Exhibit 99.2

DECEMBER 31 BUSINESS DESCRIPTION AND UPDATES

We are an independent oil and natural gas exploration and production company historically focused on the development of the Cotton Valley group of formations, specifically the Cotton Valley Sands layer in the Schuler formation and the Upper Bossier, Middle Bossier and Haynesville/Lower Bossier layers of the Bossier formation (the “Haynesville/Bossier Shale”), in the Sabine Uplift of the Carthage, North Field of Harrison and Panola counties of East Texas (our “core area”).

During 2010, we made a strategic decision to begin looking for properties that would expand our assets and development into other basins, diversify our company’s concentrated natural gas focus from two resource plays in one basin and provide the company more liquid hydrocarbon opportunities. We sought out several key employee hires to aid in this expansion. These efforts have led to successful agreements to acquire core positions in over 67,000 net acres in the two of the leading oil resource plays in the U.S. We have recently entered into separate agreements to purchase undeveloped leasehold in the very successful and competitive region located in the Williston Basin of North Dakota/Montana, targeting the Bakken/Sanish-Three Forks Formation, and in the oil window of the Denver Julesburg Basin (the “DJ Basin”) of Wyoming, targeting the emerging Niobrara Formation. We are making plans to deploy our capital and resources into these development opportunities in 2011. With the acquisition of the liquids-rich (estimated 90% oil) Bakken and Niobrara acreage, we will have better flexibility to deploy capital based on a variety of economic and technical factors, including wells costs, service availability, take-away capacity and commodity prices (including differentials applicable to the basin). We believe this flexibility will enable us to generate better cash flow growth to fund our capital expenditure program. We believe our contracted FlexRigs inventory and experienced Rockies and Haynesville/Bossier Shale horizontal drilling personnel will enable us to succeed in the development of these new oil resource plays.

We have three subsidiaries: Diamond Blue Drilling Co. (“Diamond Blue”), which owns three conventional drilling rigs in our core area, Endeavor Pipeline Inc. (“Endeavor Pipeline”), which operates our water supply and salt water disposal systems in our core area, and Endeavor Gathering, LLC (“Endeavor Gathering”), which owns the natural gas gathering system and related equipment operated by Endeavor Pipeline. A 40% membership interest in Endeavor Gathering is owned by Kinder Morgan Endeavor LLC (“KME”).

Our principal executive office is located at 9400 North Broadway, Suite 600, Oklahoma City, Oklahoma, 73114 and our telephone number is (405) 600-0711.

History

We were incorporated in 1998 and acquired producing and undeveloped oil and natural gas properties located primarily in our core area, Kansas, and southeastern New Mexico from a bankruptcy liquidation of a small, privately-held company. We have leased additional undeveloped acreage and drilled wells in our core area since 1998. We have since sold the Kansas properties and have historically concentrated our efforts in our core area, primarily since 2003 when we entered into a joint development agreement with Penn Virginia Oil & Gas, L.P. (“PVOG”), a wholly-owned subsidiary of Penn Virginia Corporation (NYSE: PVA). Although the area of mutual interest portion of this joint development agreement has expired, we continue to own acreage in our core area jointly with PVOG. We have drilled approximately 350 vertical and three horizontal Cotton Valley Sands wells in addition to Travis Peak Sand wells, though in 2010 we did not drill any Cotton Valley Sand wells and only elected to participate for a 10% working interest in two Cotton Valley Sand horizontal wells drilled by PVOG on our joint venture acreage. In the fall of 2008, we transitioned into drilling horizontal wells into the Haynesville/Bossier Shale and as of December 31, 2010, had drilled and completed 31 Haynesville/Bossier Shale horizontal (“H/B Hz”) wells. As of December 31, 2010, we had three H/B Hz wells that were drilled and awaiting completion, and we had two FlexRig3 rigs drilling H/B Hz wells.

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Company Strengths

Large, contiguous acreage position in three high quality basins. With our acreage acquisitions in the Bakken and Niobrara, we will have a material position in two of the leading oil resource plays in the United States, along with a position in the Haynesville/Bossier Shale and Cotton Valley Sands which are located in the East Texas Basin and regarded as one of the top natural gas basins in the United States. Upon completion of these acquisitions, we will have 26,087 net acres in the Bakken, and 41,637 net acres in the Niobrara. We have 61,528 gross acres (44,032 net acres) containing our Haynesville/Bossier Shale resource development in Harrison and Panola counties Texas and Caddo parish, Louisiana. As of December 31, 2010, we have drilled and completed 31 successful horizontal Haynesville/Bossier Shale wells with production profiles that we believe provide an attractive rate of return even in a low natural gas price environment. We have an active and successful natural gas hedging strategy that has provided us above-market prices since 2009 which has improved our margins. We have identified 226 net potential undrilled locations across the property base, based on 80-acre spacing. Furthermore, we drilled 19 vertical test wells in 2006, which confirmed a consistent 350-foot layer of Haynesville/Bossier Shale to be present and substantially reduced the risk associated with our Haynesville/Bossier Shale acreage. The Cotton Valley Sands resource development contains 65,284 gross acres (46,651 net acres) and has 314 producing locations, and over 100 undrilled 80 acre horizontal locations. We have a track record of drilling success in our core area with nearly a 100% drilling success rate since the inception of our Company. A significant portion of our Haynesville/Bossier Shale and Cotton Valley Sands acreage is held by production which gives us the ability to drill where we choose without significant risk of lease expiration.

Strong historical growth profile with multi-year, lower risk crude oil and natural gas resources drilling inventory. We have an inventory of approximately 261 net potential undrilled proved and unproved Haynesville/Bossier Shale drilling locations as of December 31, 2010. In addition to these Haynesville/Bossier Shale drilling locations that are primarily natural gas, we will have 81.5 net undrilled locations (4 horizontal wells/1,280 acres; 10,000’ laterals) in the Bakken and 260.2 net undrilled locations (4 horizontal wells/640 acres; 5,000’ laterals) in the Niobrara that are crude oil targets. This large undrilled inventory of 341.7 horizontal oil resource locations and 261 horizontal gas resource locations provides us with a multi-year drilling inventory which will allow us to continue significant organic reserve and production growth. For the five-year period ending December 31, 2010, we have grown our production at a compounded annual growth rate of 51%.

Ability to allocate capital to either crude oil or natural gas and higher rate of return opportunities. With the addition of the Bakken and Niobrara acreage, which are primarily crude oil resource plays, we now have commodity and basin diversity that will allow us to allocate capital to achieve the highest risk-adjusted rate of return for our portfolio of resource development opportunities. Most of our Haynesville/Bossier Shale and Cotton Valley Sands acreage is held by production, which gives us the flexibility to chose where we drill and allocate capital. Approximately 98% of our proved reserves as of December 31, 2010 were natural gas. With the acquisition of the Bakken and Niobrara acreage, we will have better flexibility to deploy capital based on a variety of economic and technical factors, including wells costs, service availability, take-away capacity and commodity prices (including differentials applicable to the basin). We believe this flexibility will enable us to generate better cash flow growth and to fund our capital expenditure program.

