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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

Commission file no. 001-33457

Pinnacle Gas Resources, Inc.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (307) 673-9710

Securities Registered Pursuant to Section 12(b) of the Exchange Act:

Securities Registered Pursuant to Section 12(g) of the Exchange Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o  No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o  No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o  No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No x

The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was approximately $68,107,043 as of June 30, 2008 (based on a closing price of $3.60 per share and excluding 10,081,478 shares held by affiliates).

As of April 9, 2009, there were 29,188,009 shares of the registrant’s common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the registrant’s 2009 Annual Meeting of Stockholders are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2008.

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PINNACLE GAS RESOURCES, INC.

Index to Form 10-K

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We are filing this Amendment No. 1 on Form 10-K/A to clarify two statements in Items 1 and 2 Business and Properties of our Form 10-K originally filed on April 15, 2009. No revisions have been made to our financial statements or any other disclosure contained in our Form 10-K originally filed on April 15, 2009.  No other Parts or disclosure from our Annual Report on Form 10-K are included in this Amendment on Form 10-K/A other than Items 1 and 2, below, and except for such included disclosure, this Amendment on Form 10-K/A does not modify or update in any way our Annual Report on Form 10-K. All disclosure provided in this Amendment on Form 10-K/A is as of the date of the Annual Report on Form 10-K. We have not updated the disclosure in the Amendment on Form 10-K/A to reflect any recent development with respect to any disclosure contained in the Annual Report on Form 10-K.

PART I

ITEMS 1 AND 2    BUSINESS AND PROPERTIES

General

Pinnacle Gas Resources, Inc. is an independent energy company engaged in the acquisition, exploration and development of domestic onshore natural gas reserves. We primarily focus our efforts on the development of coalbed methane, or CBM, properties located in the Rocky Mountain region, and we are a substantial holder of CBM acreage in the Powder River Basin. We have assembled a large, predominantly undeveloped CBM leasehold position, which we believe positions us for significant long-term growth in production and proved reserves. In addition, we own over 94% of the rights to develop conventional and unconventional oil and natural gas in zones below our existing CBM reserves. Substantially all of our undeveloped acreage as of December 31, 2008 was located in the northern end of the Powder River Basin in northeastern Wyoming and southern Montana.

As of December 31, 2008, we owned natural gas and oil leasehold interests in approximately 477,000 gross (332,000 net) acres, approximately 90% of which were undeveloped. At December 31, 2008, we had estimated net proved reserves of 27.7 Bcf, based on a year-end Colorado Interstate Gas, or CIG, index price of $4.61 per Mcf. These net proved reserves were located on approximately 10% of our net acreage. Based on our drilling results to date, analysis of core samples and third-party results in adjacent areas, we believe that our remaining undeveloped CBM acreage has substantial commercial potential. None of our acreage or producing wells is associated with coal mining operations.

As of December 31, 2008, we owned interests in 663 gross (366 net) producing wells and operated 97% of these wells. During the year ended December 31, 2008, we drilled 117 gross (82 net) wells and produced an average of 10.6 MMcf per day net to our interest. We exited 2008 producing 10.1 MMcf per day net to our interest. During 2007, we drilled 87 gross (61 net) wells and produced an average of 9.3 MMcf per day net to our interest.

We had a total capital expenditure budget of $30.1 million for 2008 and expected to drill 146 gross (110 net) wells during the period. However, due to low CIG index prices, the economic climate and limited capital resources, we reduced our 2008 capital expenditure budget resulting in actual 2008 capital expenditures of $27.8 million. In connection with our reduced capital expenditure budget, we also reduced our drilling and completion targets for 2008. We curtailed substantially all new drilling in the fourth quarter of 2008, and we have shut-in a number of wells that are not economic at current natural gas price levels. If natural gas prices remain low, we expect to continue to operate with a reduced capital expenditure plan. Under our reduced capital expenditure plan, we would generally make such expenditures only as necessary to secure drilling permits in strategic areas, drill wells that secure leasehold positions and construct the necessary infrastructure to complete and hook-up wells that have already been drilled. Our capital expenditure budget for 2009 will be dependent upon CIG index prices, our cash flows and the availability of additional capital resources.

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Our Powder River Basin and Green River Basin CBM Projects

During the period from our formation in June 2003 to December 31, 2008, we completed 777 gross (435 net) of the 817 gross (468 net) CBM wells we drilled in the Powder River and Green River Basins. As necessary infrastructure becomes available, we expect to complete the remaining gross wells drilled through December 31, 2008.

Powder River Basin

Our Powder River Basin properties are located in Wyoming and Montana. Our acreage position in the northern end of the Powder River Basin is generally contiguous, providing us with critical mass and the ability to execute large-scale development projects in our operating areas.

· Wyoming.  Our principal Wyoming properties in the Powder River Basin are located in two distinct project areas: Recluse and Cabin Creek. As of December 31, 2008, we held approximately 120,000 gross (77,000 net) acres in the Powder River Basin in Wyoming for prospective CBM development and we operated over 98% of this acreage. As of December 31, 2008, we had 257 approved drilling permits for our Powder River Basin properties in Wyoming and we are in the process of applying for an additional 302 drilling permits which we expect to be approved in 2009 and 2010.

· Montana.  Our Montana properties are located in four project areas: Kirby, Deer Creek, Bear Creek and Bradshaw. As of December 31, 2008, we held approximately 301,000 gross (220,000 net) acres in Montana for prospective CBM development and we operated 100% of this acreage. We have continued development in the Deer Creek and Kirby areas, and in 2008, we drilled 8 gross (5 net) wells in these areas. As of December 31, 2008, we had 32 approved drilling permits for our Montana properties and we are in the process of applying for an additional 213 drilling permits which we expect to be approved in 2009 and 2010. Of these additional permits, 90 are on fee and state land and 123 are on federal land.

Green River Basin

On April 20, 2006, we acquired undeveloped natural gas properties, including related interests and assets, located in the Green River Basin of Wyoming from Kennedy Oil for an aggregate purchase price of approximately $27.0 million in cash. Our Green River Basin properties are located in the northeast area of Sweetwater County, Wyoming. As of December 31, 2008, our properties in the Green River Basin consisted of approximately 33,000 gross (32,000 net) undeveloped acres for prospective CBM development in the Fort Union Big Red Coal formation. As of December 31, 2008, we operated 100% of this acreage. As part of our initial acquisition, we also acquired 20 shut-in wells and 23 approved drilling permits and a 65% working interest in existing deep rights below the base of the Fort Union formation. As part of our initial pilot program, we have been successful in downspacing a section of our Green River Basin property from 160-acre spacing to 80-acre spacing, thus allowing us to more quickly dewater wells in this area and reach gas production. We have begun development of a water management system in the Green River Basin and are currently waiting on approval of our water management plan from the Wyoming Bureau of Land Management which we expect to receive in late 2009. It is more expensive to drill in the Green River Basin because of the increased depth of the wells, the increased cost of water management in the area and the need for additional infrastructure.

As of December 31, 2008, we had 14 approved drilling permits for our Green River Basin properties. We are in the process of applying for an additional 16 drilling permits which we expect to be approved in 2009 and 2010. In addition, we are in the process of applying for 34 drilling permits for conventional wells, which we expect to be approved through 2010.   As of December 31, 2008, we had no proved reserves established in our Green River Basin properties.

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Summary of Our Powder River and Green River Basin Properties

(1) Estimated as of December 31, 2008.

(2) Includes approximately 3,000 net acres in the Big Horn Basin, Big Horn County, Wyoming.

(3) In 2008, certain wells in the Kirby area were reassigned to the Deer Creek area. For the year ended December 31, 2008, the total wells for the two areas combined declined from 114 gross (75 net) wells to 80 gross (53 net) wells.

Our History

We were formed as a Delaware corporation in June 2003 by funds affiliated with DLJ Merchant Banking III, Inc., which we refer to collectively as DLJ Merchant Banking, and subsidiaries of Carrizo Oil & Gas, Inc., or Carrizo, and U.S. Energy Corporation, or U.S. Energy. Carrizo and U.S. Energy contributed oil and gas reserves and leasehold interests in approximately 81,000 gross (40,000 net) acres in exchange for shares of our common stock and options to purchase shares of our common stock. DLJ Merchant Banking completed several cash investments in us in exchange for shares of our common stock, Series A Redeemable Preferred Stock, and warrants to purchase additional shares of our common stock, and has been instrumental in providing capital to drive our growth. As of December 31, 2008, DLJ Merchant Banking and Carrizo owned approximately 32.9% and 8.3% of our outstanding common stock, respectively.

In April 2006, we completed a private offering of 12,835,230 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors. Immediately prior to the initial closing of our private placement, DLJ Merchant Banking exchanged all of their warrants for 6,894,380 shares of common stock in a tax-free reorganization and each of Carrizo and U.S. Energy entered into a cashless exercise of all of their options for 584,102 shares of common stock, in each case based on the private placement price of $11.00 per share. Following the initial closing of our private placement, we redeemed all of the outstanding shares of Series A Redeemable Preferred Stock held by DLJ Merchant Banking with a portion of the proceeds we received in the private placement. In addition, following the final closing of our private placement, we used a portion of the proceeds we received in the private placement to repurchase an aggregate of 1,587,598 shares of common stock from DLJ Merchant Banking at a price per share equal to the private placement price of $11.00 per share less the initial purchaser’s discount and placement fee. On September 22, 2006, DLJ Merchant Banking purchased all of the 2,459,102 shares of our common stock held by U.S. Energy and its affiliates in a private transaction.

In May 2007, we completed an initial public offering of 3,750,000 shares of our common stock at a public offering price of $9.00 per share.

In addition to the initial contribution of leasehold interests to us by U.S. Energy and Carrizo, during the period from our formation in June 2003 to December 31, 2008, we acquired leasehold interests covering approximately 396,000 gross (292,000 net) acres, primarily from three significant acquisitions.

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· In June 2003, we acquired approximately 57,000 gross (22,000 net) acres along with 210 gross (96 net) producing wells and shut-in wells in Wyoming from Gastar Exploration, Ltd. and certain of its affiliates.

· In March 2005, we acquired approximately 223,000 gross (196,000 net) undeveloped acres for prospective CBM development in Montana and Wyoming from a subsidiary of Marathon Oil Corporation.

· In April 2006, we acquired approximately 30,000 gross (29,000 net) undeveloped acres in the Green River Basin in Wyoming.

Please see the information under the heading “Our Powder River Basin and Green River Basin CBM Projects—Green River Basin” in this annual report.

Capital Expenditure Plan

We had a total capital expenditure budget of $30.1 million for 2008 and expected to drill 146 gross (110 net) wells during that period. However, due to low CIG index prices, the economic climate and limited capital resources, we reduced our 2008 capital expenditure budget resulting in actual 2008 capital expenditures of $27.8 million. In connection with our reduced capital expenditure budget, we also reduced our drilling and completion targets for 2008. During the year ended December 31, 2008, we drilled 117 gross (82) net wells. We curtailed substantially all new drilling in the fourth quarter of 2008, and we have shut-in a number of wells that are not economic at current natural gas price levels. If natural gas prices remain low, we expect to continue to operate with a reduced capital expenditure plan. Under our reduced capital expenditure plan, we would generally make such expenditures only as necessary to secure drilling permits in strategic areas, drill wells that secure leasehold positions and construct the necessary infrastructure to complete and hook-up wells that have already been drilled. The CIG index price has been extremely volatile during 2007 and 2008 and at times reached unusually low levels. For instance, the CIG monthly index price per Mcf was $1.78, $3.41, $2.78 and $4.63 for delivery in September, October, November and December of 2008, respectively. If prices remain low, our cash flows from operations will decrease and the borrowing base and borrowing availability under our credit facility could be further reduced. If we do not have sufficient cash flows and cannot obtain capital through our credit facility or otherwise, our ability to execute our development and acquisition plans, replace our reserves and maintain production levels could be greatly limited. If natural gas prices do not improve, we will consider alternatives to increase liquidity, including asset sales and issuances of equity. Our capital expenditure budget for 2009 will be dependent upon CIG index prices, our cash flows and the availability of additional capital resources. For a discussion of our credit facility and other matters that may limit our ability to execute our 2009 capital expenditure plan, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity—Credit Facility.”

