This discussion and analysis contains forward-looking statements. Refer to "Cautionary Information about Forward-Looking Statements" at the end of this item for an explanation of these types of statements. The prior year balances within the accompanying financial statements and notes have been adjusted to reflect the accounting required under ASC Topic 470. Please refer to Note 7 - Long-term Debt within Part I, Item 1 of this report for additional discussion.

Overview of the Company, Highlights, and Outlook

General Overview

We are an independent energy company focused on the development, exploration, exploitation, acquisition, and production of natural gas and crude oil in North America. We generate nearly all our revenues and cash flows from the sale of produced natural gas and crude oil. Our oil and gas reserves and operations are concentrated primarily in various Rocky Mountain basins, including the Williston, Big Horn, Wind River, Powder River, and Greater Green River basins; the Mid-Continent Anadarko and Arkoma basins; the Permian Basin; the productive formations of East Texas and North Louisiana; the Maverick Basin in South Texas; and the onshore Gulf Coast. We have developed a balanced and diverse portfolio of proved reserves, development drilling opportunities, and potential resource plays.

Our mission is to deliver outstanding net asset value per share growth to our investors via attractive oil and gas investments. Historically, we relied on a strategy of growing through niche acquisitions focused in the continental United States. Over the last few years, we have shifted our strategy to focus on capturing potential resource plays earlier and at a lower cost of entry. This shift was due to the fact that, as we grew, the universe of potential niche acquisition targets became smaller, more expensive, and less impactful to our growth. We believe this shift will allow for more stable and predictable production and proved reserve growth. Going forward, we will focus on continuing to acquire significant leasehold positions in existing and emerging resource plays in North America. Our strategy can be summarized as follows:

· Acquire significant leasehold positions in new and emerging North American resource plays

· Leverage our core competencies in drilling, completing, and acquiring oil and gas assets

· Exploit our significant legacy asset production and optimize our asset base through divestitures of non-core assets when appropriate

· Maintain a strong balance sheet while funding the growth of the enterprise.

Financial Standing and Liquidity

During and subsequent to the third quarter of 2008, specific issues related to the financial sector rippled through the broader economy. The failure or takeovers of several large financial institutions adversely impacted the wider equity, debt, and credit markets. Financial strength and liquidity became increasingly important as investors considered the ability of companies to fund their planned levels of activity and to service their debt obligations. In addition, fears of prolonged weakness in the global economy leading to anemic energy demand resulted in a significant decline in oil and natural gas prices. As a result of these events, we entered 2009 with a business plan designed to operate within our operating cash flow. We have maintained a disciplined approach with our capital investments during the year, which, combined with higher operating cash flows than we anticipated originally, have allowed us to maintain our strong financial position and pay down borrowings under our credit facility. We expect our 2009 exploration and development program budget will be at or near our 2009 operating cash flows. Accordingly, we do not anticipate accessing the equity or public debt markets for the remainder of 2009.

We continue to believe we have adequate liquidity available to us through our credit facility as discussed below under the caption Overview of Liquidity and Capital Resources.

Oil and Gas Prices

Our financial condition and the results of our operations are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. We sell a majority of our natural gas under contracts that use first of the month index pricing, which means that gas produced in a given month is sold at the first of the month price regardless of the spot price on the day the gas is produced. Our crude oil is sold using contracts that pay us either the average of the NYMEX West Texas Intermediate daily settlement or the average of alternative posted prices for the periods in which the crude oil is produced, adjusted for quality, transportation, and location differentials. The following table is a summary of commodity price data for the third quarters of 2009 and 2008 and the second quarter of 2009:

                                                   For the Three Months Ended
                                  September 30, 2009      June 30, 2009      September 30, 2008
Crude Oil (per Bbl):
Average NYMEX price              $              68.30    $          59.62   $             117.98
Realized price, before the
effects of hedging               $              61.93    $          53.96   $             111.97
Net realized price, including
the effects of hedging           $              62.65    $          56.72   $              83.30

Natural Gas (per Mcf):
Average NYMEX price              $               3.41    $           3.72   $              10.09
Realized price, before the
effects of hedging               $               3.37    $           3.07   $               9.96
Net realized price, including
the effects of hedging           $               4.95    $           5.19   $               9.51

Average quarterly NYMEX crude oil prices increased 15 percent from the second quarter of 2009 to the third quarter of 2009 from $59.62 per barrel to $68.30 per barrel. The 36-month forward strip price for crude oil was $76.20 per barrel at the end of the third quarter of 2009 compared with $76.46 per barrel at the end of the second quarter of 2009. On October 27, 2009, the 36-month forward strip price had increased from the end of the third quarter 2009 by 12 percent to $85.08 per barrel. At the same time, the near month price was $79.55 per barrel, which was 13 percent higher than the September 30, 2009, near month price of $70.61 per barrel.

