if appropriate.

We believe that our operating cash flow and other capital resources will be adequate to continue to meet our needs for our planned capital expenditures, working capital, debt servicing and dividend payments for 2009 and beyond.

Analysis of Cash Flow Changes

Cash flow provided by operating activities for the three months of 2009 was $82.6 million, compared to $315.2 million for the three months ended March 31, 2008. The decrease in first quarter 2009 resulted primarily from lower revenues resulting from lower oil and gas prices.

Cash flow used in investing activities for the three months of 2009 was $200.8 million, compared to $288.2 million for the three months ended March 31, 2008. Changes in the cash flow used in investing activities are generally the result of changes in our exploration and development programs, acquisitions and property sales. The decrease from first quarter 2008 to 2009 was mostly caused by decreased oil and gas expenditures resulting from decreased activity in our drilling and exploitation programs.

Net cash flow provided by financing activities in the first three months of 2009 was $120.0 million versus $2.8 million used in the first three months of 2008. In 2009 we had borrowings under our credit facility of $125.0 million while we had no borrowings in the first quarter of 2008.

Capital Expenditures



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