We are actively marketing certain assets to raise additional capital and are also reviewing alternatives for raising additional capital through equity and debt financing, capital restructuring and possible mergers. We sold our high pressure gas gathering system in our Cabin Creek project area in Wyoming and our remaining interest in the Arvada project area in Wyoming in April 2009. Although we are pursuing various alternatives to provide additional liquidity, there is no assurance of the likelihood or timing of any of these transactions.

Overview of the CBM Industry and the Powder River Basin

CBM is natural gas that is trapped within buried coal and is stored, or adsorbed, onto the internal surfaces of the coal. Geologists have long known that coal was the source for natural gas found in many conventional accumulations, but coalbeds were not targeted for production due to high water content and minimal natural gas production. Following a West Virginia mine explosion in 1968, the U.S. Bureau of Mines began to examine ways of removing methane from coal prior to mining. The Bureau of Mines demonstrated that CBM can be produced when large volumes of water are pumped from a coal seam. In a process known as dewatering or depressuring, a submersible pump is set below the coal seam, and the water column is pumped down, reducing the pressure in the coals. As pressure within the coalbed formation is reduced, CBM is released through a process called desorption. CBM then moves into naturally occurring cracks, or cleats, in the coal, and then to the production wells. Cleats are natural fractures which have formed in the coals, usually as a result of the coalification process and geological stresses. Because the cleats are generally filled with water, the static water level above the coal must be reduced, which then lowers the reservoir pressure allowing desorption to occur. Thus, unlike producing from a conventional natural gas reservoir, reservoir pressure in a coalbed formation must generally be reduced to allow for production of

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CBM. Because of the necessity to remove water and reduce the pressure within the coal seam, CBM, unlike conventional hydrocarbons, often will not show immediately on initial production testing. Coalbed formations typically require extensive dewatering and depressuring before desorption can occur and the methane begins to flow at commercial rates.

In the past 20 years, CBM in the United States has evolved into a major component of the United States natural gas production. According to the National Energy Technology Laboratory, CBM provides approximately 8% of daily natural gas production in the United States. The Rocky Mountain region, due to its immense coal reserve base, is a significant source of United States CBM production, and there are more than 17,000 CBM wells in the Powder River Basin, according to the U.S. Department of Energy. The primary CBM basins include the San Juan, Green River, Raton, Powder River and Uinta Basins in the western United States.

Future CBM production is expected to increase substantially due to the economic viability of the resources and the tremendous reserve potential of the numerous, virtually undeveloped U.S. coal basins. Within the Rocky Mountain region, the Powder River Basin has become a major CBM producing basin. According to the U.S. Department of Energy 2002 Powder Basin Coalbed Methane Development and Produced Water Management Study, the Montana portion of the Powder River Basin is estimated to have substantial recoverable reserves. According to the Wyoming Oil and Gas Conservation Commission, approximately 1.4 Bcf of CBM has been produced from the Powder River Basin per day.

The Powder River Basin is an asymmetrical structure and sedimentary basin bounded by the Bighorn and Black Hills uplift and the Casper Arch. The Paleocene Fort Union formation crops out along the basin margin and is overlain by the Eocene Wasatch formation in the central and western part of the basin. The Wasatch and Fort Union formations contain numerous coalbeds, some of which approach 250 feet in total thickness. The Fort Union formation is divided, in ascending stratigraphic order, into the Tullock, Lebo, and Tongue River members, with the majority of coal and CBM production being produced from the Tongue River member.

The majority of Powder River Basin CBM reserves are found in the Fort Union formation. Extensive drilling in the Fort Union formation (over 25,000 drilled well bores) has provided supporting data indicating that this formation contains numerous coalbeds which are generally continuous, extremely permeable and relatively shallow (less than 1,000 feet deep) and low in rank (geologic maturity) compared to other coals in the Rocky Mountains.

Drilling and Production

CBM wells in the Powder River Basin are drilled with small truck mounted water well rigs and are drilled and completed using two basic completion techniques. The first and most common drilling technique is open hole completion. The well is drilled to the top of the target coal seam and production casing is set and cemented back to the surface. The coal seam is then drilled out and under-reamed to open up more coal face to production. The second completion technique is to drill through the base of the target coal and then set casing and cement to the surface. The well is then completed by perforating the casing at the target coal. In both completion techniques, the borehole and coal face are then cleaned out and flushed by pumping approximately 600 barrels of formation water at high rates into the coal face. Once the well is completed, a submersible pump is run into the well on production tubing to pump the water from the coal seam. After the coal is depressurized, gas flows up the casing to the wellhead. At the wellhead, the gas and water are metered. The gas then flows to a central compressor station where it is compressed into a high-pressure pipeline. The water is sent through an underground pipeline for beneficial use or disposal. CBM production must be continuous to ensure a constant low-pressure gas flow and to sustain a commercially viable operation.

We have developed specific drilling, cementing and completion technology that we have adapted to the rank, depth and thickness of the coals found in all of our operating areas. Our drilling, completion and production practices utilize technological advances in cementing, multiple zone completions and programmable submersible pumps. We have developed drilling and cementing techniques that minimize the damage to coal zones, preserve the potential of coals behind pipe and reduce cementing costs. Multiple zone completions allow for the successful perforation of multiple zones which reduces costs and gives us the ability to sustain production from coals less than

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ten feet in thickness. Programmable submersible pumps and telemetry allow us to implement aggressive production management programs on our wells and projects.

Conventional gas wells are typically 8,000 to 20,000 feet deep and initially produce large volumes of gas relative to water. Natural gas normally does not require assistance to move to the surface, and over time, gas production declines and water production may increase. In contrast, CBM wells generally range from 300 to 4,000 feet. In the early stages of CBM production, large quantities of water and low quantities of gas are produced. Water production is initiated to lower the downhole pressure which allows the methane to release from the coal. The water volumes eventually decline and gas quantities begin to rise. In most cases, assistance to bring the gas to surface is not needed for the final period of production.

Water Production and Management

Water production and disposal is a key issue in CBM development. CBM-produced water in Wyoming and Montana must have a beneficial use, which is generally defined as using the water for agricultural, irrigation, commercial, domestic, industrial, municipal, mining, hydropower production, recreational, stockwatering and fisheries, wildlife and wetlands maintenance purposes or dust suppression. Currently, the management of CBM-produced water depends on the quality of the produced water. The water produced in CBM operations can vary from very high quality (meeting state and federal drinking standards) to very low quality (having a very high concentration of dissolved solids, making it unsuitable for reuse). Testing of the produced water determines the disposal method.

Produced water is handled by utilizing one or several of the following approved methods:

· surface discharge;

· containment in reservoirs;

· irrigation of surface lands;

· injection to shallow sand formations;

· enhanced evaporation systems;

· treatment through ion exchange or reverse osmosis; and/or

· sub-surface irrigation.

We include water gathering and water disposal costs in our hook-up, infrastructure and water management cost estimate of between $62,000 and $109,000 per well depending on the location and the number of wells drilled on an 80-acre spacing unit.

We have a water treatment agreement with EMIT Water Discharge Technology, LLC for our Cabin Creek project. Pursuant to the agreement, EMIT installed and operates treatment facilities necessary to treat a maximum daily quantity of water in exchange for a fixed daily fee and a variable fee per barrel of treated water that varies with the sodium content of the water. The rate is subject to adjustment annually for inflation. The agreement has an initial term of three years from July 2007, the first date upon which EMIT was ready and able to treat water, and continues on a month-to-month basis thereafter unless terminated by either party upon 90 days’ written notice. Prior to the end of the initial term, we may extend the term by another three years upon payment of a renewal fee.

Recovery Characteristics

The primary variables that affect recovery of CBM are coal thickness, gas content and permeability. Coal thickness refers to the actual thickness of the coal layer and is used to estimate how many tons of coal underlie a section of land. The estimate of the number of tons per section is multiplied by the estimated gas content of such lands to estimate the gas in place for the section. Gas content in coal is measured in terms of standard cubic feet per ton. Sufficient coal permeability is a prerequisite for economic gas flow rates because gas and water must be able to flow to the wellbore. Most gas and water flow through the cleats and other fractures in the coal. Cleat spacing is influenced by a variety of factors and greatly affects permeability.

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Powder River Basin CBM Production Overview

The Powder River Basin is located in northeastern Wyoming and southern Montana. The Powder River Basin is rich in natural resources with significant reserves of oil and gas as well as some of the world’s thickest coal seams. The Powder River Basin holds the distinction of being the leading coal-producing area in the United States, and in recent years, has become one of the most active areas for oil and gas drilling.

We target an average of three coal seams per drilling location and have up to five coal seams that we believe are capable of commercial production. We expect that many of our wells will be completed to more than one coal seam, and thus we may drill less than three wells per location. The coal seams that we target are part of the Fort Union formation and include the Canyon, Cook, Wall, Pawnee and Flowers-Goodale (the Roberts equivalent) coals, which are found at depths ranging from 200 to 1,500 feet and are each approximately 15 to 60 feet thick.

Our wells generally reach total depth in one day and cost between $95,000 and $122,000 per well to drill and complete, depending on location, coal zones perforated and depth. Hook-up, infrastructure and water management costs are between $62,000 and $71,000 per well in the Powder River Basin. Powder River CBM wells are drilled with small truck mounted water well rigs and are completed as either single or multiple zone producers. In a single coal completion, we top set the casing in the first foot of coal and complete the well by under-reaming the coal with a 12-inch diameter tool. In a multiple zone completion, we typically top set and under-ream the deepest coal seam and perforate the upper coal seams sequentially. Our general production profile for a CBM well shows production of water for 30 to 90 days prior to initial gas production. The lowering of the static water level reduces the coal formation pressure and allows the gas to desorb from the coal and migrate to the well bore. Gas production typically inclines steeply for an average of nine months, peaking at an average of over 100 Mcf per day. A period of relatively flat production at peak continues for three to four months and then declines at an annual rate of approximately 35% over a five to seven year period. Produced water is handled by discharging it through one or more of several approved methods.

Our CBM wells in the Powder River Basin have all been drilled and cemented in anticipation of completing more than one coal seam per well bore. In our project areas, depending on the thickness of and horizontal separation between coal seams, we generally complete several coals in one well upon initial hook-up. Coal seams thicker than 25 feet are initially drilled as stand alone wells. Coal seams with less than 100 feet of vertical separation are completed simultaneously at initial hook-up. Our development activities include an active program to sequentially complete upper coal seams in wells that are producing from a single coal seam since being initially drilled and completed. We presently have over 150 wells that have been identified in the Recluse area for further completions in upper coals. Our completion strategy generally is to wait for the lower coal zones’ measured pressure to reach or equal the measured pressure of the upper zones. Once the measured pressures are determined to be equal, the upper zones are perforated and completed. Sequential completion of upper coal seams typically costs $12,000 per coal seam. We expect that multiple zone completions can increase the economic life of a well, increase previously unbooked behind pipe reserves from several thinner coal seams and enhance our rate of return.

Green River Basin CBM Production Overview

The Green River Basin is primarily located in southwestern Wyoming, and our assets are located in the eastern half of the Wyoming portion of the Green River Basin. According to the U.S. Department of Energy 2004 Coal Bed Methane Primer, the Green River Basin has significant potential CBM reserves in place. The Green River Basin is an increasingly active basin for natural gas and CBM exploration and drilling. An Environmental Impact Statement, or EIS, is currently being prepared by the Wyoming Bureau of Land Management for the drilling and development of up to approximately 9,000 natural gas wells, including up to 500 CBM wells, on a 1.1 million acre project area. Our Green River Basin acreage position is offset by multiple fields producing from conventional reservoirs in the Lance, Lewis and Almond sandstones. In 2008, there were approximately 31 CBM projects in the eastern half of the Green River Basin with a total of 176 CBM wells drilled. These projects are being developed by approximately 13 operators targeting coals in the Mesaverde, Fort Union and Wasatch formations.

