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**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

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**Form 10-K/A**

 

| x                                                                                                                                                                                                                                                                                                            | **ANNUAL REPORT PURSUANT TO SECTION 13  OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-------------------------------------------------------------------------------------------------------------------------|
|                                                                                                                                                                                                                                                                                                         |                                                                                                                    |
| **For the fiscal year ended December 31, 2008**                                                                                                                                                                                                                                                         |
|                                                                                                                                                                                                                                                                                                         |                                                                                                                    |
| **OR**                                                                                                                                                                                                                                                                                                       |
|                                                                                                                                                                                                                                                                                                         | ** **                                                                                                              |
| o                                                                                                                                                                                                                                                                                                            | **TRANSITION REPORT PURSUANT TO SECTION 13 OR  15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**       |
|                                                                                                                                                                                                                                                                                                         | ** **                                                                                                              |
| **For the transition period from                      to                      ** |

 

**Commission file no. 001-33457**

** **

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**Pinnacle Gas Resources, Inc.**

(Exact name of registrant as specified in its charter)

 

| **Delaware**                             | ** ** | **30-0182582**      |
|------------------------------------------|------------|---------------------|
| (State or other jurisdiction of          | ** ** | (I.R.S. Employer    |
| incorporation or organization)           | ** ** | Identification No.) |
|                                     | ** ** |                |
| **1 E. Alger Street**                    |       | **82801**           |
| **Sheridan, Wyoming**                    |       | (Zip code)          |
| (Address of principal executive offices) |       | ** **          |

 

Registrant’s telephone number, including areacode:**(307) 673-9710**

 

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

 

| **Title of  Each Class** | ** ** | **Name of Each Exchange on Which Registered** |
|--------------------------|------------|-----------------------------------------------|
| Common Stock             |       | Nasdaq Global Market                          |

 

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

**None**

 

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

 

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

 

Indicateby check mark whether the registrant (1) has filed all reports required tobe filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject tosuch filing requirements for the past 90 days. Yes x  No o

 

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

 

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to thebest of the registrant’s knowledge, in definitive proxy or informationstatements incorporated by reference in Part III of this Form 10-K orany amendment to this Form 10-K. x

 

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

 
| Large Accelerated Filer o      |   | Accelerated Filer o              |
|-----------------------------------------------|--------|--------------------------------------------|
|                                          |   |                                       |
| Non-Accelerated Filer x             |   | Smaller Reporting Company o |
| (Do not check if a smaller reporting company) |   |                                       |

 

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

 

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

 

Asof April 9, 2009, there were 29,188,009 shares of the registrant’s commonstock outstanding.

 

**DOCUMENTS INCORPORATED BY REFERENCE**

 

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

 

 

 

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**PINNACLEGAS RESOURCES, INC.**

 

**Index to Form 10-K**

 
| Part I                    |                                        |   | 3      |   |
|--------------------------------|---------------------------------------------|--------|--------|--------|
|                           |                                        |   |   |   |
| Items 1. and 2. | Business and Properties                     |   | 3      |   |
|                           |                                        |   |   |   |
| Item 1A.                  | Risk Factors                                |   | 24     |   |
|                           |                                        |   |   |   |
| Item 15.                  | Exhibits and  Financial Statement Schedules |   | 38     |   |
|                           |                                        |   |   |   |
|                           | Signatures                                  |   | 41     |   |

 

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We are filing thisAmendment No. 1 on Form 10-K/A to clarify two statements in Items 1and 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 otherdisclosure contained in our Form 10-K originally filed on April 15,2009.  No other Parts or disclosure fromour Annual Report on Form 10-K are included in this Amendment on Form 10-K/Aother than Items 1 and 2, below, and except for such included disclosure, thisAmendment on Form 10-K/A does not modify or update in any way our AnnualReport on Form 10-K. All disclosure provided in this Amendment on Form 10-K/Ais as of the date of the Annual Report on Form 10-K. We have not updatedthe disclosure in the Amendment on Form 10-K/A to reflect any recentdevelopment with respect to any disclosure contained in the Annual Report on Form 10-K.

 

**PART I**

 

**ITEMS1 AND 2    *BUSINESS ANDPROPERTIES***

 

**General**

 

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

 

As of December 31,2008, we owned natural gas and oil leasehold interests in approximately477,000 gross (332,000 net) acres, approximately 90% of which wereundeveloped. At December 31, 2008, we had estimated net proved reserves of27.7 Bcf, based on a year-end Colorado Interstate Gas, or CIG, index priceof $4.61 per Mcf. These net proved reserves were located on approximately10% of our net acreage. Based on our drilling results to date, analysis of coresamples and third-party results in adjacent areas, we believe that our remainingundeveloped CBM acreage has substantial commercial potential. None of ouracreage or producing wells is associated with coal mining operations.

 

As of December 31,2008, we owned interests in 663 gross (366 net) producing wells andoperated 97% of these wells. During the year ended December 31, 2008, wedrilled 117 gross (82 net) wells and produced an average of10.6 MMcf per day net to our interest. We exited 2008 producing10.1 MMcf per day net to our interest. During 2007, we drilled87 gross (61 net) wells and produced an average of 9.3 MMcf perday net to our interest.

 

We had a total capitalexpenditure budget of $30.1 million for 2008 and expected to drill146 gross (110 net) wells during the period. However, due to low CIGindex prices, the economic climate and limited capital resources, we reducedour 2008 capital expenditure budget resulting in actual 2008 capitalexpenditures of $27.8 million. In connection with our reduced capitalexpenditure budget, we also reduced our drilling and completion targets for2008. We curtailed substantially all new drilling in the fourth quarter of2008, and we have shut-in a number of wells that are not economic at currentnatural gas price levels. If natural gas prices remain low, we expect tocontinue to operate with a reduced capital expenditure plan. Under our reducedcapital expenditure plan, we would generally make such expenditures only asnecessary to secure drilling permits in strategic areas, drill wells thatsecure leasehold positions and construct the necessary infrastructure tocomplete and hook-up wells that have already been drilled. Our capitalexpenditure budget for 2009 will be dependent upon CIG index prices, our cashflows and the availability of additional capital resources.

 

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**OurPowder River Basin and Green River Basin CBM Projects**

 

During the period fromour formation in June 2003 to December 31, 2008, we completed777 gross (435 net) of the 817 gross (468 net) CBM wells wedrilled in the Powder River and Green River Basins. As necessary infrastructurebecomes available, we expect to complete the remaining gross wells drilledthrough December 31, 2008.

 

***Powder River Basin***

 

Our Powder River Basinproperties are located in Wyoming and Montana. Our acreage position in thenorthern end of the Powder River Basin is generally contiguous, providing uswith critical mass and the ability to execute large-scale development projectsin our operating areas.