High degree of horizontal drilling experience combined with operational control. We have drilled and completed 31 horizontal wells in the Haynesville/Bossier Shale using the latest technology. We routinely drill these wells with total measured depths of greater than 17,000 feet in less than 30 days. We intend to use our horizontal drilling expertise and our on-staff Rockies’ technical experience to successfully drill and operate wells in the both the Bakken and Niobrara. Once they become available, we intend to move two of our three available Helmerich & Payne FlexRig3™ rigs (“FlexRig”) to the Bakken and Niobrara and maintain a one rig program in our East Texas core area. We operate over 84% of our acreage in our East Texas core area, which permits us to better manage our operating costs and better control capital expenditures and the timing of development and exploitation activities. We believe that by being an operator in the Bakken and Niobrara acreage and by using our Haynesville/Bossier Shale horizontal drilling experience, we can achieve superior operational efficiencies.

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Significant infrastructure in place for East Texas core area. As of December 31, 2010, we had over 100 miles of gathering pipeline, 215 MMcf per day of takeaway capacity and 25,000 horsepower of compression. We also own salt-water disposal and other field infrastructure in our East Texas core area. We also have contracted four FlexRigs (one of which has been subleased to a third party for the remainder of a three-year primary term) and own three drilling rigs, six of these rigs have the capacity to drill horizontal wells in all four resource plays in which we operate. In November 2009, we contributed our gathering and compression assets to Endeavor Gathering LLC (“Endeavor Gathering”) as part of the sale of 40% of Endeavor Gathering to Kinder Morgan Endeavor LLC (“KME”), and we obtained commitments from Endeavor Gathering for priority rights to its takeaway capacity. Based on our average daily production rate of 57.1 MMcfe per day for the quarter ended December 31, 2010 and our takeaway capacity of 215 MMcf per day as of December 31, 2010, we believe our current infrastructure has sufficient capacity to support material growth in production.

Strategy

Our strategy is to expand our assets into oil resource plays in several basins that will provide the Company the ability to optimize its capital allocation and create shareholder value. Another objective is to use two of our four contracted FlexRigs to develop our two new oil resource horizontal developments in the Bakken/Sanish-Three Forks Formation of the Williston Basin in North Dakota and Montana, and the Niobrara Formation of the DJ Basin in Wyoming. We also plan to keep one contracted FlexRig drilling in our horizontal development of the Haynesville/Bossier Shale natural gas resource in East Texas. Our strategies emphasize:

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Recent Developments

Fourth Quarter and Year-End 2010 Production and Operations Update

Our production for the three months ended December 31, 2010 was 5.3 Bcfe, compared to 3.5 Bcfe in the fourth quarter of 2009, an increase of 51%. Production in the fourth quarter increased 14% when compared to the third quarter of 2010. We drilled with two FlexRigs and brought eight new H/B Hz wells to production during the fourth quarter.

Our production was 17.5 Bcfe for the twelve months ended December 31, 2010, a 30% increase from 13.5 Bcfe in 2009. Drilling in 2010 varied from two to three FlexRigs which resulted in capital expenditures in the range of $190-195 million. The increase of capital expenditures for 2010 from the original guidance was a result of fracture stimulation service availability during the fourth quarter of 2010 and the decision to complete eight H/B Hz wells during the quarter. Delays in completions due to a lack of available fracture stimulation during the third quarter of 2010 prevented us from achieving annual production closer to the higher end of our original guidance (17.5 to 19.0 Bcfe).

The eight H/B Hz wells that were brought on line in the fourth quarter had an average lateral length of 5,356 feet at an average cost of $8.9 million. The average cost per lateral foot for the completions was $1,683 and the average number of frac stages was 13. The cost per stage incurred by us peaked during the early fourth quarter but declined significantly in December 2010, and we expect our costs per stage will continue at lower levels in 2011. The Mia Austin #6H, the Company’s first 6,000 foot long lateral has a 60 day average production of 7,241 Mcf/day. The Bosh Heisman #17H was completed with 15 frac stages with a perforated lateral length of 6,164 feet and during the first 20 days of production it is performing in line with our expectations for a long lateral.

New Focus on Oil Plays and Pending Acquisitions

As discussed above, we made the strategic decision during 2010 to begin looking for oil focused properties that would diversify our concentrated natural gas focus and produce opportunities for us to expand our property development and technical experience into other basins. We have entered into five transactions to purchase undeveloped leasehold located in the Williston Basin in North Dakota/Montana, targeting the Bakken/Sanish-Three Forks Formation, as well as in the oil window of the DJ Basin in Wyoming, targeting the emerging Niobrara Formation. The Company is making plans to deploy an increasing amount of its capital and resources into these development opportunities in 2011 and 2012.

The acquisition terms consist of:

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The above referenced acquisitions are collectively referred to herein as the “Acquisitions”.

The following is a summary of our pending acquisitions acreage:

Williston Basin (Bakken / Three Forks)

Bakken/Sanish-Three Forks. Our entry into the Williston Basin involves transactions, for approximately 26,087 total net acres in eight counties. The acreage is primarily in five distinct areas, all of which are within the Bakken ‘thermal maturity window’. The leases have a minimum 80% NRI and an average 80.8% NRI and are a mix of fee (freehold), state, and federal leases, all taken within the past 12 months. The leases have five-year primary terms and many of the fee leases have options to renew for five more years. The total acreage represents the potential for 81.5 net wells using four wells per 1,280-acre spaced units.

The Upper Devonian and Lower Mississippian Bakken Formation is an unconventional reservoir that produces oil from natural fracture systems. The Bakken Formation consists of three informal but distinct members that were deposited in an intra-cratonic basin: an organic-rich upper black shale that is up to 25 ft thick, an organic-poor middle grey-brown calcareous siltstone, sandstone or dolomitic limestone that is up to 85 ft thick, and a lower organic rich black shale similar to the upper member that is up to 50 ft thick. The upper and lower shale members contain significant volumes of type II oil-prone kerogen. Total organic carbon of the upper

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and lower members averages around 12% by weight. The total system is often described in conjunction with a ‘false Bakken’ hot shale located in the overlying Lodgepole formation, and the Sanish-Three Forks (“S3”) sandstone located right below the Bakken.

The five district areas within the Bakken “thermal maturity” window for our acreage consist of:

In addition, Southern Billings County, North Dakota (approximately 1,503 net acres) offers S3 potential, with 4.7 net long lateral locations with 4 wells per 1,280 acre density that are prospective for the Sanish-Three Forks halo.

In addition to the cost of these acquisitions, we are budgeting capital expenditures in the Williston Basin to be $31.5 million in 2011 to establish a presence and begin our drilling program for the new Bakken properties (of which we expect to pay $16.6 million and $14.9 million in 2011 and 2012, respectively). Our plan is to drill 10,000’ laterals using one of our FlexRig beginning in the third quarter of 2011, and drilling continuously thereafter. Our initial acreage contains 81.5 net long lateral locations using four wells per 1,280 acre density. We plan to continue leasing and have successfully recruited experienced Bakken land staff, brokerage, and title teams to augment our current land staff capacities and competencies. We plan to join consortiums and create data sharing relationships with other operators in the basin. We have hired local consultants in the area to execute our initial plans. As we expand our development we intend to establish a GMXR field office in the area.