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The Fort Union Big Red Coal, which we are targeting, is found at depths between 2,500 to 6,500 feet. The Fort Union coals, including the Big Red Coal, aggregate approximately 100 feet in thickness. The Big Red Coal accounts for up to 50 feet of the thickness. The Fort Union coals on our acreage have excellent permeability and gas saturation of generally 200 to 400 scf per ton of coal. In addition to the Big Red Coal, CBM potential exists in other coals of the Fort Union formation and in coals in the Wasatch and Mesaverde formations.

We anticipate developing the Green River Basin CBM reserves primarily on 160-acre spacing. The 14 gross (14 net) wells drilled as of December 31, 2008 on the acreage have generally reached total depth in five days. We estimate that future wells will cost an average of $787,000 to drill, complete and hook up. We intend to complete the wells by under-reaming the coal or drilling through the coal and perforating the coal formation. Our estimated production profile assumes little gas production for three to five months as the well is dewatered and the formation pressure lowered, a steep incline in production for the following 12 months, peak production for 18 to 24 months and then a slow decline in production of approximately 10% per year over a 20 to 25 year period. We estimate the standard reserve life of a well in the Green River Basin will be approximately 25 years.

Operations

CBM Development, Projects and Operations

Our properties in the Powder River Basin are primarily located in northeastern Wyoming and southern Montana and are generally contiguous, providing us with critical mass and the ability to execute large scale development projects in our operating areas. As of December 31, 2008, we owned leasehold interests in approximately 421,000 gross (297,000 net) acres in the Powder River Basin, approximately 99% of which we operated. As of December 31, 2008, we also owned leasehold interests in 33,000 gross (32,000 net) acres in the Green River Basin in Wyoming.

Most of our development drilling is in areas of known natural gas reserves and involves much lower risk than the exploratory type of drilling that is required when searching for new natural gas reserves. During the period from our formation in June 2003 to December 31, 2008, we completed 777 gross (435 net) of the 817 gross (468 net) CBM wells we drilled in the Powder River and Green River Basins. As necessary infrastructure becomes available, we expect to complete the remaining gross wells drilled through December 31, 2008. During the year ended December 31, 2008, we drilled 117 gross (82 net) wells and connected 110 gross (77 net) wells to our low-pressure gathering system. During the year ended December 31, 2007, we drilled 87 gross (61 net) wells and connected 108 gross (73 net) wells to our low-pressure gathering system. At December 31, 2008, we were producing natural gas from approximately 663 gross (366 net) CBM wells at a net rate of 10.6 MMcf per day measured at the wellhead. In response to lower CIG index prices, the state of the economy in general and limited capital resources, we reduced our 2008 capital expenditure budget from $30.1 million to $27.8 million. We also reduced our drilling and completion targets for 2008 from approximately 146 gross (110 net) to approximately 117 gross (82 net) wells. Our revised 2008 capital expenditure budget was used to drill and complete wells in 2008, to construct gas and water infrastructure, to fund plans of development costs for future wells, to fund undeveloped leasehold acquisition costs carried over from 2007, to recomplete certain wells, and to fund infrastructure and completion costs related to such wells drilled in 2007. If natural gas prices remain low, we expect to continue to operate with a reduced capital expenditure plan that allows us to secure drilling permits in strategic areas, drill wells that secure leasehold positions and construct the necessary infrastructure to complete and hook-up wells that have already been drilled. Our capital expenditure budget for 2009 will be dependent upon CIG index prices, our cash flow and the availability of additional capital resources.

Our drilling locations target the Canyon, Cook, Wall, Pawnee and Flowers-Goodale (the Roberts equivalent) coal seams in the Powder River Basin, which are found at depths ranging from 200 to 1,500 feet, and the Fort Union Big Red Coal in the Green River Basin, which is found at depths ranging from 2,500 to 6,500 feet. Each coal seam is approximately 15 to 60 feet thick. As of December 31, 2008 and based on a year-end CIG index price of $4.61 per Mcf, Netherland, Sewell & Associates, Inc., or NSAI, had identified 881 proved drilling locations assuming one coal seam per well. We expect that many of our wells will be completed to more than one coal seam.

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Wyoming—Powder River Basin

Our principal Wyoming properties in the Powder River Basin are located in two distinct project areas: Recluse and Cabin Creek. As of December 31, 2008, we held approximately 120,000 gross (77,000 net) acres in the Powder River Basin in Wyoming for prospective CBM development and we operated over 98% of this acreage.

Approximately 54% of our gross acreage in the Powder River Basin in Wyoming is on U.S. federal land, and is subject to additional regulations not applicable to state or fee leases. Permitting new wells in Wyoming on federal land involves submitting a plan of development, or POD, to the Wyoming division of the United States Bureau of Land Management, or Wyoming BLM, and is subject to an environmental assessment and a review period. Typically, it takes three to six months to complete the permitting process and receive approval from the Wyoming BLM. Permitting new wells on state and fee land requires approval from the Wyoming Oil and Gas Conservation Commission and the approval process typically takes 30 to 60 days. Please see the information under the heading “Regulations—Permitting Issues for Federal Lands” in this section of this annual report for further information.

As of December 31, 2008, we had 257 approved drilling permits for our Wyoming properties in the Powder River Basin and we are in the process of applying for an additional 302 drilling permits which we expect to be approved in 2009 and 2010.

· Recluse—Recluse is located on the northern end of the Gillette Fairway, where a majority of Powder River Basin CBM has been produced to date. As of December 31, 2008, we held approximately 34,000 gross (16,000 net) acres in the Recluse area, of which approximately 34% were developed. As of December 31, 2008, we operated approximately 99% of these properties. As of December 31, 2008, we were producing approximately 11.8 gross (4.5 net) MMcf per day from approximately 427 gross (209 net) wells in this area. During the year ended December 31, 2008, we drilled 9 gross (3 net) wells. Our gas is gathered in over 200 miles of low-pressure gathering systems which we installed and own. As of December 31, 2008, we had approximately 7.2 Bcf of net proved reserves in the Recluse area based on a CIG index price of $4.61 per Mcf.   We are currently evaluating drilling plans for 2009 in light of the current economic and gas pricing environment.

· Cabin Creek—Our Cabin Creek project is located on the northern border of Wyoming adjacent to St. Mary’s Hanging Woman project to the west. As of December 31, 2008, we held approximately 55,000 gross (37,000 net) acres in Cabin Creek, of which approximately 25% were developed. As of December 31, 2008, we operated approximately 81% of these properties. We have a non-operating working interest in 32 wells operated by St. Mary Land and Exploration Company which are covered by a joint operating agreement. As of December 31, 2008, we participated in wells that were producing approximately 8.2 gross (3.6 net) MMcf per day from approximately 156 gross (104 net) wells in this area. During the year ended December 31, 2008, we drilled 97 gross (71 net) wells. As of December 31, 2008, we had approximately 12.4 Bcf of net proved reserves in the Cabin Creek area based on a CIG index price of $4.61 per Mcf. We are currently evaluating drilling plans for 2009 in light of the current economic and gas pricing environment.

· Other—As of December 31, 2008, we held approximately 31,000 gross (24,000 net) acres in three non-core project areas in Wyoming, all of which are undeveloped. As of December 31, 2008, we operated approximately 80 gross (58 net) wells in these areas and had approximately 0.3 Bcf of net proved reserves based on a CIG index price of $4.61 per Mcf.

Montana—Powder River Basin

Our Powder River Basin properties in Montana are located in four project areas: Kirby, Deer Creek, Bear Creek and Bradshaw. As of December 31, 2008, we held approximately 301,000 gross (220,000 net) acres in Montana for prospective CBM development and we operated 100% of this acreage. In 2008, our primary focus was the construction of water management infrastructure in the Kirby and Deer Creek areas. In addition, we drilled 8 gross (5 net) wells in these areas.

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Because CBM development in Montana is still in its early stages, the permitting process is not as streamlined in Montana as it is in Wyoming. Permitting new wells in Montana on federal land involves submitting a plan of development, or POD, which typically covers approximately 30 to 100 80-acre locations, to the Montana division of the United States Bureau of Land Management, or Montana BLM, and is subject to an environmental evaluation under the National Environmental Policy Act and a review period. Permitting new wells on state and fee land involves submitting a POD, which typically covers 200 to 300 wells, to the Montana Oil and Gas Conservation Commission, and is also subject to an environmental evaluation under the National Environmental Policy Act and a review period. An injunction which prohibited the Montana BLM from approving any CBM drilling permits in certain federal lands in the Montana portion of the Powder River Basin was lifted in December 2008. The primary lease term of federal acreage covered by the injunction was suspended during the time period that the injunction was in effect. We estimate the suspension will add an additional three to five years to the primary term of all affected federal leases. Fee and state permits were unaffected by the injunction. Approximately 67% of our gross acreage in Montana is on U.S. federal land. Prior to the issuance of the injunction, the permit approval process for federal lands typically took about a year. The permit approval process for fee and state lands typically takes three to six months. See “—Regulations—Permitting Issues for Federal Lands” for further discussion of the Montana federal permitting process and injunction.

As of December 31, 2008, we had 32 approved drilling permits for our Montana properties. We are in the process of applying for an additional 213 drilling permits, 123 of which are on federal lands and 90 of which are on state or fee lands. We expect these permits to be approved in 2009 and 2010. We are currently evaluating drilling plans for 2009 in light of the current economic and gas pricing environment.

· Kirby—Kirby was acquired at the time of our initial formation in 2003. As of December 31, 2008, we held approximately 97,000 gross (44,000 net) acres in our Kirby project area, of which approximately 2% were developed. Kirby is located adjacent to and just north of Fidelity Exploration and Development Company’s project area, which is north of J. M. Huber’s project area in Wyoming. As of December 31, 2008, we were producing approximately 1.4 gross (0.6 net) MMcf per day from approximately 23 gross (15 net) producing wells in this area. During the year ended December 31, 2008, we drilled 6 gross (3 net) wells in the Kirby area at depths between 500 and 1,200 feet in the Wall and Flowers-Goodale coals. We have commercial gas production from Kirby and transport our Kirby gas production through the Bitter Creek Pipeline, which became operational in late August 2006. We plan to target up to six distinct coal seams in the Kirby area.

As of December 31, 2008, we had approximately 4.0 Bcf of net proved reserves in Kirby based on a CIG index price of $4.61 per Mcf.

· Deer Creek—As of December 31, 2008, we held approximately 49,000 gross (41,000 net) acres in our Deer Creek project area, of which approximately 9% were developed. Our Deer Creek project area is located adjacent to St. Mary’s Hanging Woman project to the south and Fidelity’s CX Ranch Field to the west. Extensive drilling activity has occurred in both areas to date.

We acquired this acreage as part of the acquisition of properties from Marathon Oil Corp. in March 2005 and we operate 100% of the acreage. We began development in 2005 in the Dietz POD which is located in the Deer Creek area just to the southeast of Kirby. As of December 31, 2008, we were producing approximately 3.0 gross (1.4 net) MMcf per day from approximately 57 gross (38 net) wells in this area. During the year ended December 31, 2008, we drilled 2 gross (2 net) wells in the Deer Creek area at depths between 200 and 1,000 feet and targeted the Anderson, Canyon, Cook, and Wall coal seams. We transport our Deer Creek gas production through the Bitter Creek Pipeline.

As of December 31, 2008, we had 3.8 Bcf of proved reserves in Deer Creek.  Approximately 79% of our gross acreage in Deer Creek is on U.S. federal land.

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· Bear Creek—As of December 31, 2008, we held approximately 76,000 gross (64,000 net) acres in our Bear Creek project area, all of which were undeveloped. Our Bear Creek project area is located adjacent to and just north of our Cabin Creek project area in Wyoming and northeast of St. Mary’s Hanging Woman project. We operate all of our acreage in Bear Creek, which was acquired from Marathon Oil Corp. in March 2005.

As of December 31, 2008, we had no proved reserves in Bear Creek.  Approximately 87% of our gross acreage in Bear Creek is on U.S. federal land, and as of December 31, 2008, we had no drilling permits for Bear Creek.

· Bradshaw—Our Bradshaw project area is located to the northeast of our Cabin Creek project area in Wyoming. As of December 31, 2008, we held approximately 79,000 gross (71,000 net) acres in Bradshaw, all of which were undeveloped. As of December 31, 2008, we operated all of the acreage.