 

·*Wyoming.*  Our principal Wyomingproperties in the Powder River Basin are located in two distinct project areas:Recluse and Cabin Creek. As of December 31, 2008, we held approximately120,000 gross (77,000 net) acres in the Powder River Basin in Wyomingfor prospective CBM development and we operated over 98% of this acreage. As ofDecember 31, 2008, we had 257 approved drilling permits for our PowderRiver Basin properties in Wyoming and we are in the process of applying for anadditional 302 drilling permits which we expect to be approved in 2009and 2010.

·*Montana.*  Our Montana properties arelocated in four project areas: Kirby, Deer Creek, Bear Creek and Bradshaw. Asof December 31, 2008, we held approximately 301,000 gross(220,000 net) acres in Montana for prospective CBM development and weoperated 100% of this acreage. We have continued development in the Deer Creekand Kirby areas, and in 2008, we drilled 8 gross (5 net) wells inthese areas. As of December 31, 2008, we had 32 approved drilling permitsfor our Montana properties and we are in the process of applying for anadditional 213 drilling permits which we expect to be approved in 2009and 2010. Of these additional permits, 90 are on fee and state land and123 are on federal land.

 

***Green River Basin***

 

On April 20, 2006,we acquired undeveloped natural gas properties, including related interests andassets, located in the Green River Basin of Wyoming from Kennedy Oil for anaggregate purchase price of approximately $27.0 million in cash. Our GreenRiver Basin properties are located in the northeast area of Sweetwater County,Wyoming. As of December 31, 2008, our properties in the Green River Basinconsisted of approximately 33,000 gross (32,000 net) undevelopedacres 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 ourinitial acquisition, we also acquired 20 shut-in wells and 23 approveddrilling permits and a 65% working interest in existing deep rights below thebase of the Fort Union formation. As part of our initial pilot program, we havebeen successful in downspacing a section of our Green River Basin property from160-acre spacing to 80-acre spacing, thus allowing us to more quickly dewaterwells in this area and reach gas production. We have begun development of awater management system in the Green River Basin and are currently waiting onapproval of our water management plan from the Wyoming Bureau of LandManagement which we expect to receive in late 2009. It is more expensive todrill in the Green River Basin because of the increased depth of the wells, theincreased cost of water management in the area and the need for additionalinfrastructure.

 

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 permitswhich we expect to be approved in 2009 and 2010. In addition, we are inthe 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 inour Green River Basin properties.

 

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**Summaryof Our Powder River and Green River Basin Properties**

 
| ** **         | ** ** | **Producing**         | ** ** | **Producing**         | ** ** | ** **    | ** ** |
|--------------------|------------|-----------------------|------------|-----------------------|------------|---------------|------------|
| ** **         | ** ** | **Wells**             | ** ** | **Wells**             | ** ** | ** **    | ** ** |
| ** **         | ** ** | **as of**             | ** ** | **as of**             | ** ** | **Estimated** | ** ** |
| ** **         | ** ** | **December 31,** | ** ** | **December 31,** | ** ** | **Total**     | ** ** |
| ** **         | ** ** | **2008**              | ** ** | **2007**              | ** ** | **Net**       | ** ** |
| ** **         | ** ** | **Gross**             | ** ** | **Net**               | ** ** | **Gross**     | ** ** | **Net** | ** ** | **Acres(1)** | ** ** |
| Recluse            |       | 427                   |       | 209                   |       | 431           |       | 214 |   | 16,000 |   |
| Cabin  Creek       |       | 156                   |       | 104                   |       | 89            |       | 53 |   | 37,000 |   |
| Kirby(3)           |       | 23                    |       | 15                    |       | 114           |       | 75 |   | 44,000 |   |
| Deer  Creek(3)     |       | 57                    |       | 38                    |       | 0             |       | 0 |   | 41,000 |   |
| Bear  Creek        |       | 0                     |       | 0                     |       | 0             |       | 0 |   | 64,000 |   |
| Bradshaw           |       | 0                     |       | 0                     |       | 0             |       | 0 |   | 71,000 |   |
| Green  River Basin |       | 0                     |       | 0                     |       | 0             |       | 0 |   | 32,000 |   |
| Other(2)           |       | 0                     |       | 0                     |       | 0             |       | 0 |   | 27,000 |   |
| Total              |       | 663                   |       | 366                   |       | 634           |       | 342 |   | 332,000 |   |

 

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(1) Estimated as of December 31,2008.

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

(3) In 2008, certainwells in the Kirby area were reassigned to the Deer Creek area. For the yearended December 31, 2008, the total wells for the two areas combineddeclined from 114 gross (75 net) wells to 80 gross (53 net)wells.

 

**OurHistory**

 

We were formed as aDelaware corporation in June 2003 by funds affiliated withDLJ Merchant Banking III, Inc., which we refer to collectively as DLJMerchant Banking, and subsidiaries of Carrizo Oil & Gas, Inc., orCarrizo, and U.S. Energy Corporation, or U.S. Energy. Carrizo andU.S. Energy contributed oil and gas reserves and leasehold interests inapproximately 81,000 gross (40,000 net) acres in exchange for sharesof our common stock and options to purchase shares of our common stock.DLJ Merchant Banking completed several cash investments in us in exchangefor shares of our common stock, Series A Redeemable Preferred Stock, andwarrants to purchase additional shares of our common stock, and has beeninstrumental 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, wecompleted a private offering of 12,835,230 shares of our common stock toqualified 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 sharesof common stock in a tax-free reorganization and each of Carrizo andU.S. Energy entered into a cashless exercise of all of their options for 584,102shares 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, weredeemed all of the outstanding shares of Series A Redeemable PreferredStock held by DLJ Merchant Banking with a portion of the proceeds wereceived in the private placement. In addition, following the final closing ofour private placement, we used a portion of the proceeds we received in theprivate placement to repurchase an aggregate of 1,587,598 shares of commonstock from DLJ Merchant Banking at a price per share equal to the privateplacement price of $11.00 per share less the initial purchaser’s discount andplacement fee. On September 22, 2006, DLJ Merchant Banking purchased allof the 2,459,102 shares of our common stock held by U.S. Energy and itsaffiliates in a private transaction.

 

In May 2007, wecompleted an initial public offering of 3,750,000 shares of our common stock ata public offering price of $9.00 per share.

 

In addition to theinitial contribution of leasehold interests to us by U.S. Energy andCarrizo, 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 acquiredapproximately 57,000 gross (22,000 net) acres along with 210 gross(96 net) producing wells and shut-in wells in Wyoming from GastarExploration, Ltd. and certain of its affiliates.

·In March 2005, we acquiredapproximately 223,000 gross (196,000 net) undeveloped acres forprospective CBM development in Montana and Wyoming from a subsidiary ofMarathon Oil Corporation.

·In April 2006, we acquiredapproximately 30,000 gross (29,000 net) undeveloped acres in theGreen River Basin in Wyoming.