Niobrara- DJ Basin. Our entry into the Niobrara involves two transactions for approximately 41,637 net acres in southwestern Goshen, southeastern Platte and north central Laramie Counties in Wyoming with a minimum 80% NRI. One of the sellers has retained a 90-day option to reacquire 50% of our working interest

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(approximately 16,000 net acres) in these net acres at our initial cost. The fee leases generally have five year primary terms, and many have options to extend the lease another five years. Approximately 20% of the total net acres are new federal leases with 10 year terms. The 41,637 net acres provides GMXR with a development potential of 260 net wells using four wells per 640-acre unit.

The upper Cretaceous Niobrara Formation, an over-pressured fractured shale/chalk/limestone 300’ to 350’ thick reservoir, is the primary target for the play. Production varies from a nearly pure oil play in the north end where the Silo Field in Laramie County is less than 1 mcf/bbl to approximately 70% gas in the southern portion in the Wattenberg Field. The Silo Field was a vertical Niobrara play discovered in the early 1980’s that saw horizontal development in the early 1990’s move recoveries nearly ten-fold to around 225,000 barrels of oil per well even without the benefit of recent improvements in horizontal completion technologies. As an example, operators in the early 1990’s reported single stage stimulation treatments consisting of 30,000 barrels of water pumped with wax beads as diverting material. Some horizontal wells were simple open-hole completions.

Rebirth of this play’s potential has been framed by three wells of note. EOG Resources’ #2-1h Jake well in northern Weld County flowed an average 1,750 barrels of oil and 360 mcf per day for its first eight days from a 3,800 foot lateral in October 2009. The Jake produced more than 50,000 barrels of oil in its first 90 days. Noble Energy’s Gemini 1-99h (Wattenberg Field) produced 60,000 BOE in first 60 days with a projected 500,000 BOE EUR. SM Energy’s Atlas 1-19H well south of Silo Field produced 13,000 BOE while drilling using underbalanced drilling technique. The seven-day initial production average for the well was 1,075 boepd, and as of July 27, 2010, the well was reported making 500 BOE/day. This area represents the center of the oil window for the horizontal development, all positioned in the thermally mature area of the Niobrara in the DJ Basin. The position is bounded on the north by the North Platte River and Sybille Lineaments. The acreage is an area that is currently being developed by Chesapeake, EOG, Bill Barrett Corporation, Continental, Samson Oil & Gas and others. A significant portion of our position is within an area of a joint 3-D seismic shoot by Chesapeake and Samson. There are several new wells and active permitting by the above companies in this area.

In addition to the Niobrara, the project area contains two other targets that are known producers in the DJ. The Codell Sandstone formation (below the Niobrara) produced 30 million barrels of oil and 320 Bcf of gas in the Wattenberg Field. Also, the Sharon Springs Member of the Pierre Shale Formation (above the Niobrara) has produced in the Florence and Boulder Fields and has promise as an unconventional horizontal oil play.

In addition to the cost of these acquisitions, we are budgeting capital expenditures in the DJ Basin to be $53.6 million in 2011 to establish a presence and begin our drilling program (of which we expect to pay $29.5 million and $24.1 million in 2011 and 2012, respectively). We plan to continue leasing and have successfully recruited experienced land staff, brokerage, and title teams to augment its current competencies. Our operational plan is to deploy a third party rig in July 2011 to drill several vertical test wells down to 8,000 ’— 9,000’, to log and study the results, and when the sublease of one of our FlexRig3^™ rig expires at the end of 2011, to have this rig winterized and then deploy it to drill 8,000’ — 9,000’ vertical and 5,000’ — 10,000’ lateral wells. We plan to continue leasing, participate in and/or initiate our own 3D seismic shoot, join consortiums and create data sharing relationships with other operators. We have hired local consultants in the area to execute our initial plans. As we expand our development we intend to establish a GMXR field office in the area.

We plan to continue to operate one FlexRig rig in the H/B Hz shale play, with expectations of drilling 10 wells and completing 12 wells in 2011. We are also exploring opportunities to joint venture with a non-operating partner to continue to develop our Haynesville/Bossier Shale acreage.

East Texas

As of December 31, 2010, we owned 414 gross (264 net) producing wells. In our East Texas core area 325 gross (net) wells are Cotton Valley Sands wells at depths of 8,000 to 12,000 feet and 45 gross (37 net) wells are

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productive in the shallower conventional Rodessa, Travis Peak, Hosston and Pettit formations in our core area, and 31 gross (30 net) Haynesville/Bossier Shale horizontal wells producing, and 5 gross (2.8 net) wells in Louisiana at year-end 2010. We have historically grown by developing in our core area with a high degree of drilling success and with low finding and development costs. The Cotton Valley Sands is considered to be an unconventional natural gas resource that is pervasive throughout large areas, which explains our historical drilling success in this formation. At December 31, 2010, we had 319.3 Bcfe of proved reserves, which were 98% natural gas and 51% proved developed.

We presently are focusing a majority of our development efforts on the Haynesville/Bossier Shale areas. As of December 31, 2010, we have approximately 261 net proved and unproved Haynesville/Bossier Shale drilling locations (based on 80 acre well spacing) in Harrison and Panola Counties, Texas surrounded by our existing wells and other operators drilling Haynesville/Bossier Shale wells. We are continuing to see improving Haynesville/Bossier Shale results in East Texas, including Harrison County.

As of December 31, 2010, we had approximately 65,284 gross and 46,651 net acres in the Cotton Valley Sands formation, with approximately 290 net undrilled proved undeveloped Cotton Valley Sands drilling locations based on 20-acre well spacing.

Our core area properties accounted for more than 98% of our total proved reserves at December 31, 2010, 93% of our total net acreage and 98% of our 2010 production.

We operate 183 wells or 45% of our core area gross wells that produced 83% of our oil and natural gas production, as of December 31, 2010. Average daily net operated plus non-operated production in 2010 was 44.5 MMcf of gas and 261 Bbls of oil. The producing lives of these fields are generally between 12 to 70 years with a majority of the gas produced in the first ten years. Cotton Valley Sands gas sold from the area has a high MMBtu content, which after processing, can result in a net price above average daily Henry Hub natural gas prices. Oil is sold separately at a slight discount to the average Sweet Crude oil price at Cushing, Oklahoma (the NYMEX delivery point), inclusive of deductions. The acreage in East Texas lies on the Sabine Uplift, a broad positive feature that acts as a structural trap for most reservoirs. Most of the reservoirs are shallow and deep marine sediments that tend to have tremendous aerial extent and substantial thicknesses. Natural gas and oil have been produced from 3,000 feet to 11,700 feet in our core area. Prior to shifting our focus to the Haynesville/Bossier Shale, the primary objective of our development was the Cotton Valley Sands, which occurs between 8,200 feet and 10,000 feet and contains multiple layers of sands containing natural gas. Due to the multiple layers and widespread deposition of these gas saturated layers, we have a very high success rate of finding commercial wells.

The following table sets forth the gross and net wells completed and brought to sales in our core area in 2010:

In early 2006, we drilled and completed 19 vertical Haynesville/Bossier Shale wells across our property base. The exploratory work found a gas rich unconventional reservoir below the Cotton Valley Sands. We determined from these tests that the reservoirs had consistent open hole log characteristics across all of our acreage in Harrison and Panola counties. We did extensive open hole logging, coring and a variety of completion

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methods that determined, in our view, a viable horizontal unconventional candidate. We subsequently joined the Core Laboratories Haynesville Gas Shale Consortium (with approximately 50 other E&P companies) to share technical data with other operators about horizontal shale development. In early 2008, several E&P companies achieved great success in Haynesville/Bossier Shale horizontal exploration near our properties. We determined the Haynesville/Bossier Shale horizontal potential on our properties to be of greater value than the Cotton Valley Sands and gathered the resources necessary to begin Haynesville/Bossier Shale horizontal development. We were also the first company to join the Core Laboratories Haynesville/Bossier Shale Consortium.