As of December 31, 2008, we had no proved reserves in Bradshaw.  Approximately 78% of our gross acreage in Bradshaw is on U.S. federal land, and as of December 31, 2008, we had no drilling permits for Bradshaw.

Wyoming—Green River Basin

On April 20, 2006, we acquired undeveloped natural gas properties, including related interests and assets, located in the Green River Basin of Wyoming from Kennedy Oil. The initial acquisition included approximately 30,000 gross (29,000 net) undeveloped acres for prospective CBM development in the Fort Union Big Red Coal formation. As of December 31, 2008, we owned 33,000 gross (32,000 net) undeveloped acres and we operated 100% of this acreage. As part of the acquisition, we also acquired 20 shut-in wells and 23 approved drilling permits and a 65% working interest in existing deep rights below the base of the Fort Union formation. As of December 31, 2008, we had drilled 14 gross (14 net) wells. As of December 31, 2008, we had 14 approved permits for our Green River Basin properties. We are in the process of applying for an additional 16 drilling permits which we expect to be approved in 2009 and 2010. In addition, we are in the process of applying for 34 drilling permits for conventional wells which we expect to be approved through 2010.  As of December 31, 2008, we had no proved reserves in the Green River Basin.

Exploration & Production Activities

Producing Wells and Acreage

The following table sets forth certain information regarding our ownership of productive wells and total acreage as of December 31, 2006, 2007 and 2008. For purposes of this table, productive wells are wells producing gas or dewatering.

(1) Gross undeveloped and total acreage decreased from December 31, 2007 to December 31, 2008 due to the expiration of acreage in our Kirby project area where we had a 50% working interest. Net undeveloped and total acreage increased from December 31, 2007 to December 31, 2008 due to the acquisition of other acreage where we have a 100% working interest.

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Lease Expirations

(1) Leases expiring in 2010 based on lease expirations represent approximately 16,663 gross (10,794 net) acres. The combined expirations of leased acreage for 2009 and 2010 account for 6% of our gross and 5% of our net acreage currently in place. Failure to pay shut-in and delay rental payments could result in further expiration of leased acreage. We are evaluating our expiring leases for 2009 and 2010 to determine whether we should pursue extensions or release the acreage. Expiration of leases in future years could also result in additional impairments in unevaluated properties.

(2) In April and June 2005, the U.S. Bureau of Land Management in Miles City, Montana issued suspensions of operations for the majority of our federal leases in Montana. The suspensions were issued based upon a court order issued on April 5, 2005 by the U.S. District Court of Montana that required the BLM to complete a Supplemental Environmental Impact Statement (SEIS) to address phased development of coal bed natural gas. The U.S. Ninth Circuit Court of Appeals also issued an order on May 31, 2005 which enjoined the BLM from approving coal bed natural gas production projects in the Powder River Basin of Montana. Both of these actions placed limitations on lease development until completion of the SEIS.

The 2005 injunction was lifted by the Ninth Circuit Court of Appeals on October 29, 2007. The record of decision (ROD) for the SEIS was signed by the BLM on December 30, 2008 and went into effect on January 14, 2009. The Suspension of Operations and Production for the suspended leases was terminated effective February 1, 2009. We have received letters from the BLM with amended lease terms of the affected leases. Leases that were suspended will be placed back into an active lease status with the primary term increasing for approximately three to five years based on the time period the leases were in suspension.

We were also granted suspension of certain state and federal leases in the Green River Basin totaling 4,481 gross (4,361 net) acres. The suspensions were requested primarily due to a lack of necessary infrastructure for well dewatering and gas transportation. In addition, the suspensions were granted pending approval of certain surface containment and discharge options by the BLM as well as completion of the BLM’s environmental assessment of the Red Desert watershed area.

Natural Gas Reserves

The following table summarizes the reserve estimate and analysis of net proved reserves of natural gas as of December 31, 2006, 2007 and 2008, in accordance with SEC guidelines. The data for the periods listed was prepared by NSAI in Dallas, Texas. The present value of estimated future net revenues from these reserves was calculated on a non-escalated price basis discounted at 10% per year. As of December 31, 2008, there were no proved reserves related to our Green River Basin assets.

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(1) The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved reserves discounted at 10% after giving effect to income taxes, and as calculated in accordance with SFAS No. 69. Standardized measure does not represent an estimate of fair market value of our reserves.

(2) Total proved reserves for 2006 declined primarily due to declines in the price of natural gas. Please see Item 1A, Risk Factors—Risks Related to Our Business—The volatility of natural gas and oil prices could have a material adverse effect on our business.

(3) Future cash flows for 2008 declined primarily due to declines in the price of natural gas. Please see Item 1A, Risk Factors—Risks Related to our Business—The volatility of natural gas and oil prices could have a material adverse effect on our business.

Summary of Well Activity

Our drilling, recompletion, abandonment and acquisition activities for the periods indicated are shown below:

We had no exploratory wells as of December 31, 2008.

We are currently evaluating drilling plans for 2009 in light of the current economic and gas pricing environment.

Gas Gathering, Transportation and Compression

We have constructed and plan to continue to construct additional low-pressure gas gathering systems to transport natural gas from the wellhead to compression stations as part of the completion of a well. As of December 31, 2008, we owned and operated approximately 295 miles of low-pressure gas gathering pipelines primarily in the Recluse and Cabin Creek areas of Wyoming. We use third-party services to compress and transport our natural gas to market in return for compression and transportation fees.

We use Western Gas Resources, Inc. for compression and transportation services in our Squaw Creek area of the Recluse Prospect and Clear Creek Energy Services, LLC for compression services in the Ring of Fire area of our

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Recluse Prospect. We have constructed the low-pressure gathering infrastructure to the inlet of the compression facilities for both the Squaw Creek and Ring of Fire areas. Both Western Gas Resources and Clear Creek Energy Services charge a fee plus allocated fuel for compressing our gas. Western Gas Resources transports our gas to Glenrock on the Fort Union Gas Gathering Line where we take title to the gas and have the ability to sell the gas to a third party purchaser or to Western Gas Resources. Clear Creek Energy Services delivers our gas to us at the outlet of their compression facilities where we have the ability to sell the gas to a third party purchaser. Gas at the tailgate of Clear Creek Energy Services’ compression facility can move north on Grasslands Pipeline or south on Thunder Creek Gas Gathering System.

We have a low-pressure gas gathering agreement and a high-pressure gathering and compression agreement with Bitter Creek Pipelines, LLC for the Kirby and Deer Creek areas. Under the low-pressure gas gathering agreement, Bitter Creek Pipelines constructed a central compression site to compress a maximum daily quantity of gas for delivery into Bitter Creek’s Pipelines’ high-pressure gathering line in exchange for a gathering payment comprised of a commodity rate based on average daily volumes and monthly demand charges based on the number of compression sites and compressors. Pursuant to the high-pressure gas gathering agreement, Bitter Creek Pipelines transports a maximum daily quantity of our gas on its high-pressure line in exchange for a demand fee, gathering rate and processing service fee, as applicable. The rates under these agreements will be adjusted annually for inflation. The Bitter Creek Pipelines high-pressure line delivers our gas to the Bitter Creek Landeck Compressor Station for redelivery north into Williston Basin Interstate Pipeline Company and/or south into Thunder Creek Gas Services, LLC and any other future delivery points on the Bitter Creek Pipelines system. The Bitter Creek Pipelines pipeline and compression facilities became operational in late August 2006. The low-pressure gas gathering agreement has an initial term of ten years, and the high-pressure gas gathering agreement has an initial term of five years, in each case, from August 28, 2006, the effective date of the agreements. Each gas gathering agreement will be automatically renewable after the initial term on a month-to-month basis, unless terminated by either party upon 60 days notice. In addition, after five years, if Bitter Creek Pipelines determines that it is no longer economically feasible to provide services under the low-pressure gas gathering agreement, it may terminate the low-pressure gas gathering agreement in its sole discretion with 60 days written notice.

Pursuant to a gas gathering agreement, we utilize Cantera Gas Holdings, LLC to gather and compress our gas in the Cabin Creek area. We have connected this area to the Big Horn Gas Gathering Pipeline, which takes our gas to multiple outlets. Pursuant to a construction and field operation agreement between us and Bighorn Gas Gathering, L.L.C., a subsidiary of Cantera Natural Gas, Bighorn Gas Gathering is constructing and operating, and we agreed to pay the costs of the construction and operation of, the gas gathering extension that connects our properties in the Cabin Creek area to the Big Horn Gas Gathering Pipeline. The construction and operating agreement has an initial term of one year and continues on a month-to-month basis thereafter unless terminated by either party upon 90 days’ written notice. For five years after October 18, 2006, the effective date of the agreement, Big Horn Gas Gathering has an option to purchase the gas gathering extension from us. Under certain circumstances, Big Horn Gas Gathering also has a right of first refusal with respect to the extension. In 2008, Cantera Gas Holdings, LLC and Big Horn Gas Gathering, LLC were acquired by Copano Natural Gas. Big Horn Gas Gathering has indicated its intention to purchase the gas gathering extension in 2009. In connection with the purchase of the gas gathering extension, we expect to amend the terms of the gas gathering agreement to provide further transportation alternatives for our gas.

In November 2006, we entered into a gas gathering agreement with Mountain Gas Resources, Inc. related to certain of our Green River Basin properties in Sweetwater County, Wyoming. The agreement provides that we may transport up to an average of 5 MMcf/day from those Green River Basin properties in exchange for a gathering and compression fee. The fees under this agreement will be adjusted annually for inflation. The term of this agreement is two years, continuing year to year until terminated by either party with thirty days’ written notice. During the term of the agreement, if we determine that our gas deliverability from the dedicated area will exceed 3 MMcf/day, we may notify Mountain Gas Resources to initiate construction of an additional pipeline loop. Mountain Gas Resources may construct such loop at its own cost, a result of which the term of this agreement will extend for five years from the date of our notice, or we may pay the actual costs of construction directly and the term of this agreement will remain as initially established. Pursuant to this agreement, we have committed to deliver to Mountain Gas Resources all of the gas now or hereafter produced from all formations and all wells located within the dedicated area.

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Natural gas in the Powder River Basin is transported by three intrastate gathering pipelines, Thunder Creek Gas Gathering, Fort Union Gas Gathering and the Kinder Morgan Lateral, and one interstate pipeline, the Grasslands Pipeline. According to the Wyoming Oil and Gas Conservation Commission, gas transported from the Powder River Basin as of December 31, 2008 was approximately 1.4 Bcf per day, with remaining available capacity of approximately 0.2 Bcf per day, or 14% of the total capacity. The gas is moved to marketing hubs in southern Wyoming or western North Dakota, where pipeline interconnections enable gas to move to distribution centers, primarily in the midwestern and southern United States. However, a surplus of natural gas arriving at these marketing hubs from the Powder River Basin and elsewhere relative to the available takeaway capacity from these hubs has caused Rocky Mountain gas to generally trade at a discount to the NYMEX natural gas index price. From January 1, 2007 through December 31, 2007, Rocky Mountain gas traded at a differential to the NYMEX natural gas index price that ranged from a premium of $0.46 to a discount of $7.42 with an average differential of a discount of $3.06. From January 1, 2008 through December 31, 2008, Rocky Mountain gas traded at a differential to the NYMEX natural gas index price that ranged from a premium of $0.17 to a discount of $6.26 with an average differential of a discount of $2.45.

Transportation of natural gas and access to throughput capacity have a direct impact on natural gas prices in the Rocky Mountain region, where our operations are concentrated. As drilling activity increases throughout the Rocky Mountain region, additional production may come on line, which could cause bottlenecks or capacity constraints. Generally speaking, a surplus of natural gas production relative to available transportation capacity has a negative impact on prices. Conversely, as capacity increases, and bottlenecks are eliminated, prices generally increase. The Rockies Express Pipeline, which was completed to Audrain County, Missouri in early 2008, has increased takeaway capacity by approximately 2 Bcf per day from key marketing hubs. We expect that the completion of additional proposed pipelines will help reduce the differential between gas produced in the Rocky Mountain region and the NYMEX natural gas index price. Additional proposed pipelines are scheduled to be completed in late 2010 and 2011. General economic conditions and the future demand for natural gas may change the timing of proposed pipelines.