 

Please see theinformation under the heading “Our Powder River Basin and Green River Basin CBMProjects—Green River Basin” in this annual report.

 

**CapitalExpenditure Plan**

 

We had a total capitalexpenditure budget of $30.1 million for 2008 and expected to drill146 gross (110 net) wells during that period. However, due to low CIGindex prices, the economic climate and limited capital resources, we reducedour 2008 capital expenditure budget resulting in actual 2008 capitalexpenditures of $27.8 million. In connection with our reduced capitalexpenditure budget, we also reduced our drilling and completion targets for2008. During the year ended December 31, 2008, we drilled 117 gross(82) net wells. We curtailed substantially all new drilling in the fourthquarter of 2008, and we have shut-in a number of wells that are not economic atcurrent natural gas price levels. If natural gas prices remain low, we expectto continue to operate with a reduced capital expenditure plan. Under ourreduced capital expenditure plan, we would generally make such expendituresonly as necessary to secure drilling permits in strategic areas, drill wellsthat secure leasehold positions and construct the necessary infrastructure tocomplete and hook-up wells that have already been drilled. The CIG index pricehas been extremely volatile during 2007 and 2008 and at times reached unusuallylow 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 of2008, respectively. If prices remain low, our cash flows from operations willdecrease and the borrowing base and borrowing availability under our creditfacility could be further reduced. If we do not have sufficient cash flows andcannot obtain capital through our credit facility or otherwise, our ability toexecute our development and acquisition plans, replace our reserves andmaintain production levels could be greatly limited. If natural gas prices donot improve, we will consider alternatives to increase liquidity, includingasset sales and issuances of equity. Our capital expenditure budget for 2009will be dependent upon CIG index prices, our cash flows and the availability ofadditional capital resources. For a discussion of our credit facility and othermatters that may limit our ability to execute our 2009 capital expenditureplan, please see “Management’s Discussion and Analysis of Financial Conditionand Results of Operations—Liquidity—Credit Facility.”

 

We are actively marketingcertain assets to raise additional capital and are also reviewing alternativesfor raising additional capital through equity and debt financing, capitalrestructuring and possible mergers. We sold our high pressure gas gatheringsystem in our Cabin Creek project area in Wyoming and our remaining interest inthe Arvada project area in Wyoming in April 2009. Although we are pursuingvarious alternatives to provide additional liquidity, there is no assurance ofthe likelihood or timing of any of these transactions.

 

**Overviewof the CBM Industry and the Powder River Basin**

 

CBM is natural gas thatis trapped within buried coal and is stored, or adsorbed, onto the internalsurfaces of the coal. Geologists have long known that coal was the source fornatural gas found in many conventional accumulations, but coalbeds were nottargeted for production due to high water content and minimal natural gasproduction. Following a West Virginia mine explosion in 1968, the U.S. Bureauof 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 ofwater are pumped from a coal seam. In a process known as dewatering ordepressuring, a submersible pump is set below the coal seam, and the watercolumn is pumped down, reducing the pressure in the coals. As pressure withinthe coalbed formation is reduced, CBM is released through a process calleddesorption. CBM then moves into naturally occurring cracks, or cleats, in thecoal, and then to the production wells. Cleats are natural fractures which haveformed in the coals, usually as a result of the coalification process andgeological stresses. Because the cleats are generally filled with water, thestatic water level above the coal must be reduced, which then lowers thereservoir pressure allowing desorption to occur. Thus, unlike producing from aconventional natural gas reservoir, reservoir pressure in a coalbed formationmust generally be reduced to allow for production of

 

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CBM. Because of thenecessity to remove water and reduce the pressure within the coal seam, CBM,unlike conventional hydrocarbons, often will not show immediately on initialproduction testing. Coalbed formations typically require extensive dewateringand depressuring before desorption can occur and the methane begins to flow atcommercial rates.

 

In the past20 years, CBM in the United States has evolved into a major component ofthe United States natural gas production. According to the National EnergyTechnology Laboratory, CBM provides approximately 8% of daily natural gasproduction in the United States. The Rocky Mountain region, due to its immensecoal reserve base, is a significant source of United States CBM production, andthere are more than 17,000 CBM wells in the Powder River Basin, according tothe 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 isexpected to increase substantially due to the economic viability of theresources and the tremendous reserve potential of the numerous, virtuallyundeveloped U.S. coal basins. Within the Rocky Mountain region, the PowderRiver Basin has become a major CBM producing basin. According to the U.S.Department of Energy 2002 Powder Basin Coalbed Methane Development and ProducedWater Management Study, the Montana portion of the Powder River Basin isestimated to have substantial recoverable reserves. According to the WyomingOil and Gas Conservation Commission, approximately 1.4 Bcf of CBM has beenproduced from the Powder River Basin per day.

 

The Powder River Basin isan asymmetrical structure and sedimentary basin bounded by the Bighorn andBlack Hills uplift and the Casper Arch. The Paleocene Fort Union formationcrops out along the basin margin and is overlain by the Eocene Wasatchformation in the central and western part of the basin. The Wasatch and FortUnion formations contain numerous coalbeds, some of which approach 250 feet intotal thickness. The Fort Union formation is divided, in ascendingstratigraphic order, into the Tullock, Lebo, and Tongue River members, with themajority of coal and CBM production being produced from the Tongue Rivermember.

 

The majority of PowderRiver Basin CBM reserves are found in the Fort Union formation. Extensivedrilling in the Fort Union formation (over 25,000 drilled well bores) hasprovided supporting data indicating that this formation contains numerouscoalbeds which are generally continuous, extremely permeable and relativelyshallow (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 PowderRiver Basin are drilled with small truck mounted water well rigs and aredrilled and completed using two basic completion techniques. The first and mostcommon drilling technique is open hole completion. The well is drilled to thetop of the target coal seam and production casing is set and cemented back tothe surface. The coal seam is then drilled out and under-reamed to open up morecoal face to production. The second completion technique is to drill throughthe base of the target coal and then set casing and cement to the surface. Thewell is then completed by perforating the casing at the target coal. In bothcompletion techniques, the borehole and coal face are then cleaned out andflushed by pumping approximately 600 barrels of formation water at high ratesinto the coal face. Once the well is completed, a submersible pump is run intothe well on production tubing to pump the water from the coal seam. After thecoal is depressurized, gas flows up the casing to the wellhead. At thewellhead, the gas and water are metered. The gas then flows to a centralcompressor station where it is compressed into a high-pressure pipeline. Thewater is sent through an underground pipeline for beneficial use or disposal.CBM production must be continuous to ensure a constant low-pressure gas flowand to sustain a commercially viable operation.