In 2010, we funded cash payments related to our drilling and development activity of $192.3 million in our core area with cash on hand at December 31, 2009 from the proceeds of a $86 million offering of 4.50% convertible senior notes due 2015 in October 2009, a $104 million common stock offering in October 2009, the sale of a non-controlling, minority interest in Endeavor Gathering for $36 million in November 2009, and proceeds from borrowings on our revolving bank credit facility and cash flow from operations.

The following table sets forth our proved undeveloped locations in our core area as of December 31, 2010:

The pace of future development of this property will depend on availability of capital, future drilling and completion results, the general economic conditions of the energy industry and on the price we receive for the natural gas and crude oil produced. Additionally, in certain areas in which we own our interest jointly with PVOG, the pace of future development will depend on PVOG’s level of activity in those areas. Based on the joint development agreement, we have the ability to limit the number of rigs that PVOG operates in these areas and we have the ability to limit our participation in any PVOG well.

The number of wells we drill in 2011 will vary, and our potential capital expenditures may vary depending on the number of wells drilled, drilling and completion results and other factors. We have budgeted $123.8 million for capital expenditures in 2011 for Haynesville/Bossier Shale horizontal drilling, including $29.5 million of the completion of wells drilled in 2010, along with acreage acquisitions, new gathering systems infrastructure, other capital expenditures including capitalized interest and capitalized overhead. We plan on drilling approximately 10 horizontal wells in East Texas in 2011, all of which will be Haynesville/Bossier Shale horizontal wells. We will fund our drilling expenses primarily from cash on the balance sheet at December 31, 2010, internal cash flow, borrowings under our revolving bank credit facility, and debt and equity offerings.

Other Properties

We have approximately 2,400 gross (2,100 net) acres in the Waskom Field in Caddo parish in Louisiana with five gross (2.6 net) producing wells, three of which we operate. Total reserves and production from these areas represent less than 1% of our proved reserves and 2010 production.

Gas Gathering

We have, through our majority-owned subsidiary, Endeavor Gathering, gas gathering lines and compression equipment for gathering and delivery of natural gas from our core area that we operate. As of December 31, 2010, Endeavor Gathering had invested approximately $60 million in this gathering system, including the purchase of compressors and pipe inventory, which consisted of over 100 miles of gathering lines and 25,000 horsepower of compressors that collect and compress gas from approximately 99% of our operated gas

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production from wells in our core area. At year end 2010, this gas gathering system had takeaway capacity of 115 MMcf per day compared to our year end gross production volumes of 78.5 MMcfe per day. This system enables us to improve the control over our production and enhances our ability to obtain access to pipelines for ultimate sale of our gas. At present, Endeavor Gathering only gathers from wells in which we own an interest. Remaining gas is gathered by unrelated third parties. See “—Marketing.”

PVOG has installed and operates gathering facilities to each of the wells drilled and operated by PVOG in our jointly-owned areas. PVOG charges us a gathering fee of $0.10/MMBtu and actual cost of compression plus five percent for all gas gathered at the wellhead and redelivered to a central sales point. At year end 2010, the PVOG gathering system had takeaway capacity of 80 MMcf per day compared to production of 20.7 MMcf per day.

Diamond Blue Drilling

Our subsidiary, Diamond Blue, owns three drilling rigs that were laid down in 2009 due to the decline in natural gas prices and our long-term drilling. As of December 31, 2010, these rigs were classified as held for sale on our balance sheet and the Company’s intention is to sell the rigs in 2011.

Oil and Natural Gas Reserves

At December 31, 2010, our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firms, MHA Petroleum Consultants, Inc. (“MHA”) and DeGolyer and MacNaughton (“D&M”), were approximately 319.3 Bcfe. As of December 31, 2010, D&M estimated our proved reserves related to the Haynesville/Bossier Shale to be 234.1 Bcfe, of which 79.1 Bcfe was proved developed reserves, and MHA estimated our remaining reserves related to other areas, including the Cotton Valley Sands, to be 85.2 Bcfe. An estimated 164.4 Bcfe is expected to be produced from existing wells and another 154.9 Bcfe is classified as proved undeveloped. Substantially all of our proved reserves relate to our Haynesville/Bossier Shale and Cotton Valley Sands development based on SEC rules. All of our proved undeveloped reserves are on locations that are adjacent to wells productive in the same formations.

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which was effective for reporting 2009 reserve information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our 2009 and 2010 reserve reports as a change in accounting principle. Under the SEC’s final rule, 2008 reserves were not restated. The primary impacts of the SEC’s final rule on the fiscal years ended 2009 and 2010 included the use of the twelve-month average of the first-day-of-the-month reference prices and a five year limitation on proved undeveloped locations.

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The following table shows the estimated net quantities of our proved reserves as of the dates indicated and the Estimated Future Net Revenues and Present Values attributable to total proved reserves at December 31. All of our proved reserves are located in the United States:

Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.

In accordance with the guidelines of the SEC, our independent reserve engineer’s estimates of future net revenues from our properties, and the PV-10 and standardized measure thereof, were determined to be

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economically producible under existing economic conditions, which requires the use of the 12-month average price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the period January through December, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For 2009 and 2010, the average prices used in such estimates were $3.87 and $4.38 per MMbtu of natural gas and $61.19 and $79.43 per Bbl of crude oil, respectively. These prices do not include the impact of hedging transactions, nor do they include applicable transportation and quality differentials, nor price differentials between natural gas liquids and oil, which are deducted from or added to the index prices on a well by well basis.

The following table shows our total 2009 and 2010 proved reserves by area:

Proved Reserves—2009 SEC Pricing

Proved Reserves—2010 SEC Pricing

The amendments to Regulations S-K and S-X of the SEC also revised the guidelines for reporting proved undeveloped reserves. Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered, and they are scheduled to be drilled within five years of their initial inclusion as proved reserves, unless specific circumstances justify a longer time. In addition, proved undeveloped reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

Approximately 49% of our proved reserves are undeveloped under the new SEC rules. At the end of 2009, we, like other operators, reviewed all our existing proved undeveloped reserves in light of the SEC’s new five-year rule and decided to remove proved undeveloped reserves in the Cotton Valley Sands where we had 30% working interests in non-operated locations. At December 31, 2010, due to the drilling opportunities we have in the Haynesville/Bossier Shale and now in the oil resource plays of the Bakken and Niobrara, we do not believe we will develop our remaining Cotton Valley Sands proved undeveloped locations within the SEC’s five-year rule. None of these Cotton Valley Sands locations were actually beyond the five-year limit, but would have presented scheduling and capital priority issues under the new SEC guidelines going forward, especially in the context of our focus on the Haynesville/Bossier Shale, Bakken, and Niobrara drilling opportunities. We still believe the removed Cotton Valley Sands locations to be geologically and economically viable. If the price environment should change for the better, we would consider accelerating this development. The determination, as of December 31, 2009, to remove the 30% working interests in non-operated Cotton Valley Sands undeveloped locations resulted in the reduction of proved reserves by 53 Bcfe. The determination, as of December 31, 2010, to remove the remaining Cotton Valley Sands locations resulted in the reduction of proved reserves by 219.6 Bcfe. The remaining proved undeveloped reserves correspond to Haynesville/Bossier Shale