Average quarterly NYMEX natural gas prices decreased eight percent from the second quarter of 2009 to the third quarter of 2009 from $3.72 per Mcf to $3.41 per Mcf. Natural gas prices have been under downward pressure due to concerns regarding high levels of natural gas in storage and concerns of a perpetual amount of excess supply in the market, as well as declining U.S. demand for natural gas. The 36-month forward strip price for natural gas increased four percent to $6.58 per MMBtu at the end of the third quarter of 2009 compared with $6.33 per MMBtu at the end of the second quarter of 2009, largely due to improving sentiment regarding the economic outlook in the U.S. economy. As of October 27, 2009, the 36-month forward strip price had decreased three percent to $6.40 per MMBtu. At the same time, the near month price had decreased from the September 30, 2009, near month price of $4.84 per MMBtu by an additional six percent to $4.56 per MMBtu.

While changes in quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the price we receive for oil and natural gas is affected by quality, energy content, location, and transportation differentials for these products. We refer to this price as our realized price, which excludes the effects of hedging. Our realized price is further impacted by the results of our hedging arrangements that are settled in the respective periods. We refer to this price as our net realized

price. Our net natural gas and oil price realizations for the three months ended September 30, 2009, were positively impacted by $27.2 million and $1.1 million of realized hedge gains, respectively. Net natural gas and oil price realizations for the nine months ended September 30, 2009, were positively impacted by $105.6 million and $21.6 million of realized hedge gains, respectively.

Hedging Activities

Hedging is an important part of our financial risk management program. The amount of production we hedge is driven by the amount of debt on our consolidated balance sheet and the level of capital commitments and long-term obligations we have in place. In the case of a significant acquisition of producing properties, we will consider hedging a portion of the acquired production in order to protect the economics assumed in the acquisition. With the hedges we have in place, we believe we have established a base cash flow stream for our future operations, and our use of collars for a portion of the hedges allows us to participate in upward movements in oil and gas prices. Please see Note 8 - Derivative Financial Instruments of Part I, Item 1 of this report for additional information regarding our oil and gas hedges, and see the caption, Summary of Oil and Gas Production Hedges in Place, later in this section.

We attempt to qualify our oil and gas derivative instruments as cash flow hedges for accounting purposes under ASC Topic 815. Changes in the value of our hedge positions are primarily reflected in our consolidated balance sheets. A portion of the change in the value of our hedge positions is recognized in our consolidated statements of operations due to the hedges being partially ineffective. We recognized $4.1 million in non-cash derivative loss in the third quarter of 2009. This was primarily caused by increases in the price of oil causing what had previously been hedge assets to become hedge liabilities, which in turn resulted in ineffectiveness losses from these hedge liabilities.

The U.S. Congress is currently considering recent proposals to increase the regulatory oversight of the over-the-counter derivatives markets in order to promote more transparency in those markets. Although we cannot predict the ultimate outcome of these proposals, new regulations in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and otherwise manage our financial risks related to swings in oil and gas commodity prices.

Third Quarter 2009 Highlights

Developments in emerging resource plays. During 2008, the Haynesville shale, the Eagle Ford shale, and the Marcellus shale resource plays emerged as significant new sources of gas supply for the exploration and production industry. We have exposure to each of these plays that, if successful, could provide for significant future organic growth in reserves and production. The Haynesville shale emerged early in 2008 in northern Louisiana and eastern Texas and quickly became the most active resource play in the country. Our position was built as a result of earlier leasing activity targeting the James Lime and Cotton Valley formations. Our Eagle Ford shale position in the Maverick Basin in South Texas was built from 2007 through 2009 through a combination of property acquisitions, leasing activity, and participation in a joint venture with industry partners. Late in 2008 we entered into arrangements that allow us to earn or purchase acreage in the Marcellus shale in north central Pennsylvania.

During the third quarter of 2009, we announced we would be increasing the number of wells planned for the Eagle Ford shale from four wells to ten wells on our operated high working interest acreage. Results from the completed wells to date have been positive. As of the date of this filing, we have publicly reported production information related to our first four wells across our high working interest leasehold position and these initial production rates have been encouraging to us. We are proceeding with our previously announced program and will be adding a second operated rig to drill on this high working interest acreage in the fourth quarter of 2009. Our expectation is that we will operate two rigs in this part of the play for the foreseeable future. Also during the third quarter, we drilled and completed three wells on joint venture acreage where we have two industry partners. There is a shortage of sales infrastructure in this area which we believe has limited the ability to fully evaluate these wells at this time. We continue to

work with our partners in the play and are committed to participating in the joint venture going forward. Between the joint venture and our other acreage holding, we currently have a total of approximately 225,000 net acres with potential for the Eagle Ford shale in Dimmitt, LaSalle, Maverick, and Webb counties in Texas. We continue to evaluate ways to increase our leasehold position across the play.