 

We have developedspecific drilling, cementing and completion technology that we have adapted tothe rank, depth and thickness of the coals found in all of our operating areas.Our drilling, completion and production practices utilize technologicaladvances in cementing, multiple zone completions and programmable submersiblepumps. We have developed drilling and cementing techniques that minimize thedamage to coal zones, preserve the potential of coals behind pipe and reducecementing costs. Multiple zone completions allow for the successful perforationof multiple zones which reduces costs and gives us the ability to sustain productionfrom coals less than

 

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ten feet in thickness. Programmable submersible pumps and telemetryallow us to implement aggressive production management programs on our wellsand projects.

 

Conventional gas wellsare typically 8,000 to 20,000 feet deep and initially produce large volumes ofgas relative to water. Natural gas normally does not require assistance to moveto the surface, and over time, gas production declines and water production mayincrease. In contrast, CBM wells generally range from 300 to 4,000 feet. In theearly stages of CBM production, large quantities of water and low quantities ofgas are produced. Water production is initiated to lower the downhole pressurewhich allows the methane to release from the coal. The water volumes eventuallydecline and gas quantities begin to rise. In most cases, assistance to bringthe gas to surface is not needed for the final period of production.

** **

***Water Production and Management***

 

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

 

Produced water is handledby 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 reverseosmosis; and/or

·sub-surface irrigation.

 

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

 

We have a water treatmentagreement with EMIT Water Discharge Technology, LLC for our Cabin Creekproject. Pursuant to the agreement, EMIT installed and operates treatmentfacilities necessary to treat a maximum daily quantity of water in exchange fora fixed daily fee and a variable fee per barrel of treated water that varieswith the sodium content of the water. The rate is subject to adjustmentannually 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 continueson a month-to-month basis thereafter unless terminated by either party upon90 days’ written notice. Prior to the end of the initial term, we mayextend the term by another three years upon payment of a renewal fee.

 

***Recovery Characteristics***

 

The primary variablesthat 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 toestimate how many tons of coal underlie a section of land. The estimate of thenumber of tons per section is multiplied by the estimated gas content of suchlands to estimate the gas in place for the section. Gas content in coal ismeasured in terms of standard cubic feet per ton. Sufficient coal permeabilityis a prerequisite for economic gas flow rates because gas and water must beable to flow to the wellbore. Most gas and water flow through the cleats andother fractures in the coal. Cleat spacing is influenced by a variety offactors and greatly affects permeability.

 

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**PowderRiver Basin CBM Production Overview**

 

The Powder River Basin islocated in northeastern Wyoming and southern Montana. The Powder River Basin isrich in natural resources with significant reserves of oil and gas as well assome of the world’s thickest coal seams. The Powder River Basin holds thedistinction of being the leading coal-producing area in the United States, andin recent years, has become one of the most active areas for oil and gasdrilling.

 

We target an average ofthree coal seams per drilling location and have up to five coal seams that webelieve are capable of commercial production. We expect that many of our wellswill be completed to more than one coal seam, and thus we may drill less thanthree wells per location. The coal seams that we target are part of the FortUnion formation and include the Canyon, Cook, Wall, Pawnee and Flowers-Goodale(the Roberts equivalent) coals, which are found at depths ranging from 200 to1,500 feet and are each approximately 15 to 60 feet thick.

 

Our wells generally reachtotal depth in one day and cost between $95,000 and $122,000 per well to drilland complete, depending on location, coal zones perforated and depth. Hook-up,infrastructure and water management costs are between $62,000 and $71,000 perwell in the Powder River Basin. Powder River CBM wells are drilled with smalltruck mounted water well rigs and are completed as either single or multiplezone producers. In a single coal completion, we top set the casing in the firstfoot of coal and complete the well by under-reaming the coal with a 12-inchdiameter tool. In a multiple zone completion, we typically top set andunder-ream the deepest coal seam and perforate the upper coal seamssequentially. Our general production profile for a CBM well shows production ofwater for 30 to 90 days prior to initial gas production. The lowering ofthe static water level reduces the coal formation pressure and allows the gasto desorb from the coal and migrate to the well bore. Gas production typicallyinclines steeply for an average of nine months, peaking at an average of over100 Mcf per day. A period of relatively flat production at peak continues forthree 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 itthrough one or more of several approved methods.

 

Our CBM wells in thePowder River Basin have all been drilled and cemented in anticipation ofcompleting more than one coal seam per well bore. In our project areas,depending on the thickness of and horizontal separation between coal seams, wegenerally complete several coals in one well upon initial hook-up. Coal seamsthicker than 25 feet are initially drilled as stand alone wells. Coal seamswith less than 100 feet of vertical separation are completedsimultaneously at initial hook-up. Our development activities include an activeprogram to sequentially complete upper coal seams in wells that are producingfrom a single coal seam since being initially drilled and completed. Wepresently have over 150 wells that have been identified in the Recluse area forfurther completions in upper coals. Our completion strategy generally is towait for the lower coal zones’ measured pressure to reach or equal the measuredpressure of the upper zones. Once the measured pressures are determined to beequal, the upper zones are perforated and completed. Sequential completion ofupper coal seams typically costs $12,000 per coal seam. We expect that multiplezone completions can increase the economic life of a well, increase previouslyunbooked behind pipe reserves from several thinner coal seams and enhance ourrate of return.

 

**GreenRiver Basin CBM Production Overview**

 

The Green River Basin isprimarily located in southwestern Wyoming, and our assets are located in theeastern half of the Wyoming portion of the Green River Basin. According to theU.S. Department of Energy 2004 Coal Bed Methane Primer, the Green RiverBasin has significant potential CBM reserves in place. The Green River Basin isan increasingly active basin for natural gas and CBM exploration and drilling.An Environmental Impact Statement, or EIS, is currently being prepared by theWyoming Bureau of Land Management for the drilling and development of up toapproximately 9,000 natural gas wells, including up to 500 CBM wells, on a1.1 million acre project area. Our Green River Basin acreage position isoffset by multiple fields producing from conventional reservoirs in the Lance,Lewis and Almond sandstones. In 2008, there were approximately 31 CBMprojects in the eastern half of the Green River Basin with a total of176 CBM wells drilled. These projects are being developed by approximately13 operators targeting coals in the Mesaverde, Fort Union and Wasatchformations.

 

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The Fort Union Big RedCoal, which we are targeting, is found at depths between 2,500 to6,500 feet. The Fort Union coals, including the Big Red Coal, aggregate approximately100 feet in thickness. The Big Red Coal accounts for up to 50 feet ofthe thickness. The Fort Union coals on our acreage have excellent permeabilityand gas saturation of generally 200 to 400 scf per ton of coal. Inaddition to the Big Red Coal, CBM potential exists in other coals of the FortUnion formation and in coals in the Wasatch and Mesaverde formations.