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horizontal drilling locations in our core area that are planned to be drilled within the next five years. The quantity and value of our proved undeveloped Haynesville/Bossier Shale reserves are dependent upon our ability to fund the associated development costs, which were estimated to be $269.8 million in the aggregate as of December 31, 2010. The estimated future development costs do not include exploration costs related to our Bakken, Niobrara and Haynesville/Bossier Shale drilling programs, which are estimated to be in the range of $175 million to $200 million per year, based on a one rig drilling program in each of the three areas. We have examined all sources of available funding, including our expected operating cash flows, availability under our revolving bank credit facility, and potential future debt and equity issuances, and we are reasonably certain that we will be able to fund the necessary development costs for our proved undeveloped reserves over the next five years.

Our estimates of proved reserves, related future net revenues and PV-10 at December 31, 2008, 2009 and estimates of our Cotton Valley Sands development reserves at December 31, 2010 were prepared by our independent petroleum consultant, MHA, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The primary person responsible for the reserve estimates prepared by MHA is Mr. John Arsenault. Mr. Arsenault is a Vice President with MHA and has approximately 25 years of direct industry engineering experience, 11 of which have been specifically related to reserves estimation. He obtained a B. Sc. in Petroleum Engineering from the Colorado School of Mines in 1985 and is a member of the Society of Petroleum Engineers.

Our estimates of proved reserves and related future net revenues and PV-10 at December 31, 2010 with respect to our Haynesville/ Bossier Shale reserves are based on reports prepared by D&M, our independent reserve engineer, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and current guidelines established by the SEC. D&M is a Delaware corporation with offices in Dallas, Houston, Calgary and Moscow. The firm’s more than 100 professionals include engineers, geologists, geophysicists, petrophysicists and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. These services have been provided for over 70 years. D&M restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any oil, gas or mineral properties, or securities or notes of clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The Senior Vice President at D&M primarily responsible for overseeing the preparation of the reserve estimates is a Registered Petroleum Engineer in the State of Texas with more than 36 years of experience in oil and gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1974 and he is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists. The firm is a Texas Registered Engineering Firm.

Technology used to establish proved reserves

Under the new SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, D&M and MHA employed technologies that have been demonstrated to yield results with consistency and repeatability. The

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technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity.

Internal controls over reserves estimation process.

Our policies and practices regarding internal control over the estimating of reserves are structured to objectively and accurately estimate our oil and natural gas reserves quantities and present values in compliance with the SEC’s regulations and U.S. Generally Accepted Accounting Principles. We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with our independent petroleum consultant and our independent reserve engineer to ensure the integrity, accuracy and timeliness of data furnished to MHA and to D&M in their reserves estimation process. Inputs to our reserves estimation process are based on historical results for production history, oil and natural gas prices, lease operating expenses, development costs, ownership interest and other required data. Our technical team meets regularly with representatives of MHA and D&M to review properties and discuss methods and assumptions used in MHA’s and D&M’s preparation of the year-end reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves the MHA and D&M reserve reports and any internally estimated significant changes to our proved reserves on a timely basis. We anticipate that our Audit Committee will conduct a similar review on an annual basis.

Our Vice President—Geosciences, Timothy Benton, was the technical person within the Company primarily responsible for overseeing the preparation of our year-end 2010 reserves estimates. Mr. Benton has over 30 years of industry experience in engineering and reservoir evaluations. He is a Registered Professional Engineer in the state of Oklahoma, a member of the Society of Petrophysics & Well Log Analysts and a member of the Society of Petroleum Engineers. Mr. Benton reports directly to our Chief Executive Officer and our President.

No estimates of our proved reserves comparable to those included in this report have been included in reports to any federal agency other than the SEC.

Costs Incurred

The following table shows certain information regarding the costs incurred by us in our acquisition, exploration, and development activities during the periods indicated.

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The exploratory drilling costs of $15.9 million, $116.2 million, and $164.2 million in 2008, 2009, and 2010, respectively, relate to our Haynesville/Bossier Shale drilling. As of December 31, 2010, we had drilled and completed 31 successful horizontal Haynesville/Bossier Shale wells, respectively, with production profiles that support our strategy of continued and focused development of this play.

Oil and Natural Gas Production, Production Prices and Production Costs

Drilling Results

We drilled or participated in the drilling of wells as set out in the table below for the periods indicated. The table was completed based upon the date drilling commenced. You should not consider the results of prior drilling activities as necessarily indicative of future performance, nor should you assume that there is necessarily any correlation between the number of productive wells drilled and the oil and natural gas reserves generated by those wells. All of the following wells were drilled in the United States.

As of December 31, 2009 and 2010, we had two Haynesville/Bossier Shale horizontal wells drilling that are not included in the table above.

Acreage

The following table shows our developed and undeveloped oil and natural gas lease and mineral acreage as of December 31, 2010.

We have approximately 226 net potential undrilled Haynesville/Bossier Shale locations in central and eastern Harrison and Panola counties in East Texas that are near acreage actively being drilled by other operators.

Title to oil and natural gas acreage is often complex. Landowners may have subdivided interests in the mineral estate. Oil and natural gas companies frequently subdivide the leasehold estate to spread drilling risk and often create overriding royalties. When we purchased the properties, the purchase included title opinions prepared by counsel analyzing mineral ownership in each well drilled. Further, for each producing well there is a division order signed by the current recipients of payments from production stipulating their assent to the fraction of the revenues they receive. We obtain similar title opinions with respect to each new well drilled. While these practices, which are common in the industry, do not assure that there will be no claims against title to the wells or the associated revenues, we believe that we are within normal and prudent industry practices. Because many of the properties in our current portfolio were purchased out of bankruptcy in 1998, we have the advantage that any known or unknown liens against the properties were cleared in the bankruptcy.

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Productive Well Summary

The following table shows our ownership in productive wells as of December 31, 2010. Gross oil and natural gas wells include wells with multiple completions. Wells with multiple completions are counted only once for purposes of the following table.

Substantially all of our productive wells are related to our Cotton Valley Sands development.

Facilities

As of December 31, 2010, we leased 32,458 square feet in Oklahoma City, Oklahoma for our corporate headquarters. The annual rental cost is approximately $487,000. We also lease approximately 2,500 square feet of office space in Marshall, Texas used primarily for land field operations. The annual rent is approximately $27,000.

We own a 50-acre operations field yard approximately seven miles southeast of Marshall, Texas that has approximately 21,500 square feet of office and warehouse space. We also own 48 acres on which our gas gathering sales point is located. In addition, we own 100 acres for expansion of our field operations near Marshall, Texas. In 2008, we opened a second field office of approximately 2,400 square feet dedicated to land operations situated on 14 acres approximately two miles from the operations field yard.

Employees

As of December 31, 2010, we had 109 full-time employees. This compares to 95 full-time employees at December 31, 2009, We also use a number of independent contractors to assist in land and field operations. We believe our relations with our employees are satisfactory. Our employees are not covered by a collective bargaining agreement.