Marketing and Customers

We currently have a contract with Enserco Energy Inc. to purchase the gas at the tailgate of the Clear Creek compression facility in Recluse and at the Landeck compressor station for gas delivered from our Kirby and Deer Creek project areas. Pursuant to an agreement with United Energy Trading, United Energy Trading currently purchases our gas at Glenrock, Wyoming after the compression and transportation from our Squaw Creek and Cabin Creek areas. Both Enserco Energy and United Energy Trading have extensive experience in gas marketing services in the Rocky Mountain region and specifically in the Powder River Basin and surrounding gas producing basins. Our contractual arrangements with Enserco Energy and United Energy Trading are based on the CIG index price and are cancelable upon thirty and sixty days’ written notice, respectively, if we determine there are more attractive purchasing arrangements in the marketplace. During the year ended December 31, 2007, Enserco Energy, United Energy Trading and Cantera Natural Gas purchased 58%, 36% and 5% of our gas sold, respectively. During the year ended December 31, 2008, Enserco Energy, and United Energy Trading purchased 46%, and 54% of our gas sold, respectively. In the event that Enserco Energy or United Energy Trading were to experience financial difficulties or were to no longer purchase our natural gas, we could, in the short-term, experience difficulty in our marketing of natural gas, which could adversely affect our results of operations.

Hedging Activities

We seek to reduce our exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. Our fixed-price contracts are comprised of energy swaps and collars. These contracts allow us to predict with greater certainty the effective natural gas prices to be received for hedged production and provide a benefit to operating cash flows and earnings when market prices are less than the fixed prices provided by the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling prices and floors provided in those contracts. With regard to hedging arrangements, our credit facility provides that acceptable commodity hedging arrangements cannot be greater than 80 to 85%, depending on the measurement date, of our monthly production from our hydrocarbon

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properties that are used in the borrowing base determination, and that the fixed or floor price of our hedging arrangements must be equal to or greater than the gas price used by the lenders in determining the borrowing base.

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of December 31, 2008. As of December 31, 2008, we had hedged volumes through December 2009. Please see Note 6 and Note 20 of the notes to the audited financial statements appearing elsewhere in this report for further information regarding our derivatives.

(1) Volumes hedged using the CIG index price published in the first issue of Inside FERC’s Gas Market Report for each calendar month of the derivative transaction.

(2) Assumes ceiling prices for natural gas collar volumes.

(3) Fair value based on CIG index price in effect for each month as of December 31, 2008.

Competition

We compete with a number of other potential purchasers of oil and gas leases and producing properties, many of which have greater financial resources than we do. The bidding for oil and gas leases has become particularly intense in the Powder River Basin with bidders evaluating potential acquisitions with varying product pricing parameters and other criteria that result in widely divergent bid prices. The presence of bidders willing to pay prices higher than are supported by our evaluation criteria could further limit our ability to acquire oil and gas leases. In addition, low or uncertain prices for properties can cause potential sellers to withhold or withdraw properties from the market. In this environment, we cannot guarantee that there will be a sufficient number of suitable oil and gas leases available for acquisition or that we can obtain oil and gas leases or obtain financing for or participants to join in the development of prospects.

In addition to competition for leasehold acreage in the Powder River Basin, the oil and gas exploration and production industry is intensely competitive as a whole. We compete against well-established companies that have significantly greater financial, marketing, personnel and other resources than we do. This competition could have a material adverse effect on our ability to execute our plan and our profitability.

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Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in certain areas of the Rocky Mountain region. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Employee and Labor Relations

We have reduced our full-time employees to 38 as of April 9, 2009 as a result of cost cutting measures. We believe that our relationships with our current employees are good. None of our employees are covered by a collective bargaining agreement. From time to time, we use the services of independent consultants to perform various professional services, particularly in the areas of legal and regulatory services. Independent contractors often perform well drilling and production operations, including pumping, maintenance, dispatching, inspection and testing. Reductions in full-time employees were due to general economic conditions and low natural gas prices in the Rocky Mountain region. While we believe the employees in place are integral to our future business plans, our liquidity and ability to attract capital will determine future staffing levels.

We depend to a large extent on the services of certain key management personnel and the loss of any could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees, including our executive officers.

Regulations

The natural gas industry is subject to regulation by federal, state and local authorities on matters such as employee health and safety, permitting, bonding and licensing requirements, air quality standards, water pollution, the treatment, storage and disposal of wastes, plant and wildlife protection, storage tanks, the reclamation of properties and plugging of oil wells after gas operations are completed, the discharge or release of materials into the environment, and the effects of gas well operations on groundwater quality and availability and on other resources.

In addition, the possibility exists that new legislation or regulations may be adopted or new interpretations of existing laws and regulations may be issued that would have a significant impact on our operations or our customers’ ability to use gas and may require us or our customers to change our or their operations significantly or incur substantial costs.

Climate change regulation is one area of potential future environmental law development. Studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases. The U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases from sources within the U.S. between 2012 and 2050. In addition, at least 17 states have developed initiatives to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The Environmental Protection Agency, or EPA, is separately considering whether it will regulate greenhouse gases as “air pollutants” under the existing federal Clean Air Act. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions of greenhouse gases, including methane or carbon dioxide in areas in which we conduct business, could result in changes to the consumption and demand for natural gas and could have adverse effects on our business, financial position, results of operations and prospects. These changes could increase the costs of our operations, including costs to operate and maintain our facilities, install new

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emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief, or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry. We have internal procedures and policies to ensure that our operations are conducted in substantial regulatory compliance.

Environmental Regulation of Gas Operations

Numerous governmental permits, authorizations and approvals are required for gas operations. In order to obtain such permits, authorizations and approvals, we are, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of gas or related activities may have upon the environment. Compliance with the terms of such permits, authorizations and approvals and all other requirements imposed by such authorities may be costly and time consuming and may delay or limit commencement or continuation of exploration or production operations. Moreover, failure to comply may result in the imposition of significant fines, penalties and injunctions. Future legislation or regulations may increase and/or change the requirements for the protection of the environment, health and safety and, as a consequence, our activities may be more closely regulated. This type of legislation and regulation, as well as future interpretations of existing laws, may result in substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which cannot be predicted. Further, the imposition of new or revised environmental laws, regulations or requirements could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste.

While it is not possible to quantify the costs of compliance with all applicable federal, state and local environmental laws, those costs have been and are expected to continue to be significant. We did not make any capital expenditures for environmental control facilities for the years ended December 31, 2007 or 2008. Any environmental costs are in addition to well closing costs, property restoration costs and other, significant, non-capital environmental costs, including costs incurred to obtain and maintain permits, gather and submit required data to regulatory authorities, characterize and dispose of wastes and effluents, and maintain management operational practices with regard to potential environmental liabilities. Compliance with these federal and state environmental laws has substantially increased the cost of gas production, but is, in general, a cost common to all domestic gas producers.

The magnitude of the liability and the cost of complying with environmental laws cannot be predicted with certainty due to the lack of specific environmental, geologic, and hydrogeologic information available with respect to many sites, the potential for new or changed laws and regulations, the development of new drilling, remediation, and detection technologies and environmental controls, and the uncertainty regarding the timing of work with respect to particular sites. As a result, we may incur material liabilities or costs related to environmental matters in the future and such environmental liabilities or costs could adversely affect our results and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct our operations. Further, given the retroactive nature of certain environmental laws, we have incurred, and may in the future incur, liabilities associated with: the investigation and remediation of the release of hazardous substances, oil, natural gas, other petroleum products or other substances; environmental conditions; and damage to natural resources arising from properties and facilities currently or previously owned or operated as well as sites owned by third parties to which we sent waste materials for disposal.

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We may be subject to various generally applicable federal environmental and related laws, including the following:

· the Clean Air Act;

· the Federal Water Pollution Control Act/Clean Water Act;

· the National Environmental Policy Act;

· the Federal Land Policy and Management Act;

· the Safe Drinking Water Act;

· the Toxic Substances Control Act;

· the Comprehensive Environmental Response, Compensation and Liability Act (Superfund);

· the Solid Waste Disposal Act/Resource Conservation and Recovery Act;

· the Emergency Planning and Community Right to Know Act; and

· the Endangered Species Act;

as well as state laws of similar scope and substance in each state in which we operate.

Regulatory requirements not directly applicable to us, but governing the ability of federal, state, or local governments to issue approvals, permits, or authorizations, or to take other actions, may also affect our operations. Such requirements include, without limitation, the National Environmental Policy Act and similar state statutory or regulatory requirements.

These environmental laws require monitoring, reporting, permitting and/or approval of many aspects of gas operations. Both federal and state inspectors regularly inspect facilities during construction and during operations after construction. We have ongoing environmental management, compliance and permitting programs designed to assist in compliance with such environmental laws. We believe that we have obtained or are in the process of obtaining all required permits under federal and state environmental laws for our current gas operations. Further, we believe that we are in substantial compliance with such permits. However, violations of permits, failure to obtain permits or other violations of federal or state environmental laws could cause us to incur significant liabilities to correct such violations, to provide additional environmental controls, to obtain required permits or to pay fines which may be imposed by governmental agencies. New permit requirements and other requirements imposed under federal and state environmental laws may cause us to incur significant additional costs that could adversely affect our operating results.

Some laws, rules and regulations relating to the protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination. Such laws render a person or company liable for environmental and natural resource damages, cleanup costs and, in the case of oil spills in certain states, consequential damages without regard to negligence or fault. Other laws, rules and regulations may require the rate of natural gas and oil production to be below the economically optimal rate or may even prohibit exploration or production activities in environmentally sensitive areas.

Common law theories of recovery may apply to operations where the presence, release, storage, transportation or use of natural gas or production waste is alleged to cause personal injury, illness or property damage as a result. The theories of negligence, trespass and strict liability have been used by land owners, individuals or trespassers to invoke claims for recovery of personal injuries, illness, property damage, loss of profits and related claims. Generally, such common law claims by third parties are not preempted by federal or state environmental laws, rules or regulations and may be used by plaintiffs in state law claims or as supplemental jurisdiction claims in conjunction with federal or state statutory environmental litigation.

In addition, state laws often require some form of remedial action such as closure of inactive pits and plugging of abandoned wells to prevent pollution from former or suspended operations. Legislation has been proposed and continues to be evaluated in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes.” This reclassification would make such wastes subject to much more stringent and expensive storage, treatment, disposal and clean up requirements. If such legislation were to be enacted, it could have a significant adverse impact on our operating costs, as well as the natural gas and oil industry

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in general. Initiatives to regulate further the disposal of natural gas and oil wastes are also proposed in certain states from time to time and may include initiatives at county, municipal and local government levels. These various initiatives could have a similar adverse impact on us.

From time to time, we have been the subject of investigations, administrative proceedings and litigation by government agencies and third parties relating to environmental matters. We may become involved in future proceedings, litigation or investigations and incur liabilities that could be materially adverse to us.

Federal Regulation of the Sale and Transportation of Gas

Various aspects of our operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission, or FERC, regulates the transportation and sale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In the past, the federal government has regulated the prices at which gas could be sold. While “first sales” by producers of natural gas, and all sales of condensate and natural gas liquids, can be made currently at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the Natural Gas Policy Act in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

We own certain natural gas in-field low-pressure pipelines that we believe meet the traditional tests which FERC has used to establish a pipeline’s status as a gatherer under section 1(b) of the Natural Gas Act, 16 U.S.C. § 717(b) and are therefore not subject to FERC jurisdiction.