 

We anticipate developingthe Green River Basin CBM reserves primarily on 160-acre spacing. The14 gross (14 net) wells drilled as of December 31, 2008 on theacreage have generally reached total depth in five days. We estimate thatfuture 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 throughthe coal and perforating the coal formation. Our estimated production profileassumes little gas production for three to five months as the well is dewateredand the formation pressure lowered, a steep incline in production for thefollowing 12 months, peak production for 18 to 24 months and then aslow decline in production of approximately 10% per year over a 20 to25 year period. We estimate the standard reserve life of a well in theGreen River Basin will be approximately 25 years.

 

**Operations**

*** ***

***CBM Development, Projects and Operations***

 

Our properties in thePowder River Basin are primarily located in northeastern Wyoming and southernMontana and are generally contiguous, providing us with critical mass and theability to execute large scale development projects in our operating areas. Asof December 31, 2008, we owned leasehold interests in approximately421,000 gross (297,000 net) acres in the Powder River Basin, approximately99% of which we operated. As of December 31, 2008, we also owned leaseholdinterests in 33,000 gross (32,000 net) acres in the Green River Basin inWyoming.

 

Most of our developmentdrilling is in areas of known natural gas reserves and involves much lower riskthan the exploratory type of drilling that is required when searching for newnatural gas reserves. During the period from our formation in June 2003 toDecember 31, 2008, we completed 777 gross (435 net) of the 817gross (468 net) CBM wells we drilled in the Powder River and Green RiverBasins. As necessary infrastructure becomes available, we expect to completethe remaining gross wells drilled through December 31, 2008. During theyear ended December 31, 2008, we drilled 117 gross (82 net)wells and connected 110 gross (77 net) wells to our low-pressuregathering system. During the year ended December 31, 2007, we drilled87 gross (61 net) wells and connected 108 gross (73 net)wells to our low-pressure gathering system. At December 31, 2008, we wereproducing natural gas from approximately 663 gross (366 net) CBMwells at a net rate of 10.6 MMcf per day measured at the wellhead. Inresponse to lower CIG index prices, the state of the economy in general andlimited capital resources, we reduced our 2008 capital expenditure budget from$30.1 million to $27.8 million. We also reduced our drilling andcompletion targets for 2008 from approximately 146 gross (110 net) toapproximately 117 gross (82 net) wells. Our revised 2008 capitalexpenditure budget was used to drill and complete wells in 2008, to construct gasand water infrastructure, to fund plans of development costs for future wells,to fund undeveloped leasehold acquisition costs carried over from 2007, torecomplete certain wells, and to fund infrastructure and completion costsrelated to such wells drilled in 2007. If natural gas prices remain low, weexpect to continue to operate with a reduced capital expenditure plan thatallows us to secure drilling permits in strategic areas, drill wells thatsecure leasehold positions and construct the necessary infrastructure to completeand hook-up wells that have already been drilled. Our capital expenditurebudget for 2009 will be dependent upon CIG index prices, our cash flow and theavailability of additional capital resources.

 

Our drilling locationstarget the Canyon, Cook, Wall, Pawnee and Flowers-Goodale (the Robertsequivalent) coal seams in the Powder River Basin, which are found at depthsranging from 200 to 1,500 feet, and the Fort Union Big Red Coal in theGreen 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 proveddrilling locations assuming one coal seam per well. We expect that many of ourwells will be completed to more than one coal seam.

 

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*Wyoming—PowderRiver Basin*

 

Our principal Wyomingproperties in the Powder River Basin are located in two distinct project areas:Recluse and Cabin Creek. As of December 31, 2008, we held approximately120,000 gross (77,000 net) acres in the Powder River Basin in Wyomingfor prospective CBM development and we operated over 98% of this acreage.

 

Approximately 54% of ourgross acreage in the Powder River Basin in Wyoming is on U.S. federalland, and is subject to additional regulations not applicable to state or feeleases. Permitting new wells in Wyoming on federal land involves submitting aplan of development, or POD, to the Wyoming division of the United StatesBureau of Land Management, or Wyoming BLM, and is subject to an environmentalassessment and a review period. Typically, it takes three to six months tocomplete the permitting process and receive approval from the Wyoming BLM.Permitting new wells on state and fee land requires approval from the WyomingOil and Gas Conservation Commission and the approval process typically takes 30to 60 days. Please see the information under the heading “Regulations—PermittingIssues for Federal Lands” in this section of this annual report for furtherinformation.

 

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

 

·*Recluse*—Recluse is located on the northern endof the Gillette Fairway, where a majority of Powder River Basin CBM has beenproduced to date. As of December 31, 2008, we held approximately34,000 gross (16,000 net) acres in the Recluse area, of which approximately34% were developed. As of December 31, 2008, we operated approximately 99%of these properties. As of December 31, 2008, we were producingapproximately 11.8 gross (4.5 net) MMcf per day from approximately427 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 over200 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 areabased on a CIG index price of $4.61 per Mcf.  We are currently evaluating drilling plans for 2009 in light of thecurrent economic and gas pricing environment.

·*Cabin Creek*—Our Cabin Creek project is located onthe northern border of Wyoming adjacent to St. Mary’s Hanging Womanproject to the west. As of December 31, 2008, we held approximately55,000 gross (37,000 net) acres in Cabin Creek, of whichapproximately 25% were developed. As of December 31, 2008, we operatedapproximately 81% of these properties. We have a non-operating working interestin 32 wells operated by St. Mary Land and Exploration Company which arecovered by a joint operating agreement. As of December 31, 2008, weparticipated 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 drilled97 gross (71 net) wells. As of December 31, 2008, we hadapproximately 12.4 Bcf of net proved reserves in the Cabin Creek areabased on a CIG index price of $4.61 per Mcf. We are currently evaluatingdrilling plans for 2009 in light of the current economic and gas pricingenvironment.

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

* *

*Montana—PowderRiver Basin*

 

Our Powder River Basinproperties in Montana are located in four project areas: Kirby, Deer Creek,Bear Creek and Bradshaw. As of December 31, 2008, we held approximately301,000 gross (220,000 net) acres in Montana for prospective CBMdevelopment and we operated 100% of this acreage. In 2008, our primary focuswas the construction of water management infrastructure in the Kirby and DeerCreek areas. In addition, we drilled 8 gross (5 net) wells in theseareas.