Marketing

Our ability to market oil and natural gas often depends on factors beyond our control. The potential effects of governmental regulation and market factors, including alternative domestic and imported energy sources, available pipeline capacity, and general market conditions, are not entirely predictable.

Natural Gas. Natural gas is generally sold pursuant to individually negotiated gas purchase contracts, which vary in length from spot market sales of a single day to term agreements that may extend several years. Customers who purchase natural gas include marketing affiliates of the major oil and gas companies, pipeline companies, natural gas marketing companies, and a variety of commercial and public authorities, industrial, and institutional end-users who ultimately consume the gas. Gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market may vary daily, reflecting changing market conditions. The deliverability and price of natural gas are subject to both governmental regulation and supply and demand forces.

Substantially all of our gas from our East Texas company-operated wells is initially sold to our wholly owned subsidiary, Endeavor Pipeline, which in turn sells gas to unrelated third parties. All of our gas is currently

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sold under contracts providing for market sensitive terms that are terminable with 30-60 day notice by either party without penalty. This means that we both enjoy the benefits of high prices in increasing price markets and suffer the impact of low prices when gas prices decline. In addition, PVOG markets 100% of the gas produced from wells operated by PVOG in areas we jointly own. A subsidiary of PVOG charges us a marketing fee of 1% of the sales proceeds subject to certain price caps for oil and natural gas sold on our behalf in areas we jointly own.

Crude Oil. Oil produced from our properties is sold at the prevailing field price to one or more of a number of unaffiliated purchasers in the area. Generally, purchase contracts for the sale of oil are cancelable on 30 days’ notice. The price paid by these purchasers is an established market or “posted” price that is offered to all producers.

In June 2009 we entered into a firm sales agreement for 15,000 MMBtu per day increasing to 100,000 MMBtu per day through May 2014 at a price equal to the NGPL Tx-Ok index minus $0.02 per MMBtu. If we do not deliver physical gas, we have to pay a $0.02 per MMBtu deficiency fee on volumes not delivered. We sell a comingled package of gas owned by GMXR, other working interest owners, and royalty owners under this agreement.

On February 1, 2010 we began shipping gas from east Texas to Perryville, Louisiana on the Regency pipeline under a 10 year firm transportation agreement in which we reserved 50,000 MMBtu per day of firm capacity; we pay a demand fee of $0.30 per MMBtu per day, and pay variable shipping fees equal to $0.05 per MMBtu plus the pipeline retains 1.0% fuel on volumes of gas that flow under our firm agreement. We ship a comingled package of gas owned by GMXR, other working interest owners, and royalty owners under this agreement.

On February 1, 2010 as we began shipping gas on the Regency pipeline, we also began shipping gas on Gulf States pipeline under a 10 year firm transportation agreement in which we reserved 35,000 MMBtu per day of firm capacity; we pay a demand fee of $0.0151 per MMBtu per day, and pay variable shipping fees equal to $0.0019 per MMBtu; there is no fuel retained by the pipeline under our firm agreement. We ship a comingled package of gas owned by GMXR, other working interest owners, and royalty owners under this agreement.

In 2010, our largest purchaser of natural gas was Texla Energy Management, Inc. which accounted for over 53% of total natural gas sales. In 2009, our largest purchaser of crude oil was Sunoco, Inc. which accounted for 52% of crude oil sales. We do not believe that the loss of any of our purchasers would have a material adverse affect on our operations as there are other purchasers active in the market.

Competition

We compete with major integrated oil and natural gas companies and independent oil and natural gas companies in all areas of operation. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop these properties. Most of our competitors have substantially greater financial and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Further, our competitors may have technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have operated for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

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At various times, we have and may continue to experience occasional or prolonged shortages or unavailability of drilling rigs, drill pipe and other material used in oil and natural gas drilling. Such unavailability could result in increased costs, delays in timing of anticipated development or cause interests in undeveloped oil and natural gas leases to lapse.

Regulation

Exploration and Production. The exploration, production and sale of oil and natural gas are subject to various types of local, state and federal laws and regulations. These laws and regulations govern a wide range of matters, including the drilling and spacing of wells, allowable rates of production, restoration of surface areas, plugging and abandonment of wells and requirements for the operation of wells. Our operations are also subject to various conservation requirements. These include the regulation of the size and shape of drilling and spacing units or proration units and the density of wells that may be drilled and the unitization or pooling of oil and natural gas properties. In this regard, some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. All of these regulations may adversely affect the rate at which wells produce oil and natural gas and the number of wells we may drill. All statements in this report about the number of locations or wells reflect current laws and regulations.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental, Health and Safety Matters. We are subject to various federal, regional, state and local laws and regulations governing health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and gas drilling and production; restrict the way we handle or dispose of our materials and wastes; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim any abandoned well sites and pits. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Compliance with these laws and regulations requires expenditures of time and financial resources, and failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas. While we believe that compliance with current requirements will not have a material adverse effect on our financial condition or results of operations, there is no assurance that changes in environmental requirements for the interpretation or enforcement of them will not have a material adverse effect.

Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities or oil and natural gas wells. Discharged hydrocarbons may migrate through soil to water supplies or adjoining property, giving rise to additional liabilities. Accidental releases or spills of substances may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons.

Additionally, federal and state legislatures and government agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly compliance, waste

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handling, disposal, cleanup and remediation requirements for the oil and gas industry could have a significant impact on our operating costs. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, emissions or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes liability, often regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the present and past owner or operator of a disposal site or sites where the release occurred or sites affected by the release, and persons that dispose or arrange for disposal of hazardous substances. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and severable liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Many states have analogous programs assigning liability for the release of hazardous substances. We could be subject to the liability under CERCLA or state analogues because our drilling and production activities generate waste that may be subject to classification as hazardous substances under CERCLA.

The federal Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating and waste handling requirements, and imposes liability for failure to meet such requirements, on a person who is a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state-law counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate exempt quantities of hazardous wastes. However, at various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, could increase the volume of hazardous waste we are required to manage and dispose of and could cause us to incur increased operating expenses.

The federal Water Pollution Control Act of 1972, as amended (“Clean Water Act”), and analogous state laws, impose restrictions and strict controls regarding the discharge of pollutants into certain water bodies. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into waters of the United States or, under state law, state surface or subsurface waters. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of a permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate operating protocols including containment berms and similar structures to help prevent the contamination of regulated waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities or during construction activities.