Additional proposals and proceedings that might affect the gas industry are pending before Congress, FERC, the Minerals Management Service, state commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon our capital expenditures, earnings or competitive position. No material portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

Beginning in 1992, FERC issued a series of orders (“Order No. 636”) which required interstate natural gas pipelines to provide transportation service separate or unbundled from the pipeline’s sales of gas. In addition, Order No. 636 required interstate natural gas pipelines to provide open access transportation on a non-discriminatory basis that treats similarly situated shippers equally. The courts affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, and FERC has since reviewed and modified its open access regulations. In particular, FERC has reviewed its transportation regulations, including how they operate in conjunction with state proposals for retail gas marketing restructuring, whether to eliminate cost of service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. In February 2000, FERC issued Order No. 637 amending certain regulations governing interstate natural gas pipeline companies in response to the development of more competitive markets for natural gas and natural gas transportation. The goal of Order No. 637 is to “fine tune” the open access regulations implemented by Order No. 636 to accommodate subsequent changes in the market. Key provisions of Order No. 637 include:

(1)   waiving the price ceiling for short-term capacity release transactions until September 30, 2002 (which was reversed pursuant to an order on remand issued by FERC on October 31, 2002);

(2)   permitting value oriented peak/off peak rates to better allocate revenue responsibility between short-term and long-term markets;

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(3)   permitting term differentiated rates, in order to better allocate risks between shippers and the pipeline;

(4)   revising the regulations related to scheduling procedures, capacity, segmentation, imbalance management, and penalties;

(5)   retaining the right of first refusal and the five year matching cap for long-term shippers at maximum rates, but significantly narrowing the right of first refusal for customers that FERC does not deem to be captive; and

(6)   adopting new web site reporting requirements that include daily transactional data on all firm and interruptible contracts and daily reporting of scheduled quantities at points or segments.

The new reporting requirements became effective on September 1, 2000. FERC has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if FERC does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. Our low-pressure gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services. In addition, FERC’s approval of transfers of previously regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to FERC regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future.

State Regulation of Gas Operations

Our operations are also subject to regulation at the state and, in some cases, the county, municipal and local governmental levels. Such regulations include requiring permits for the construction, drilling and operation of wells, maintaining bonding requirements in order to drill or operate wells, regulating the surface use and requiring the restoration of properties upon which wells are drilled, requiring the proper plugging and abandonment of wells, and regulating the disposal of fluids used and produced in connection with operations. Our operations are also subject to various state conservation laws and regulations. These include regulations that may affect the size of drilling and spacing units or proration units, the density of wells which may be drilled, and the mandatory unitization or pooling of gas properties. In addition, state conservation regulations may establish the allowable rates of production from gas wells, may prohibit or regulate the venting or flaring of gas, and may impose certain requirements regarding the ratability of gas production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory and nonpreferential purchase and/or transportation requirements, but does not generally entail rate regulation. These regulatory burdens may affect profitability, and we are unable to predict the future cost or impact of complying with such regulations.

Permitting Issues for Federal Lands

Approximately 67% and 61% of our gross acreage in Montana and Wyoming, respectively, is on U.S. federal land. Federal leases in Montana and Wyoming must be developed pursuant to the U.S. BLM’s Resource Management Plans. Federal leases are also subject to the National Environmental Policy Act and Federal Land Policy Management Act. The National Environmental Policy Act process imposes obligations on the federal government that may result in legal challenges and potentially lengthy delays in obtaining project permits or approvals. The Montana and Wyoming BLMs have been subject to several lawsuits from various environmental and tribal groups challenging Resource Management Plan amendments and supporting Environmental Impact Statements addressing CBM development in Montana and Wyoming. In 2003, the Montana BLM and Wyoming BLM each amended their Resource Management Plans based in part on Environmental Impact Statements prepared

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pursuant to the National Environmental Policy Act. Shortly after the issuance of the Environmental Impact Statements and amended Resource Management Plans, various plaintiffs brought legal actions challenging the Montana and Wyoming Environmental Impact Statements and Resource Management Plans. There have been at least five federal district court challenges to the Montana Environmental Impact Statements. There are also at least three federal district court challenges to the Wyoming Environmental Impact Statements currently pending before the United States District Court for the District of Wyoming.

In April and June 2005, the Montana BLM in Miles City, Montana issued suspensions of operations for the majority of our federal leases in Montana. The suspensions were issued based upon the court order issued on April 5, 2005 by the U.S. District Court of Montana which required the BLM to complete a SEIS to address phased development of coal bed natural gas. The U.S. Ninth Circuit Court of Appeals also issued an order on May 31, 2005 which enjoined the BLM from approving coal bed natural gas production projects in the Powder River Basin of Montana. Both of these actions placed limitations on lease development until completion of the SEIS.

The injunction on the development of federal leases in Montana was effectively lifted on February 1, 2009. As a result, leases that were suspended during the injunction will be placed back into an active lease status with the primary term increasing for approximately three to five years due to the time period the leases were in suspension.

In December 2007, the U.S. BLM imposed a permitting application fee of $4,000 per well drilled on federal lands. This fee increased our regulatory costs in 2008 by an additional $1.0 million and could affect the timing of our development of federal leases.

In addition to federal regulation, our federal leases are subject to certain state regulations which require governmental agencies to evaluate the potential environmental impact of a proposed project on government owned lands.

We have dedicated significant resources to managing regulatory and permitting matters to achieve efficient processing of federal permits and resource management plans. We believe we are making significant progress in resolving the outstanding regulatory and environmental issues in Montana and Wyoming.

Employee Health and Safety

We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements and general industry standards regarding recordkeeping requirements and the monitoring of occupational exposure to regulated substances.

ITEM 1A    RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, financial condition or results of operation.

Risks Related to Our Business

 Due to the recent financial and credit crisis, we may not be able to obtain funding, or obtain funding on acceptable terms, to meet our future capital needs, which could negatively affect our business, results of operations and financial condition.

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The continued credit crisis and the related turmoil in the global financial system have had an adverse impact on our business and financial condition, and we may face major challenges if conditions in the financial markets do not improve. Currently, we are not able to borrow additional amounts under our credit facility. As a result, we curtailed substantially all new drilling in the fourth quarter of 2008, and if our operating cash flow is not sufficient to carry out our drilling plans for 2009, we will be required to reduce the number of wells we drill or seek alternative sources of financing. However, due to the financial crisis, financing through the capital markets or otherwise may not be available to us on acceptable terms or at all. If additional funding is not available, or is available only on unfavorable terms, we may be unable to implement our drilling plans, make capital expenditures, withstand a further downturn in our business or the economy in general, or take advantage of business opportunities that may arise. Any further curtailment of our operations would have an additional adverse effect on our revenues and results of operations. In addition, current economic conditions have led to reduced demand for, and lower prices of, oil and natural gas, and a sustained decline in the price of natural gas would adversely affect our business, results of operations and financial condition. Please read “The volatility of natural gas and oil prices could have a material adverse effect on our business” below. Further, the economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us, and on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments. Also, market conditions could have an impact on our natural gas and oil derivatives transactions if our counterparties are unable to perform their obligations or seek bankruptcy protection.

Our credit facility has substantial restrictions and financial covenants that may affect our ability to successfully operate our business. In addition, we may have difficulty returning to compliance with certain financial covenants.

Our credit facility imposes certain operational and financial restrictions on us. These restrictions, among other things, limit our ability to:

·incur additional indebtedness;

·create liens;

·sell our assets or consolidate or merge with or into other companies;

·make investments and other restricted payments, including dividends; and

·engage in transactions with affiliates.

These limitations are subject to a number of important qualifications and exceptions. In addition, our credit facility requires us to maintain certain financial ratios and to satisfy certain financial conditions which may require us to reduce our debt or to take some other action in order to comply with them. These restrictions in our credit facility could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our credit facility.

We are not in compliance with the current ratio financial covenant and certain other covenants related to accounts payable, permitted liens and permitted debt under our credit facility, and would be in default absent a waiver or amendment. On April 14, 2009, the lenders waived compliance with the current ratio as of December 31, 2008 and March 31, 2009, and with such other restrictive covenants, subject to certain financial caps, until the next borrowing base redetermination expected in the fall of 2009. We have also not been in compliance with certain financial covenants for the last four quarters, including the first quarter of 2009, but obtained waivers and/or amendments in each instance. As a result of such non-compliance, we are unable to borrow additional funds under our credit agreement. We believe that we may not be in compliance with certain restrictive covenants throughout 2009, but will seek additional waivers. There can be no assurance that we will be able to obtain such waivers or that such waivers will be obtained on acceptable terms. If we are unable to obtain future waivers and/or to comply with the restrictive covenants, the lenders could accelerate our indebtedness or foreclose on properties held by liens. In addition, due to borrowing base limitations, we are currently unable to borrow additional funds under the credit facility. In connection with the waiver of the restrictive covenants, the lenders reduced our borrowing base to $9.0 million, with further monthly reductions until the borrowing base reaches $6.5 million on October 1, 2009. If natural gas prices do not improve, we expect that our borrowing base could be further reduced in the future.

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Please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility,” for a discussion of our credit facility.

Our development activities could require significant outside capital, which may not be available or could change our risk profile.

We expect to make substantial capital expenditures in the development of natural gas reserves in the future as part of our business strategy. In general, we intend to finance our capital expenditures in the future through cash flow from operations and the incurrence of indebtedness. However, due to limitations in our credit facility, we are currently unable to borrow additional amounts. In addition, our business experienced reduced cash flows during the fourth quarter of 2008 due to low natural gas prices. Future cash flows and the availability of financing will be subject to a number of variables such as:

· the level of production from existing wells;

· prices of natural gas and oil;

· our results in locating and producing new reserves;

· the success and timing of development of proved undeveloped reserves; and

· general economic, financial, competitive, legislative, regulatory and other factors beyond our control.

If we are unable to fund our planned activities with the combination of cash flow from operations and availability under our credit facility, we may have to obtain additional financing through the issuance of debt and/or equity. Recent conditions in the financial markets have had an adverse impact on our ability to access equity and capital markets. As a result, the availability of credit has become more expensive and difficult to obtain, and the cost of equity capital has also become more expensive. Some lenders are imposing more stringent restrictions on the terms of credit and there may be a general reduction in the amount of credit available in the markets in which we conduct business. The negative impact on the tightening of the credit markets will have a material adverse effect on us. In addition, the distribution levels of new equity issued may be higher than our historical levels, making additional equity issuances more expensive. Further, issuing equity securities to satisfy our financing requirements could cause substantial dilution to our stockholders. The level of our debt financing could also materially affect our operations and significantly affect our financial risk profile.

If our revenues decrease due to lower natural gas and oil prices, decreased production or other reasons, and if we could not obtain capital through our credit facility or otherwise, our ability to execute our development and acquisition plans, replace our reserves or maintain production levels could be greatly limited.

The volatility of natural gas and oil prices could have a material adverse effect on our business.

Our revenues, profitability and future growth and the carrying value of our natural gas and oil properties depend to a large degree on prevailing natural gas and oil prices. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon natural gas and oil prices. Prices for natural gas and oil are subject to large fluctuations in response to relatively minor changes in the supply and demand for natural gas and oil, uncertainties within the market and a variety of other factors in large part beyond our control, such as:

· the domestic and foreign supply of natural gas and oil;

· the activities of the Organization of Petroleum Exporting Countries and state-owned oil companies relating to oil price and production controls;

· overall domestic and global economic and political conditions;

· the consumption pattern of industrial consumers, electricity generators and residential users;

· the availability of transportation systems with adequate capacity;

· price and availability of alternative fuels;

· weather conditions and fluctuating seasonal demand;

· natural disasters;

· acts of terrorism;

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· political stability in the Middle East and elsewhere;

· domestic and foreign governmental regulations, including conservation efforts and taxation;

· the price and quantity of foreign imports; and

· the price and availability of alternative fuels.

In the past, natural gas prices have been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2007, the NYMEX natural gas index price ranged from a high of $8.64 per MMBtu to a low of $5.38 per MMBtu, while the CIG natural gas index price ranged from a high of $7.11 per MMBtu to a low of $0.06 per MMBtu. For example, during the year ended December 31, 2008, the NYMEX natural gas index price ranged from a high of $13.58 per MMBtu to a low of $5.29 per MMBtu, while the CIG natural gas index price ranged from a high of $10.26 per MMBtu to a low of $1.00 per MMBtu.

In addition to downward pressure on prices caused by reduced domestic demand, some analysts expect near-term domestic gas prices to fall further due to additional gas supplies from lower-cost resource plays, including shale, that use new exploration and production technologies and from foreign gas imports through existing and new natural gas liquefaction capacity.