 

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Because CBM developmentin Montana is still in its early stages, the permitting process is not asstreamlined in Montana as it is in Wyoming. Permitting new wells in Montana onfederal land involves submitting a plan of development, or POD, which typicallycovers approximately 30 to 100 80-acre locations, to the Montana division ofthe United States Bureau of Land Management, or Montana BLM, and is subject toan environmental evaluation under the National Environmental Policy Act and areview period. Permitting new wells on state and fee land involves submitting aPOD, which typically covers 200 to 300 wells, to the Montana Oil and GasConservation Commission, and is also subject to an environmental evaluationunder the National Environmental Policy Act and a review period. An injunctionwhich prohibited the Montana BLM from approving any CBM drilling permits incertain federal lands in the Montana portion of the Powder River Basin waslifted in December 2008. The primary lease term of federal acreage coveredby the injunction was suspended during the time period that the injunction wasin effect. We estimate the suspension will add an additional three to fiveyears to the primary term of all affected federal leases. Fee and state permitswere unaffected by the injunction. Approximately 67% of our gross acreage inMontana 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. Thepermit approval process for fee and state lands typically takes three to sixmonths. See “—Regulations—Permitting Issues for Federal Lands” for furtherdiscussion 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 inthe process of applying for an additional 213 drilling permits, 123 of whichare on federal lands and 90 of which are on state or fee lands. We expect thesepermits to be approved in 2009 and 2010. We are currently evaluating drillingplans for 2009 in light of the current economic and gas pricing environment.

 

·*Kirby*—Kirby was acquired at the time of ourinitial formation in 2003. As of December 31, 2008, we held approximately97,000 gross (44,000 net) acres in our Kirby project area, of whichapproximately 2% were developed. Kirby is located adjacent to and just north ofFidelity Exploration and Development Company’s project area, which is north ofJ. 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 fromapproximately 23 gross (15 net) producing wells in this area. Duringthe year ended December 31, 2008, we drilled 6 gross (3 net) wells inthe Kirby area at depths between 500 and 1,200 feet in the Wall andFlowers-Goodale coals. We have commercial gas production from Kirby andtransport our Kirby gas production through the Bitter Creek Pipeline, whichbecame operational in late August 2006. We plan to target up to sixdistinct coal seams in the Kirby area.

 

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

 

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

 

We acquired this acreageas part of the acquisition of properties from Marathon Oil Corp. in March 2005and we operate 100% of the acreage. We began development in 2005 in the DietzPOD which is located in the Deer Creek area just to the southeast of Kirby. Asof 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 drilled2 gross (2 net) wells in the Deer Creek area at depths between 200and 1,000 feet and targeted the Anderson, Canyon, Cook, and Wall coalseams. We transport our Deer Creek gas production through the Bitter CreekPipeline.

 

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

 

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·*Bear Creek*—As of December 31, 2008, we heldapproximately 76,000 gross (64,000 net) acres in our Bear Creekproject area, all of which were undeveloped. Our Bear Creek project area is locatedadjacent to and just north of our Cabin Creek project area in Wyoming andnortheast of St. Mary’s Hanging Woman project. We operate all of ouracreage 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 onU.S. federal land, and as of December 31, 2008, we had no drillingpermits for Bear Creek.

 

·*Bradshaw*—Our Bradshaw project area is located tothe northeast of our Cabin Creek project area in Wyoming. As of December 31,2008, we held approximately 79,000 gross (71,000 net) acres inBradshaw, all of which were undeveloped. As of December 31, 2008, weoperated 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 onU.S. federal land, and as of December 31, 2008, we had no drillingpermits for Bradshaw.

* *

*Wyoming—GreenRiver Basin*

 

On April 20, 2006,we acquired undeveloped natural gas properties, including related interests andassets, located in the Green River Basin of Wyoming from Kennedy Oil. Theinitial acquisition included approximately 30,000 gross (29,000 net)undeveloped acres for prospective CBM development in the Fort Union Big RedCoal formation. As of December 31, 2008, we owned 33,000 gross(32,000 net) undeveloped acres and we operated 100% of this acreage. Aspart of the acquisition, we also acquired 20 shut-in wells and23 approved drilling permits and a 65% working interest in existing deeprights 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. Weare in the process of applying for an additional 16 drilling permits which weexpect to be approved in 2009 and 2010. In addition, we are in the process ofapplying for 34 drilling permits for conventional wells which we expect to beapproved through 2010.  As of December 31,2008, we had no proved reserves in the Green River Basin.

*** ***

***Exploration & Production Activities***

* *

*ProducingWells and Acreage*

 

The following table setsforth certain information regarding our ownership of productive wells and totalacreage as of December 31, 2006, 2007 and 2008. For purposes of thistable, productive wells are wells producing gas or dewatering.

 
| ** **                 | ** ** | **Productive** | ** ** | **Approximate Leasehold Acreage** | ** ** |
|----------------------------|------------|----------------|------------|-----------------------------------|------------|
| ** **                 | ** ** | **Wells**      | ** ** | **Developed**                     | ** ** | **Undeveloped** | ** ** | **Total** | ** ** |
| ** **                 | ** ** | **Gross**      | ** ** | **Net**                           | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| December 31,  2006    |       | 529            |       | 281                               |       | 26,160 |   | 17,400 |   | 427,840 |   | 290,600 |   | 454,000 |   | 308,000 |   |
| December 31,  2007    |       | 634            |       | 342                               |       | 33,120 |   | 22,200 |   | 460,880 |   | 293,800 |   | 494,000 |   | 316,000 |   |
| December 31,  2008(1) |       | 663            |       | 366                               |       | 47,000 |   | 31,800 |   | 430,000 |   | 300,200 |   | 477,000 |   | 332,000 |   |

 

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(1) Grossundeveloped 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 a50% working interest. Net undeveloped and total acreage increased from December 31,2007 to December 31, 2008 due to the acquisition of other acreage where wehave a 100% working interest.

 

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*LeaseExpirations*

 
| ** **         | ** ** | **Expiring Acres 2009(1)** | ** ** | **Held by Production** | ** ** | **Suspended(2)** | ** ** |
|--------------------|------------|----------------------------|------------|------------------------|------------|------------------|------------|
| ** **         | ** ** | **Gross**                  | ** ** | **Net**                | ** ** | **Gross**        | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Wyoming**        |       |                       |       |                   |       |             |       |   |   |   |   |   |   |
| Recluse            |       | 502                        |       | 342                    |       | 30,021           |       | 15,239 |   | 0 |   | 0 |   |
| Cabin  Creek       |       | 77                         |       | 7                      |       | 18,717           |       | 15,863 |   | 0 |   | 0 |   |
| Green  River Basin |       | 0                          |       | 0                      |       | 6,761            |       | 6,537 |   | 4,841 |   | 4,361 |   |
|               |       |                       |       |                   |       |             |       |   |   |   |   |   |   |
| **Montana**        |       |                       |       |                   |       |             |       |   |   |   |   |   |   |
| Bear  Creek        |       | 1,275                      |       | 628                    |       | 844              |       | 769 |   | 66,020 |   | 57,163 |   |
| Deer  Creek        |       | 480                        |       | 108                    |       | 5,100            |       | 3,955 |   | 38,817 |   | 32,553 |   |
| Bradshaw           |       | 5,368                      |       | 3,959                  |       | 0                |       | 0 |   | 61,327 |   | 60,662 |   |
| Kirby              |       | 1,969                      |       | 833                    |       | 22,230           |       | 12,375 |   | 34,651 |   | 17,324 |   |
| **Totals**         |       | 9,671                      |       | 5,877                  |       | 83,673           |       | 54,738 |   | 205,656 |   | 172,063 |   |

 

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(1) Leases expiringin 2010 based on lease expirations represent approximately 16,663 gross(10,794 net) acres. The combined expirations of leased acreage for 2009and 2010 account for 6% of our gross and 5% of our net acreage currently inplace. Failure to pay shut-in and delay rental payments could result in furtherexpiration of leased acreage. We are evaluating our expiring leases for 2009 and2010 to determine whether we should pursue extensions or release the acreage.Expiration of leases in future years could also result in additionalimpairments in unevaluated properties.