Our operations employ hydraulic fracturing techniques to stimulate natural gas production from unconventional geological formations, which entails the injection of pressurized fracturing fluids (consisting of

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water, sand and certain chemicals) into a well bore. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the federal Safe Drinking Water Act (“SDWA”) to exclude hydraulic fracturing from the definition of “underground injection” under certain circumstances. However, the repeal of this exclusion has been advocated by certain advocacy organizations and others in the public. Legislation to amend the SDWA to repeal this exemption and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. Similar legislation could be introduced in the current session of Congress, which commenced on January 3, 2011. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing, the results of which are anticipated to be available by late 2012. Last year, a committee of the U.S. House of Representatives commenced investigations into hydraulic fracturing practices. The U.S. Department of the Interior has announced that it will consider regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents. In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production. For example, New York has imposed a de facto moratorium on the issuance of permits for certain hydraulic fracturing practices until an environmental review and potential new regulations are finalized, which will at the earliest be July 31, 2011. Significant controversy has surrounded drilling operations in Pennsylvania. Wyoming has adopted legislation requiring drilling operators conducting hydraulic fracturing activities in that state to publicly disclose the chemicals used in the fracturing process, and Colorado requires recordkeeping and disclosure of fracturing fluid constituents to officials in certain circumstances. Our operations are concentrated largely in Texas and Louisiana and we do not currently have operations on federal lands or in the states where the most stringent proposals have been advanced. However, if new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. It is also possible that our drilling and injection operations could adversely affect the environment, which could result in a requirement to perform investigations or clean-ups or in the incurrence of other unexpected material costs or liabilities.

The Oil Pollution Act of 1990, as amended (“OPA”), which amends the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect regulated waters.

The Federal Clean Air Act, as amended (“Clean Air Act”), and state air pollution permitting laws, restrict the emission of air pollutants from many sources, including processing plants and compressor stations and potentially from our drilling and production operations, and as a result affects oil and natural gas operations. We may be required to incur compliance costs or capital expenditures for existing or new facilities to remain in compliance. In addition, more stringent regulations governing emissions of air pollutants, including greenhouse gases such as methane (a component of natural gas) and carbon dioxide (“CO₂”) are being developed by the federal government, and may increase the costs of compliance for some facilities or the cost of transportation or processing of produced oil and gas which may affect our operating costs. Obtaining permits has the potential to delay the development of oil and natural gas projects. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues, we do not believe, based on current law, that such requirements will have a material adverse effect on our operations.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases from industrial and energy sources contribute to increases of carbon dioxide levels in the earth’s atmosphere and oceans and cause global warming, effects on climate, and other environmental effects and therefore present an endangerment to public health and the environment, the EPA has adopted various regulations under the federal Clean Air Act addressing emissions of greenhouse gases that may affect the oil and gas industry. On

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November 8, 2010, the EPA finalized rules expanding its Mandatory Greenhouse Gas Reporting Rule, originally promulgated in October 2009, to be applicable to the oil and natural gas industry, including certain onshore oil and natural gas production activities, which may affect certain of our existing or future operations and require the inventory and reporting of emissions. In addition, EPA has taken the position that existing Clean Air Act provisions require an assessment of greenhouse gas emissions within the permitting process for certain large new or modified stationary sources under EPA’s Prevention of Significant Deterioration (“PSD”) and Title V permit programs beginning in 2011. Facilities triggering permit requirements may be required to reduce greenhouse gas emissions consistent with “best available control technology” standards if deemed to be cost-effective. Such changes will affect state air permitting programs in states that administer the federal Clean Air Act under a delegation of authority, including states in which we have operations. In the last Congress, numerous legislative measures were introduced that would have imposed restrictions or costs on greenhouse gas emissions, including from the oil and gas industry. It is uncertain whether similar measures will be introduced in, or passed by, the new Congress which convened in January 2011. In addition, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change. In addition, certain U.S. states or regional coalitions of states have adopted measures regulating or limiting greenhouse gases from certain sources or have adopted policies seeking to reduce overall emissions of greenhouse gases. The adoption and implementation of any international treaty, of federal or state legislation or regulations, imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to comply with such requirements and possibly require the reduction or limitation of emissions of greenhouse gases associated with our operations and other sources within the industrial or energy sectors. Such legislation or regulations could adversely affect demand for the oil and natural gas we produce or the cost of transportation and processing our products. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases may produce changes in climate or weather, such as increased frequency and severity of storms, floods and other climatic events, which if any such effects were to occur, could have adverse physical effects on our exploration and production operations or associated infrastructure or disrupt markets for our products.

The federal Endangered Species Act, as amended (“ESA”), and comparable state laws, may restrict activities that affect endangered and threatened species or their habitats. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. The designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. These laws and provisions of CERCLA require reporting of spills and releases of hazardous chemicals in certain situations.

We do not believe that our environmental, health and safety risks will be materially different from those of comparable U.S. companies in the oil and natural gas industry. Nevertheless, there can be no assurance that such environmental, health and safety laws and regulations will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our capital expenditures, financial condition and results of operations.

In accordance with industry practice, we maintain insurance against some, but not all, potential operating losses including environmental liabilities, and some environmental risks generally are not fully insurable. For some operating risks, we may not obtain insurance if we believe the cost of available insurance is excessive

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relative to the risks presented. If a significant operating accident or other event occurs and is not fully covered by insurance, it could adversely affect the profitability or viability of the Company.

In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

Natural Gas Marketing and Transportation. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the Federal Energy Regulatory Commission (“FERC”). The FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting.

In addition, the FERC is continually proposing and implementing new rules affecting segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation.

The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC under Order No. 637 will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers with which we compete.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC, the Commodity Futures Trading Commission, or the CFTC and/or the Federal Trade Commission, or the FTC. Please see below the discussion of “Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

Crude Oil Marketing and Transportation. Our sales of crude oil and condensate are currently not regulated and are made at market prices. Nevertheless, Congress could reenact price controls in the future.

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Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is materially different from those of our competitors who are similarly situated.

Further, intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Other Federal Laws and Regulations Affecting Our Industry

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005, or the EPAct 2005. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior prescribed by the FERC. EPAct 2005 also provides the FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, the FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.

FTC Anti-Manipulation Rule. Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the FTC issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale from: (a) knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1 million per day per violation, in addition to any applicable penalty under the Federal Trade Commission Act.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

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Acquisition Risk Factors

Increased drilling in our current leased or owned properties or properties to be acquired pursuant to the Acquisitions may cause pipeline capacity problems that may limit our ability to sell natural gas and oil.

If the Haynesville/Bossier Shale continues to be successful, the amount of gas being produced in and around our core area from these new wells, as well as other existing wells, may exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available. If this occurs, it will be necessary for new pipelines and gathering systems to be built. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than we currently project, which would adversely affect our results of operations.

In addition, there are crude oil and natural gas pricing and take-away risks in the Bakken and Niobrara basins. In the Bakken, producers sell their crude oil to marketers who take delivery and title at the producer’s tank battery facilities, and transport the crude to markets for resale. Crude oil is trucked from the producer’s tank batteries to both pipelines and rail facilities whose available capacity can be curtailed in the winter season due to inclement weather. There is currently 500,000 Bbls of take-away capacity which is comprised of approximately 385,000 Bbls of pipeline capacity and 115,000 Bbls of rail capacity. Third parties have announced expansion projects totaling approximately 1,134,000 Bbls of new capacity projects that may become available over the next 18 months. The average difference between the WTI crude oil price and the North Dakota Crude Oil First Purchase Price for the nine months of 2010 was $8.80 per Bbl.

Natural gas produced in the Bakken has a high Btu content that requires gas processing to remove the natural gas liquids before it can be redelivered into transmission pipelines; this is done by either producers or third party processors, who currently operate a total of 15 plants. There is over 3.0 Bcf per day of natural gas take-away capacity on transmission pipelines; the capacity is currently fully subscribed, though the entire capacity is not currently being utilized. There have been announced additional capacity projects totaling over 1.0 Bcf per day that are scheduled to go in service in 2011. The natural gas prices realized by producers in the Bakken are a function of the NYMEX price, less transportation costs, plus the upgrade received from the proceeds related to the natural gas liquids that are extracted and sold separately.