A sharp decline in natural gas prices would result in a commensurate reduction in our revenues, income and cash flows from the production of natural gas and could have a material adverse effect on our borrowing base and proved reserves. In the event prices fall substantially, we may not be able to realize a profit from our production and would operate at a loss, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Due to a decline in the price of natural gas during the third quarter and the beginning of the fourth quarter, we curtailed substantially all new drilling for the fourth quarter of 2008 and have shut-in a number of wells that are not economic at current natural gas price levels.

Lower natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. For example, if natural gas prices decline by $0.10 per Mcf, then the pre-tax PV-10 of our proved reserves as of December 31, 2008 would decrease from $32.8 million to $31.7 million.

Low natural gas prices may result in impairments of our oil and gas properties.

Accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our properties for impairments. As such, we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period such impairment charges are taken. We reported impairments of our oil and gas properties of approximately $21.5 million and $18.2 million for the years ended December 31, 2008 and 2007, respectively, due to low CIG index prices. Based on the CIG index price of $2.20 per Mcf on April 9, 2009, we would have been required to take a total impairment of approximately $46.7 million at December 31, 2008. A further decline in gas prices or an increase in operating costs subsequent to the measurement date or reductions in the economically recoverable quantities could result in the recognition of additional impairments of our gas properties in future periods.

Approximately 62% of our total proved reserves as of December 31, 2008 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.

As of December 31, 2008, approximately 18% of our total proved reserves were developed non-producing and approximately 44% were undeveloped. We plan to develop and produce all of our proved reserves in the future, but ultimately some of these reserves may not be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced in the time periods we have planned, at the costs we have budgeted, or at all. Due to expectations of low natural gas prices in 2009, we have deferred drilling of our undeveloped reserves to future years which has affected the present value of future net cash flows for these reserves.

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Our estimated reserves are based on many assumptions, some of which may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

This annual report contains estimates of natural gas reserves, and the future net cash flows attributable to those reserves, prepared by Netherland, Sewell & Associates, Inc., our independent petroleum and geological engineers. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our and Netherland, Sewell & Associates, Inc.’s control. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to those reserves, is a function of: (1) the available data; (2) the accuracy of assumptions regarding future natural gas and oil prices and future development and exploitation costs and activities; and (3) engineering and geological interpretation and judgment. Reserves and future cash flows may be subject to material downward or upward revisions based upon production history, development and exploitation activities and natural gas and oil prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in this report. Any significant variance between these assumptions and actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this annual report were prepared by Netherland, Sewell & Associates, Inc. in accordance with the rules of the Securities and Exchange Commission, or SEC, and are not intended to represent the fair market value of such reserves.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our natural gas and oil properties also will be affected by factors such as:

· geological conditions;

· changes in governmental regulations and taxation;

· assumptions governing future prices;

· the amount and timing of actual production;

· future operating costs; and

· the capital costs of drilling new wells.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

We may not be able to find, acquire or develop additional natural gas reserves that are economically recoverable.

The rate of production from natural gas and oil properties declines as reserves are depleted. As a result, we must locate, acquire and develop new natural gas and oil reserves to replace those being depleted by production. We must do this even during periods of low natural gas and oil prices when it is difficult to raise the capital necessary to finance activities. Our future natural gas reserves and production and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to find or acquire and develop additional reserves at an acceptable cost or have necessary financing for these activities in the future.

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The development of natural gas properties involves substantial risks that may result in a total loss of investment.

The business of exploring for, developing and operating natural gas and oil properties involves a high degree of business and financial risks, and thus a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:

· unexpected or adverse drilling conditions;

· elevated pressure or irregularities in geologic formations;

· equipment failures, repairs or accidents;

· title problems;

· fires, explosions, blowouts, cratering, pollution and other environmental risks or other accidents;

· compliance with governmental regulations;

· adverse weather conditions;

· reductions in natural gas and oil prices;

· pipeline ruptures;

· unavailability or high cost of drilling rigs, other field services, equipment and labor; and

· limitations in the market for oil and gas.

A productive well may become uneconomic in the event that unusual quantities of water or other deleterious substances are encountered, which impair or prevent the production of natural gas and/or oil from the well. In addition, production from any well may be unmarketable if it is contaminated with unusual quantities of water or other deleterious substances. We may drill wells that are unproductive or, although productive, do not produce natural gas and/or oil in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Furthermore, a successful completion of a well does not ensure a profitable return on the investment.

We may not adhere to our proposed drilling schedule.

Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

· the results of our exploration efforts and the acquisition, review and analysis of data;

· the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;

· the approval of the prospects by the other participants after additional data has been compiled;

· economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability and prices of drilling rigs and crews; and

· the availability of leases and permits on reasonable terms for the prospects.

We must obtain governmental permits and approvals for drilling operations, which can result in delays in our operations, be a costly and time consuming process, and result in restrictions on our operations.

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuances in the Rocky Mountain region. Compliance with the requirements imposed by these authorities can be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations and/or fines. For example, in the ordinary course of our business, we have received notices of violation or orders to cease production with respect to certain of our wells that have resulted in production delays and/or fines. Similar regulatory or legal actions in the future may materially interfere with our operations or otherwise have a material adverse effect on us. In addition, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits

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we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitability. For example, in December 2007, the U.S. BLM imposed a permitting application fee of $4,000 per well drilled on federal lands. This fee increased our regulatory costs in 2008 by an additional $1.0 million and affected the timing of our development of federal leases.

Our natural gas sales are dependent on two customers and the loss of these customers or their inability to pay for our gas would adversely affect our ability to market our gas.

We market substantially all our natural gas to two purchasers. During the year ended December 31, 2008, Enserco Energy and United Energy Trading purchased 46% and 54% of our gas sold, respectively. In the event that Enserco Energy or United Energy Trading experienced financial difficulties or no longer purchased our natural gas, we could, in the short-term, experience difficulty in our marketing of natural gas, which could adversely affect our results of operations.

We may be adversely affected by natural gas prices in the Rocky Mountain region.

Substantially all of our properties are geographically concentrated at the northern end of the Rocky Mountain region. The price received by us for the natural gas production from these properties is determined mainly by factors affecting the regional supply of and demand for natural gas, as well as the general availability of pipeline capacity to deliver natural gas to the market. Based on recent experience, regional differences could cause a negative basis differential between the published indices generally used to establish the price received for regional natural gas production and the actual price we receive for natural gas production. For example, from January 1, 2008 through December 31, 2008, Rocky Mountain gas traded at a differential to the NYMEX natural gas index price that ranged from a premium of $0.17 to a discount of $6.26, and the differential averaged a discount of $2.45.

The majority of our properties are located in a five-county region in the northern end of the Powder River Basin in northeastern Wyoming and southern Montana, making us vulnerable to risks associated with having our production concentrated in one area.

The majority of our properties are geographically concentrated in a five-county region in the northern end of the Powder River Basin in northeastern Wyoming and southern Montana. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these properties caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or other events which impact this area.

We may suffer losses or incur liability for events for which we or the operator of a property have chosen not to obtain insurance.

Our operations are subject to hazards and risks inherent in producing and transporting natural gas and oil, such as fires, natural disasters, explosions, pipeline ruptures, spills and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our and others’ properties. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. In addition, pollution and environmental risks generally are not fully insurable. As a result of market conditions, existing insurance policies may not be renewed and other desirable insurance may not be available on commercially reasonable terms, if at all. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.

Our use of hedging arrangements could result in financial losses or reduce our income.

We currently engage in hedging arrangements to reduce our exposure to fluctuations in the prices of natural gas for a significant portion of our current natural gas production. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, the counterparty to the hedging contract defaults on its contract obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements

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may limit the benefits we would otherwise receive from increases in prices for natural gas. Please see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A, Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk and Items 1 and 2, Business and Properties—Operations—Hedging Activities.

Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce.

The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. For example, although volumes increased in 2008 overall, our volumes were reduced by approximately 1.3 MMcf per day from September 1, 2008 through December 31, 2008 due to low natural gas pricing, weather interruptions and pipeline flow interruptions due to hydrostatic testing.

In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, would have an adverse effect on our business.

Shortages of drilling rigs and equipment and experienced personnel could delay our operations.

Higher natural gas prices generally increase the demand for drilling rigs and equipment, field services and personnel with drilling or other oil and gas operational experience, and can lead to shortages of, and increasing costs or wages for, such equipment, services and personnel. Shortages of, or increasing costs for, experienced operational personnel and oil field equipment and services could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in wages or drilling or other operational costs could reduce our revenues.

We may incur losses as a result of title deficiencies in the properties in which we invest.

It is our practice in acquiring natural gas and oil leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of natural gas and oil lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to the drilling of a natural gas or oil well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. A title review conducted in connection with our credit facility revealed title defects on numerous properties. We have cured these defects and do not believe they will have a material adverse effect on our business or operations. Our failure to cure any future title defects may adversely impact our ability in the future to increase production and reserves. In addition, if a title review reveals that a lease or interest has been purchased in error from a person who was not the owner, our interest would be worthless.

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We may incur losses in our acreage position due to the expiration of leases.

Our leasehold position is subject to leases with terms which expire from 2009 to 2018. Our leases may not be held by production and may consequently expire if we are unable to develop them in a timely manner. In addition, leases held by production which are subsequently shut-in due to low natural gas prices may also expire if we are unable to make shut-in payments.

We are subject to environmental regulation that can materially adversely affect the timing and cost of our operations.

Our exploration and production activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, we are subject to legislation regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. Such laws and regulations have been frequently changed in the past, and we are unable to predict the ultimate cost of compliance as a result of any future changes. The adoption or enforcement of stricter regulations could have a significant impact on our operating costs, as well as on the natural gas and oil industry in general. Compliance with environmental laws and regulations can be very complex, and therefore, no assurances can be given that such environmental laws and regulations will not have a material adverse effect on our business, financial condition and results of operations.

Our operations could result in liability for personal injuries, property damage, discharge of hazardous materials, remediation and clean up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, but we do not believe that insurance coverage for environmental damages that occur over time, or complete coverage for sudden and accidental environmental damages, is available at a reasonable cost. Accordingly, we may be subject to liability or may lose the right to continue exploration or production activities upon substantial portions of our properties if certain environmental damages occur.

We are subject to complex governmental regulations which may materially adversely affect the cost of our business and result in delays in our operations.

Numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. We may be required to make large expenditures to comply with these regulatory requirements. Any increases in the regulatory burden on the natural gas and oil industry created by new legislation would increase our cost of doing business and could result in delays in our operations, and consequently, adversely affect our profitability. For example, in December 2007 the U.S. BLM imposed a permitting application fee of $4,000 per well drilled on federal lands. This fee increased our regulatory costs in 2008 by an additional $1.0 million and affected the timing of our development of federal leases.

In addition, from time to time we may be subject to legal proceedings and claims as a result of these regulations. Please see Item 3, Legal Proceedings, for a description of material pending litigation.

We operate in a highly competitive environment and our competitors may have greater resources than us.

The natural gas and oil industry is intensely competitive and we compete with other companies, many of which are larger and have greater financial, technological, human and other resources. Many of these companies not only explore for and produce crude oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Such companies may be able to pay more for productive natural gas and oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of

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properties and prospects than our financial or human resources permit. In addition, such companies may have a greater ability to continue exploration activities during periods of low oil and gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete, our operating results and financial position may be adversely affected.

The coal beds from which we produce methane gas contain water that may hamper our ability to produce gas in commercial quantities.

Coal beds contain water that must be reduced in order for the gas to desorb from the coal and flow to the well bore. Where groundwater produced from our coalbed methane projects fails to meet the quality requirements of applicable regulatory agencies or our wells produce water in excess of the applicable volumetric permit limit, we may have to explore alternative methods of disposal such as re-injections or water treatment facilities. The costs to dispose of this produced water may increase if any of the following occur:

· we cannot obtain future permits from applicable regulatory agencies;

· water of lesser quality is produced;

· our wells produce excess water; or

· new laws or regulations require water to be disposed of in a different manner.