(2) In April andJune 2005, the U.S. Bureau of Land Management in Miles City, Montanaissued suspensions of operations for the majority of our federal leases inMontana. 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 tocomplete a Supplemental Environmental Impact Statement (SEIS) to address phaseddevelopment of coal bed natural gas. The U.S. Ninth Circuit Court ofAppeals also issued an order on May 31, 2005 which enjoined the BLM fromapproving coal bed natural gas production projects in the Powder River Basin ofMontana. Both of these actions placed limitations on lease development untilcompletion of the SEIS.

 

The 2005 injunction waslifted by the Ninth Circuit Court of Appeals on October 29, 2007. Therecord 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 ofOperations and Production for the suspended leases was terminated effective February 1,2009. We have received letters from the BLM with amended lease terms of theaffected leases. Leases that were suspended will be placed back into an activelease status with the primary term increasing for approximately three to fiveyears based on the time period the leases were in suspension.

 

We were also grantedsuspension of certain state and federal leases in the Green River Basintotaling 4,481 gross (4,361 net) acres. The suspensions wererequested primarily due to a lack of necessary infrastructure for welldewatering and gas transportation. In addition, the suspensions were grantedpending approval of certain surface containment and discharge options by theBLM as well as completion of the BLM’s environmental assessment of the RedDesert watershed area.

 

*NaturalGas Reserves*

 

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

 

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| ** **                                                                          | ** ** | **As of December 31,** | ** ** |
|-------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                          | ** ** | **2006(2)**                 | ** ** | **2007** | ** ** | **2008(3)** | ** ** |
| **Estimated net proved reserves:**                                                  |       |                        |       |   |   |   |   |
| Proved  developed producing (MMcf)                                                  |       | 3,588                       |       | 7,442 |   | 10,465 |   |
| Proved  developed non-producing (MMcf)                                              |       | 4,292                       |       | 3,016 |   | 4,947 |   |
| Total  proved developed (MMcf)                                                      |       | 7,880                       |       | 10,458 |   | 15,412 |   |
| Proved  undeveloped (MMcf)                                                          |       | 12,409                      |       | 15,263 |   | 12,307 |   |
| Total  proved reserves (MMcf)                                                       |       | 20,289                      |       | 25,721 |   | 27,719 |   |
| Future  cash flows before income taxes (in millions)                                |       | $                           | 34.8       |   | $ | 65.0 |   | $ | 47.3 |   |
| Standardized  measure (in millions)(1)                                              |       | $                           | 22.4       |   | $ | 38.6 |   | $ | 32.1 |   |
| Price  used for computing reserves (CIG index price per Mcf as of December 31) |       | $                           | 4.460      |   | $ | 6.040 |   | $ | 4.605 |   |

 

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(1) The standardizedmeasure of discounted future net cash flows represents the present value offuture cash flows attributable to our proved reserves discounted at 10% aftergiving 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 ourreserves.

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

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

* *

*Summaryof Well Activity*

 

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

 
| ** **                     | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------|------------|----------------------------------|------------|
| ** **                     | ** ** | **2006**                         | ** ** | **2007** | ** ** | **2008** | ** ** |
| ** **                     | ** ** | **Gross**                        | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Wells  Drilled:                |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Capable  of Production         |       | 230                              |       | 139 |   | 87 |   | 61 |   | 117 |   | 82 |   |
| Dry                            |       | 0                                |       | 0 |   | 0 |   | 0 |   | 0 |   | 0 |   |
| Wells  Acquired                |       | 29                               |       | 29 |   | 0 |   | 0 |   | 3 |   | 3 |   |
| Wells  Abandoned               |       | 1                                |       | 1 |   | 1 |   | 1 |   | 16 |   | 9 |   |
| Net  Increase in Capable Wells |       | 258                              |       | 167 |   | 86 |   | 60 |   | 104 |   | 76 |   |

 

We had no exploratorywells as of December 31, 2008.

 

We are currentlyevaluating drilling plans for 2009 in light of the current economic and gaspricing environment.

*** ***

***Gas Gathering, Transportation and Compression***

 

We have constructed andplan to continue to construct additional low-pressure gas gathering systems totransport natural gas from the wellhead to compression stations as part of thecompletion of a well. As of December 31, 2008, we owned and operatedapproximately 295 miles of low-pressure gas gathering pipelines primarilyin the Recluse and Cabin Creek areas of Wyoming. We use third-party services tocompress and transport our natural gas to market in return for compression andtransportation fees.

 

We use Western GasResources, Inc. for compression and transportation services in our SquawCreek area of the Recluse Prospect and Clear Creek Energy Services, LLCfor compression services in the Ring of Fire area of our 

 

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

 

We have a low-pressuregas gathering agreement and a high-pressure gathering and compression agreementwith Bitter Creek Pipelines, LLC for the Kirby and Deer Creek areas. Underthe low-pressure gas gathering agreement, Bitter Creek Pipelines constructed acentral compression site to compress a maximum daily quantity of gas fordelivery into Bitter Creek’s Pipelines’ high-pressure gathering line inexchange for a gathering payment comprised of a commodity rate based on averagedaily volumes and monthly demand charges based on the number of compressionsites and compressors. Pursuant to the high-pressure gas gathering agreement,Bitter Creek Pipelines transports a maximum daily quantity of our gas on itshigh-pressure line in exchange for a demand fee, gathering rate and processingservice fee, as applicable. The rates under these agreements will be adjustedannually for inflation. The Bitter Creek Pipelines high-pressure line deliversour gas to the Bitter Creek Landeck Compressor Station for redelivery northinto Williston Basin Interstate Pipeline Company and/or south into ThunderCreek Gas Services, LLC and any other future delivery points on the BitterCreek Pipelines system. The Bitter Creek Pipelines pipeline and compressionfacilities became operational in late August 2006. The low-pressure gasgathering agreement has an initial term of ten years, and the high-pressure gasgathering 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 willbe automatically renewable after the initial term on a month-to-month basis,unless terminated by either party upon 60 days notice. In addition, afterfive years, if Bitter Creek Pipelines determines that it is no longereconomically feasible to provide services under the low-pressure gas gatheringagreement, it may terminate the low-pressure gas gathering agreement in itssole discretion with 60 days written notice.