In the Niobrara, producers sell their crude oil to marketers who take delivery and title at the producer’s tank battery facilities, and transport the crude to markets for resale. Crude oil is trucked from the producer’s tank batteries to pipelines whose available capacity can be curtailed in the winter season due to inclement weather. There is currently 200,000 Bbls of pipeline take-away capacity. The average difference between the WTI crude oil price and the Wyoming Crude Oil First Purchase Price for the nine months of 2010 was $10.73 per Bbl.

Natural gas produced in the Niobrara has a high Btu content that requires gas processing to remove the natural gas liquids before it can be redelivered into transmission pipelines; this is done by either producers or third party processors. There is over 6.0 Bcf per day of natural gas take-away capacity on transmission pipelines; the capacity is currently fully subscribed, though approximately 40% of the entire capacity is not currently being utilized. There have been announced additional capacity projects totaling over 2.0 Bcf per day that are scheduled to go in service in 2011. Though transmission capacity exists, extensive gas gathering infrastructure does not currently exist in the counties in which we will operate, and will need to be built by producers or pipeline companies. The natural gas prices realized by producers in the Niobrara are a function of the NYMEX price, less transportation costs, plus the upgrade received from the proceeds related to the natural gas liquids that are extracted and sold separately.

Such fluctuations and discounts could have a material adverse effect on our financial condition and results of operations.

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The closing of the Acquisitions under the applicable purchase agreements is subject to significant contingencies and closing conditions. The failure to complete some or all of the Acquisitions could adversely affect the market price of our common stock and otherwise have an adverse effect on us.

The completion of the Acquisitions pursuant to the applicable purchase agreements and related documentation is subject to a number of contingencies and the satisfaction of various closing conditions, and there can be no assurance that the Acquisitions will be completed. Most significantly, in order for us to close the Acquisitions, we will need to procure the funds necessary to pay the cash portion of the purchase price. To finance the cash payment, we will need to use our existing working capital and cash flow from operations, the borrowing base available under our amended secured credit facility and use a portion of the net proceeds from this offering. If we are unable to secure sufficient funds to pay the cash portion of the purchase price of the Acquisitions, we may be forced to terminate the Acquisitions.

If some or all of the Acquisitions are not completed, we must nonetheless pay costs related to the Acquisitions including, among others, legal, accounting and financial advisory. We also could be subject to litigation related to the failure to complete the Acquisitions or other factors, which may adversely affect our business, financial results and stock price. A failed transaction may result in negative publicity and/or negative impression of us in the investment community and may affect our relationships with creditors and other business partners. Additionally, the market price of our common stock may fall to the extent that the market price reflects an expectation that the Acquisitions will be completed.

Successful completion of the Acquisitions would result in us having exposure to producing properties and operations in the Bakken formation in Montana and North Dakota region, which makes us vulnerable to risks associated with operating in one major geographic area.

The Acquisitions consists of undeveloped lease acreage in the Niobrara formation of the DJ Basin in Wyoming and the Bakken/Sanish-Three Forks formation in Montana and North Dakota. Consequently, as a result of the Acquisitions, we will be exposed to the risks associated with operating in this geographic area, including, but not limited to, delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

The undeveloped acreage and undeveloped proved reserves to be acquired pursuant to the Acquisitions, in addition to our already large inventory of undeveloped acreage and large percentage of undeveloped proved reserves, creates additional economic risk. Such assets may not produce oil or natural gas as projected.

Our success is, and if the Acquisitions close, will be even more so, dependent upon our ability to develop significant amounts undeveloped acreage and undeveloped reserves. As of December 31, 2010, approximately 49% of our total proved reserves were undeveloped. The Acquisitions consist entirely of undeveloped acreage and do not have any undeveloped proved reserves. To the extent the drilling results on our current properties or on the properties to be acquired pursuant to the Acquisitions are not as successful as we anticipate, natural gas and oil prices decline, or sufficient funds are not available to drill these locations and reserves, we may not capture the expected or projected value of these properties. In addition, delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic, including those on the properties to be acquired pursuant to the Acquisitions.

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We may not have accurately estimated the benefits to be realized from the Acquisitions, or we may fail to identify problems associated with the assets to be acquired under the related purchase and sale agreements, either of which could cause us to incur significant losses.

The expected benefits from the Acquisitions may not be realized if our estimates of the potential production and net cash flows associated with the assets, once developed, are materially inaccurate or if we fail to identify problems or liabilities associated with the assets prior to closing. We are performing an inspection of the assets to be acquired, which we believe to be generally consistent with industry practices. However, the accuracy of our assessments of the assets and of our estimates are inherently uncertain. Our inspection will not likely reveal all existing or potential problems nor will it likely permit us to fully assess the deficiencies and potential recoverable reserves of the assets to be acquired. There could be environmental or other problems that are not necessarily observable even when the inspection is undertaken. If problems were to be identified after closing of the Acquisitions, the purchase and sale agreements relating to the Acquisitions provide for very limited, recourse against the sellers.

We have no experience drilling wells in the Bakken or Niobrara shale formations and less information regarding reserves and decline rates in the Bakken and Niobrara formations than in other areas of our operations.

We have no exploration or development experience in the Bakken or Niobrara shale formations. Other operators in the these formations and the related Williston and DJ basins have significantly more experience in the drilling of Bakken and Niobrara wells, including the drilling of horizontal wells. As a result, we have less information with respect to the ultimate recoverable reserves and the production decline rate in the Bakken and Niobrara formations than we have in other areas in which we operate.

Impairment Charges; Fourth Quarter 2010 Estimates

In connection with our December 31, 2010 financial statements, we expect to record an impairment charge of approximately $139 million, consisting of (i) an estimated $130 million ceiling test writedown of our oil and natural gas properties based on a natural gas price of $4.38 per MMBtu and a crude oil price of $79.43 per barrel and (ii) an estimated $9 million write-down in connection with the reclassification of certain assets to assets held for sale. The ceiling test writedown was a result of our decision to remove approximately 290 net proved undrilled Cotton Valley locations that had proved reserves totaling 220 Bcfe at December 31, 2009. Due to the drilling opportunities we have in the Haynesville/Bossier Shale and will have in the Bakken and Niobrara Formations, we do not believe we would develop our Cotton Valley Sands proved undeveloped locations within the required five-year timeframe under SEC requirements for including estimated proved reserves. The writedown in connection with the reclassification of assets to assets held for sale includes three conventional drilling rigs, compressors designed for low pressure gathering service, large diameter pipeline pipe, and related valves and similar equipment that were all purchased prior to 2009 in connection with our prior focus on a multi-rig long-term Cotton Valley Sand vertical drilling program. In addition to the $9 million charge, we recognized estimated selling costs of $1.2 million related to these assets.

As a result of additional completions in the fourth quarter of 2010, our production for the month of December was 2.1 Bcfe. This increase in December’s production reduced our estimated monthly per unit cost for lease operating expense and general and administrative expense (excluding $1.2 million non-recurring estimated selling costs described above). We expect our fourth quarter 2010 Adjusted EBITDA to be modestly higher than our third quarter 2010 results.

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