During the quarter, we completed our second well targeting the Haynesville shale in northern San Augustine County, Texas. The well was cored and logged, then completed vertically. We view the production rate and core data from this well positively since we think it could have favorable implications to the horizontal development in this part of the Haynesville shale trend. In addition, offsetting industry activity in this part of East Texas appears encouraging. We are drilling our second well in the area, in southern Shelby County, Texas, and we plan to complete this well vertically. We have an ongoing program to shoot, acquire, and interpret 3D seismic data over a large part of our East Texas acreage, which we expect will be completed in the first quarter of 2010. We think seismic data will be important to the successful horizontal development of this play. We continue to participate with partners in non-operated wells in northern Louisiana. We have a total of 50,000 net acres with Haynesville potential in East Texas and Louisiana.

In the Marcellus shale program in Pennsylvania, we drilled and completed our first horizontal well in McKean County, Pennsylvania during the third quarter. At quarter end, we were in the process of drilling and completing our second horizontal well, which is also in McKean County. We are moving ahead with the construction of a sales line for this portion of our acreage. We currently have over 40,000 net acres in north central Pennsylvania with potential for the Marcellus shale.

Shift toward oil-weighted projects. As a result of continued downward pressure on natural gas prices and an increase in oil prices, we began shifting capital investment dollars toward oil-weighted projects during the third quarter. We saw an increase in activity in our Permian and Rocky Mountain regions as a result of this shift in capital.

Borrowing base on credit facility maintained. On September 29, 2009, the borrowing base on our credit facility was redetermined and maintained by our bank group at a value of $900 million.

Marketing of non-core properties. In the third quarter of 2009, we began marketing a new package of certain non-core properties located primarily in the Rocky Mountain region. Please refer to Note 13 - Assets Held for Sale, in Part I, Item 1 of this report for additional information.

Production results. The table below details the regional breakdown of our third quarter 2009 production:

                   Mid-                                             Rocky
                 Continent   ArkLaTex    Gulf Coast    Permian    Mountain    Total (1)
Third Quarter
2009 Production:
Oil (MBbl)            65.4        29.4         90.5       414.3       928.1     1,527.7
Gas (MMcf)         8,483.2     3,420.5      1,495.6     1,023.8     2,787.9    17,211.0
Equivalent
(MMCFE)            8,875.7     3,596.8      2,038.4     3,509.7     8,356.8    26,377.4
Avg. Daily
Equivalents
(MMCFE/d)             96.5        39.1         22.2        38.1        90.8       286.7
Relative
percentage             34%         13%           8%         13%         32%        100%

(1) Totals may not add due to rounding

For the third quarter of 2009 our oil and gas production was in-line with our expectations and higher than our original budget estimates from the beginning of the year. Production has declined over the last three quarters as a result of lower levels of capital investment. Our ability to fund the

capital investments necessary to grow our production is influenced significantly by the price we receive for produced oil and natural gas. Market prices for natural gas and oil during the first several months of the year limited the amount of capital available to invest. We also deferred some of our capital investments due to our view that drilling and completion costs would decrease throughout the year as a result of lower levels of industry activity. Our expectation is that the deferral will provide a better economic return.

Equity Compensation. On August 1, 2009, we granted awards of performance shares and restricted stock units pursuant to our long term incentive program to various employees of the Company eligible to participate in the LTIP. The fair value associated with this grant was $31.6 million. Please refer to Note 5 - Compensation Plans within Part I, Item 1 of this report for additional discussion.

First Nine Months 2009 Highlights

Impairments. We recognized significant non-cash impairments during the first nine months of 2009. We recorded $147.0 million of proved property impairments during the first quarter of 2009, and our total impairment of proved properties for the nine months ended September 30, 2009, totaled $153.2 million. A significant decrease in the market price for natural gas, including differentials in effect at March 31, 2009, caused the majority of the non-cash impairment of proved properties in that period. The largest portion of the impairment was $97.3 million related to assets located in the Mid-Continent region which were significantly impacted by wider than normal differentials at that time. During the second quarter of 2009, we incurred a $6.0 million impairment on proved properties related to the write-down of certain assets located in the Gulf of Mexico in which we are relinquishing our ownership interests.

During the first nine months of 2009, we recognized a charge of $20.3 million for the abandonment and impairment of unproved properties. The largest component of the abandonment and impairment of unproved properties was associated with our Floyd shale leasehold in Mississippi that was recognized during the second quarter of 2009.