Our ability to remove and dispose of sufficient quantities of water from a coal seam will determine whether or not we can produce gas in commercial quantities from that seam. The cost of water disposal may affect our profitability.

Our coalbed methane wells typically have a shorter reserve life and lower rates of production than conventional natural gas wells, which may adversely affect our profitability during periods of low natural gas prices.

The shallow coals from which we produce natural gas in the Powder River Basin typically have a seven to eight year reserve life and have lower total reserves and produce at lower rates than most conventional natural gas wells. We depend on drilling a large number of wells each year to replace production and reserves in the Powder River Basin and to distribute operational expenses over a larger number of wells. A decline in natural gas prices could make certain wells uneconomical because production rates are lower on an individual well basis and may be insufficient to cover operational costs.

We may have difficulty managing growth in our business.

Because of our small size, growth in accordance with our business plan, if achieved, will place a significant strain on our financial, technical, operational and management resources. If we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

Our success depends on our key management personnel, the loss of any of whom could disrupt our business.

The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management. The loss of services of any of our key managers could have a material adverse effect on our business. We have not obtained “key man” insurance for any members of our management. Mr. Peter G. Schoonmaker is our Chief Executive Officer and President, and Mr. Ronald T. Barnes is our Chief Financial Officer, Senior Vice President and Secretary. The loss of the services of either of these individuals, or other key personnel,

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may adversely affect our business and prospects. We currently do not have employment agreements or non-competition agreements with any of the members of our management other than Mr. Schoonmaker and Mr. Barnes.

Some of our directors may have conflicts of interest because they are also currently affiliates, directors or officers of entities that make investments in the energy sector and/or may compete with us. The resolution of these conflicts of interest may not be in our or our stockholders’ best interests.

Robert L. Cabes, Jr. and Jeffrey P. Gunst, two of our directors, serve as Partner and Principal, respectively, of Avista Capital Holdings, L.P., or Avista, a private equity firm that makes investments in the energy sector. Messrs. Cabes and Gunst have in the past provided consulting services to certain DLJ Merchant Banking portfolio companies through arrangements with MB Advisory Partners, LLC, an affiliate of Avista. In addition, Sylvester P. Johnson, IV serves as President, Chief Executive Officer and a director of Carrizo. F. Gardner Parker is a director of Carrizo and Susan Schnabel is a Managing Director of DLJ Merchant Banking which holds a 32.9% equity stake in us. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our stockholders’ best interest. In addition, our certificate of incorporation limits the fiduciary duties of our directors in conflict of interest situations, among other things.

Our failure to complete and integrate future acquisitions successfully could reduce our earnings and slow our growth.

We may be unable to identify potential acquisitions or to make acquisitions on terms that we consider economically acceptable. Furthermore, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our growth strategy may be hindered if we are not able to obtain such financing or regulatory approvals. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

Properties we acquire may not produce as expected, may be in an unexpected condition and may subject us to increased costs and liabilities, including environmental liabilities. Although we review acquired properties prior to acquisition in a manner consistent with industry practices, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit us to become sufficiently familiar with the properties to assess fully their condition, any deficiencies, and development potential. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties or properties with known adverse conditions and will sample the remainder. In addition, environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

The coal beds from which we produce may be drained by offsetting production wells.

Our drilling locations are spaced primarily using 80-acre spacing. Producing wells located on the 80-acre spacing units contiguous with our drilling locations may drain the acreage underlying our wells. If a substantial number of productive wells are drilled on spacing units adjacent to our properties, it could have an adverse impact on the economically recoverable reserves of our properties that are susceptible to such drainage.

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We may not be able to keep pace with technological developments in our industry.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other natural gas and oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

Because we are a relatively small company, we have been and expect to continue to be disproportionately negatively impacted by the cost of compliance with securities laws and regulations.

The Sarbanes-Oxley Act of 2002, or the Act, which became law in July 2002, has required changes in the corporate governance, securities disclosure and compliance practices of public companies. The SEC has promulgated rules pursuant to the Act covering a variety of subjects, including corporate governance guidelines. Compliance with these rules has significantly increased our legal, financial and accounting costs. In addition, compliance with these rules has required the dedication of a significant amount of the time of management and the board of directors and may make it more difficult for us to attract and retain qualified directors, particularly independent directors, or qualified executive officers. Because we are a small company with relatively few employees, we have been disproportionately negatively impacted by these rules and regulations.

As directed by Section 404 of the Act, the SEC adopted rules requiring public companies to include a report of management on the company’s internal control over financial reporting in their annual reports on Form 10-K that contains an assessment by management of the effectiveness of the company’s internal control over financial reporting. In addition, the public accounting firm auditing the company’s financial statements must attest to and report on management’s assessment of the effectiveness of the company’s internal control over financial reporting. The requirement to include management’s report first applies to this annual report. Our accounting firm will first be required to attest to and report on management’s assessment in the annual report for the year ended December 31, 2009. If management is unable to conclude that we have effective internal control over financial reporting, or if our independent auditors are unable to provide us, when required, with an unqualified report as to the effectiveness of our internal control over financial reporting, investors could lose confidence in the reliability of our financial statements, which could result in a decrease in the value of our securities.

We are a small company with limited resources. The number and qualifications of our finance and accounting staff are limited, and we have limited monetary resources. We experience difficulties in attracting qualified staff with requisite expertise due to our profile and a generally tight market for staff with expertise in these areas. We retained a consultant to assist us in the process of testing and evaluating our internal control over financial reporting. A key risk is that management will not timely remediate any deficiencies that may be identified as part of the review process.

Risks Related to our Relationship with DLJ Merchant Banking and Other Initial Stockholders

Our founding stockholders have substantial influence over the outcome of certain stockholder votes and may exercise this voting power in a manner adverse to our other stockholders.

DLJ Merchant Banking beneficially owns approximately 32.9% of our outstanding common stock. Accordingly, DLJ Merchant Banking is in a position to have a substantial influence on the outcome of certain matters requiring a stockholder vote, including the election of directors and the adoption of certain amendments to our certificate of incorporation.

In addition, Carrizo beneficially owns approximately 8.3% of our outstanding common stock. This ownership, when combined with that of DLJ Merchant Banking, constitutes slightly less than a majority of our common stock

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and could have the effect of delaying or preventing a change in control of or otherwise discouraging a potential acquirer from attempting to obtain control of us. In addition, the interests of these stockholders may differ from those of our other stockholders, and these stockholders may vote their common stock in a manner that may adversely affect our other stockholders.

Risks Relating to Our Common Stock

The price of our common stock may be volatile and you may not be able to resell your shares at a favorable price.

The market price of our common stock may be volatile and you may not be able to resell your shares at or above the price you paid for such shares. During 2008, the closing price of our common stock ranged from a high of $5.10 per share to a low of $0.24 per share. The risk factors set forth in this report, among other items, could affect our stock price.

The market for purchases and sales of our common stock may be very limited, and the sale of a limited number of shares could cause the price to fall sharply.

Although our common stock is listed for trading on the NASDAQ Global Market, our securities are currently relatively thinly traded. Accordingly, it may be difficult to sell shares of common stock quickly without significantly depressing the value of the stock. Unless we are successful in developing continued investor interest in our stock, sales of our stock could continue to result in major fluctuations in the price of the stock.

We may not be able to maintain compliance with NASDAQ’s continued listing requirements.

We must comply with NASDAQ’s continued listing requirements in order to maintain our listing on NASDAQ’s Global Market. These continued listing standards include requirements addressing the number of shares publicly held, market value of publicly held shares, stockholder’s equity, number of round lot holders, and a $1.00 minimum closing bid price. Our stock price has generally been below the $1.00 minimum bid requirement since October 2008. Ordinarily, if a company’s closing bid price is below $1.00 for 30 consecutive trading days, it receives a notice from NASDAQ that it will be subject to delisting if it fails to regain compliance within 180 days following the date of the notice letter by maintaining a minimum bid closing price of at least $1.00 for ten consecutive business days. However, the NASDAQ has proposed suspending the $1.00 minimum bid requirement through July 19, 2009. If NASDAQ reinstates the $1.00 minimum bid price requirement as scheduled and, thereafter, the closing bid price for our common stock is below $1.00 per share for 30 consecutive days or if we in the future fail to meet the other requirements for continued listing on the NASDAQ Global Market, then our common stock could be delisted.

In order to regain compliance with the $1.00 minimum bid requirement, we would have to attain a stock price of at least $1.00 per share for a minimum of 10 consecutive business days prior to the expiration of 180 days from the date of the notice letter from NASDAQ, but the NASDAQ may in its discretion require that we maintain a bid price of at least $1.00 per share for a period in excess of 10 consecutive business days.

The delisting of our common stock would adversely affect the market liquidity for our common stock, the per share price of our common stock and impair our ability to raise capital that may be needed for future operations. Delisting from NASDAQ could also have other negative results, including the potential loss of confidence by customers and employees, the loss of institutional investor interest and fewer business development opportunities. In addition, we would be subject to a number of restrictions regarding the registration and qualification of our common stock under federal and state securities laws.

If our common stock is not eligible for quotation on another market or exchange, trading of our common stock could be conducted in the over-the-counter market or on an electronic bulletin board established for unlisted securities such as the Pink Sheets or the OTC Bulletin Board. In such event, it could become more difficult to dispose of, or obtain accurate quotations for the price of our common stock, and there would likely also be a

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reduction in our coverage by security analysts and the news media, which could cause the price of our common stock to decline further.

If our stock price trades below $1.00 for a sustained period and we face delisting on the NASDAQ, we may seek to implement a reverse stock split. However, reverse stock splits frequently result in a loss in stockholder value as the actual post-split price is often lower than the pre-split price, adjusted for the split. Accordingly, a reverse stock split may not solve the listing requirement deficiency even if implemented.

The percentage ownership evidenced by the common stock is subject to dilution.

We are authorized to issue up to 100,000,000 shares of common stock and are not prohibited from issuing additional shares of such common stock. You do not have statutory “preemptive rights” and therefore are not entitled to maintain a proportionate share of ownership by buying additional shares of any new issuance of common stock before others are given the opportunity to purchase the same. Accordingly, your percentage ownership, as a holder of the common stock, will be subject to change as a result of the sale of any additional common stock or other equity interests in us.

Anti-takeover provisions in our certificate of incorporation, our bylaws and Delaware law could prohibit a change of control that our stockholders may favor and which could affect our stock price.

Provisions in our second amended and restated certificate of incorporation, our amended and restated bylaws, and applicable provisions of the Delaware General Corporation Law may make it more difficult and expensive for a third party to acquire control of us, even if a change of control would be beneficial to the interests of our stockholders. These provisions could discourage potential takeover attempts and could adversely affect the market price of our common stock. Our certificate of incorporation and bylaws:

· authorize the issuance of blank check preferred stock that could be issued by our board of directors to thwart a takeover attempt;

· classify the board of directors into staggered, three-year terms, which may lengthen the time required to gain control of our board of directors;

· prohibit cumulative voting in the election of directors, which would otherwise allow holders of less than a majority of stock to elect some directors;

· require super-majority voting by our stockholders to effect amendments to provisions of our certificate of incorporation concerning the number of directors;

· require super-majority voting by our stockholders to effect any stockholder-initiated amendment to any provision of our bylaws;

· limit who may call special meetings of our stockholders;

· prohibit stockholder action by written consent, thereby requiring all actions to be taken at a meeting of the stockholders;

· establish advance notice requirements for stockholder nominations of candidates for election to the board of directors or for stockholder proposals that can be acted upon at annual meetings of stockholders; and

· require that vacancies on the board of directors, including newly-created directorships, be filled only by a majority vote of directors then in office.

In addition, Section 203 of the Delaware General Corporation Law may discourage, delay or prevent a change in control by prohibiting us from engaging in a business combination with an interested stockholder for a period of three years after the person becomes an interested stockholder.

Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings,

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financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the board of directors deems relevant. The terms of our credit facility restrict the payment of dividends without the prior written consent of the lenders. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.

PART IV

ITEM 15    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(3) Exhibits

The following documents are filed as exhibits to this annual report:

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*              Filed herewith

†              Management contract or compensatory plan or arrangement

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: November 30, 2009

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

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