Lastly, we incurred inventory write-downs of $13.4 million for the nine-month period ended September 30, 2009, as a result of the decrease in the market value of tubular goods and other inventory items that were purchased in 2008 when prices for these goods were considerably higher.

Net Profits Plan. For the nine months ended September 30, 2009, the change in the value of this liability resulted in a non-cash benefit of $14.0 million compared to non-cash expense of $46.9 million for the same period in 2008. Significant decreases in oil and gas commodity prices have decreased the estimated liability for the future amounts to be paid to plan participants. This liability is a significant management estimate. Adjustments to the liability are subject to estimation and may change dramatically from period to period based on assumptions used for production rates, reserve quantities, commodity pricing, discount rates, tax rates, and production costs.

Payments made or accrued for current year distributions under the Net Profits Plan totaled $14.1 million and $45.9 million for the nine months ended September 30, 2009, and 2008, respectively. The actual cash payments we make are dependent on actual production, realized prices, and operating and capital costs associated with the properties in each individual pool. Actual cash payments will be inherently different from the estimated liability amounts. More detailed discussion is included in the Comparison of Financial Results and Trends sections below and in Note 11 - Fair Value Measurements and Note 5 - Compensation Plans in Part I, Item 1. An increasing percentage of the costs associated with the payments from the Net Profits Plan are now being categorized as general and administrative expense as compared to exploration expense. This is a function of the normal departure of employees who previously contributed to our exploration efforts. In December 2007, our Board approved an incentive compensation plan restructuring, whereby the Net Profits Plan was replaced with a long-term incentive program utilizing equity awards. As a result, the 2007 Net Profits Plan pool was the last pool established.

The calculation of the estimated liability for the Net Profits Plan is highly sensitive to our price estimates and discount rate assumptions. For example, if we changed the commodity prices in our calculation by five percent, the liability recorded on the balance sheet at September 30, 2009, would differ by approximately $13 million. A one percentage point decrease in the discount rate would result in an increase to the liability of approximately $8 million, while a one percentage point increase in the discount rate would result in a decrease to the liability of approximately $7 million. We frequently re-evaluate the assumptions used in our calculations and consider the possible impacts stemming from the current market environment including current and future oil and gas prices, discount rates, and overall market conditions.

Production results. The table below details the regional breakdown of our first nine months of 2009 production:

                   Mid-                                             Rocky
                 Continent   ArkLaTex    Gulf Coast    Permian    Mountain    Total (1)
First nine
months of 2009
Production:
Oil (MBbl)           213.3       103.0        288.2     1,419.4     2,792.0     4,815.8
Gas (MMcf)        26,247.5    11,231.0      5,156.4     3,093.7     8,326.9    54,055.5
Equivalent
(MMCFE)           27,527.5    11,848.7      6,885.4    11,610.3    25,078.7    82,950.6
Avg. Daily
Equivalents
(MMCFE/d)            100.8        43.4         25.2        42.5        91.9       303.8
Relative
percentage             34%         14%           8%         14%         30%         100 %

(1) Totals may not add due to rounding

For the first nine months of 2009 our production and oil and gas production revenues have outperformed our initial budget for 2009 due to stronger than anticipated production results from our Mid-Continent and Permian regions.

Outlook for the Remainder of 2009 and 2010

Unlike prior years, we entered 2009 without a specific capital budget for exploration and development activities. Our plan for 2009 was to make capital investments for exploration and development activities at a level at or near our operating cash flows. We established a flexible capital program that could be quickly adjusted rather than setting a fixed budget for the year. We have maintained our discipline and have kept our investing activities within operating cash flow throughout the year.

With respect to oil-weighted and liquids-weighted projects, we believe we are at the appropriate point in the commodity price cycle where increased levels of capital investment should be made. In recent months we have been increasing our activity in the oilier parts of our portfolio, specifically the Permian and Rocky Mountain regions. We currently anticipate that we will maintain or increase this level of oil-weighted activity through 2010. Generally, we do not believe that current natural gas prices support capital investment development projects at this time. We plan to continue to drill wells in certain exploratory projects that have the potential to add significant amounts of proved reserves and resource to our inventory. An example of this is our drilling in what appears to be the natural gas window in the Eagle Ford shale play. We also plan to drill some natural gas wells in order to preserve certain strategic acreage positions that would otherwise expire.

Financial Results of Operations and Additional Comparative Data

We recorded a net loss of $4.4 million or $0.07 per diluted share for the three months ended September 30, 2009, compared to third quarter 2008 results of net income of $87.0 million or $1.38 per diluted share.

The table below provides information regarding selected production and financial information for the quarter ended September 30, 2009, and the immediately preceding three quarters. Additional details of per MCFE costs are contained later in this section.