 

Pursuant to a gasgathering agreement, we utilize Cantera Gas Holdings, LLC to gather andcompress our gas in the Cabin Creek area. We have connected this area to theBig Horn Gas Gathering Pipeline, which takes our gas to multiple outlets.Pursuant to a construction and field operation agreement between us and BighornGas Gathering, L.L.C., a subsidiary of Cantera Natural Gas, Bighorn GasGathering is constructing and operating, and we agreed to pay the costs of theconstruction and operation of, the gas gathering extension that connects ourproperties in the Cabin Creek area to the Big Horn Gas Gathering Pipeline. Theconstruction and operating agreement has an initial term of one year and continueson a month-to-month basis thereafter unless terminated by either party upon90 days’ written notice. For five years after October 18, 2006, theeffective date of the agreement, Big Horn Gas Gathering has an option topurchase the gas gathering extension from us. Under certain circumstances, BigHorn Gas Gathering also has a right of first refusal with respect to theextension. In 2008, Cantera Gas Holdings, LLC and Big Horn GasGathering, LLC were acquired by Copano Natural Gas. Big Horn Gas Gatheringhas indicated its intention to purchase the gas gathering extension in 2009. Inconnection with the purchase of the gas gathering extension, we expect to amendthe terms of the gas gathering agreement to provide further transportationalternatives for our gas.

 

In November 2006, weentered 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 5MMcf/day from those Green River Basin properties in exchange for a gatheringand compression fee. The fees under this agreement will be adjusted annuallyfor inflation. The term of this agreement is two years, continuing year to yearuntil terminated by either party with thirty days’ written notice. During theterm of the agreement, if we determine that our gas deliverability from thededicated area will exceed 3 MMcf/day, we may notify Mountain Gas Resources toinitiate construction of an additional pipeline loop. Mountain Gas Resourcesmay construct such loop at its own cost, a result of which the term of thisagreement will extend for five years from the date of our notice, or we may paythe actual costs of construction directly and the term of this agreement willremain as initially established. Pursuant to this agreement, we have committedto deliver to Mountain Gas Resources all of the gas now or hereafter producedfrom all formations and all wells located within the dedicated area.

 

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Natural gas in the PowderRiver Basin is transported by three intrastate gathering pipelines, ThunderCreek Gas Gathering, Fort Union Gas Gathering and the Kinder Morgan Lateral,and one interstate pipeline, the Grasslands Pipeline. According to the WyomingOil and Gas Conservation Commission, gas transported from the Powder RiverBasin as of December 31, 2008 was approximately 1.4 Bcf per day, withremaining available capacity of approximately 0.2 Bcf per day, or 14% of thetotal capacity. The gas is moved to marketing hubs in southern Wyoming orwestern North Dakota, where pipeline interconnections enable gas to move todistribution centers, primarily in the midwestern and southern United States.However, a surplus of natural gas arriving at these marketing hubs from thePowder River Basin and elsewhere relative to the available takeaway capacityfrom these hubs has caused Rocky Mountain gas to generally trade at a discountto 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 gasindex price that ranged from a premium of $0.46 to a discount of $7.42 with anaverage 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 gasindex price that ranged from a premium of $0.17 to a discount of $6.26 with anaverage differential of a discount of $2.45.

 

Transportation of naturalgas and access to throughput capacity have a direct impact on natural gasprices in the Rocky Mountain region, where our operations are concentrated. Asdrilling activity increases throughout the Rocky Mountain region, additionalproduction may come on line, which could cause bottlenecks or capacityconstraints. Generally speaking, a surplus of natural gas production relativeto available transportation capacity has a negative impact on prices.Conversely, as capacity increases, and bottlenecks are eliminated, pricesgenerally increase. The Rockies Express Pipeline, which was completed toAudrain County, Missouri in early 2008, has increased takeaway capacity byapproximately 2 Bcf per day from key marketing hubs. We expect that thecompletion of additional proposed pipelines will help reduce the differentialbetween gas produced in the Rocky Mountain region and the NYMEX natural gasindex price. Additional proposed pipelines are scheduled to be completed inlate 2010 and 2011. General economic conditions and the future demand fornatural gas may change the timing of proposed pipelines.

*** ***

***Marketing and Customers***

 

We currently have acontract with Enserco Energy Inc. to purchase the gas at the tailgate ofthe Clear Creek compression facility in Recluse and at the Landeck compressorstation for gas delivered from our Kirby and Deer Creek project areas. Pursuantto an agreement with United Energy Trading, United Energy Trading currentlypurchases our gas at Glenrock, Wyoming after the compression and transportationfrom our Squaw Creek and Cabin Creek areas. Both Enserco Energy and UnitedEnergy Trading have extensive experience in gas marketing services in the RockyMountain region and specifically in the Powder River Basin and surrounding gasproducing basins. Our contractual arrangements with Enserco Energy and UnitedEnergy Trading are based on the CIG index price and are cancelable upon thirtyand sixty days’ written notice, respectively, if we determine there are moreattractive purchasing arrangements in the marketplace. During the year ended December 31,2007, Enserco Energy, United Energy Trading and Cantera Natural Gas purchased58%, 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 ourgas sold, respectively. In the event that Enserco Energy or United EnergyTrading were to experience financial difficulties or were to no longer purchaseour natural gas, we could, in the short-term, experience difficulty in ourmarketing of natural gas, which could adversely affect our results ofoperations.

*** ***

***Hedging Activities***

 

We seek to reduce ourexposure to unfavorable changes in natural gas prices, which are subject tosignificant and often volatile fluctuation, through the use of fixed-pricecontracts. Our fixed-price contracts are comprised of energy swaps and collars.These contracts allow us to predict with greater certainty the effectivenatural gas prices to be received for hedged production and provide a benefitto operating cash flows and earnings when market prices are less than the fixedprices provided by the contracts. However, we will not benefit from marketprices that are higher than the fixed prices in the contracts for hedgedproduction. Collar structures provide for participation in price increases anddecreases to the extent of the ceiling prices and floors provided in thosecontracts. With regard to hedging arrangements, our credit facility providesthat acceptable commodity hedging arrangements cannot be greater than 80 to85%, depending on the measurement date, of our monthly production from ourhydrocarbon

 

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

 

The following tablesummarizes the estimated volumes, fixed prices, fixed-price sales and fairvalue 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 financialstatements appearing elsewhere in this report for further information regardingour derivatives.

 
| ** **                                 | ** ** | **Year Ending  December 31,  2009** | ** ** |
|--------------------------------------------|------------|------------------------------------------|------------|
| ** **                                 | ** ** | **(Unaudited)**                          | ** ** |
| **Natural Gas Collars:**                   |       |                                     |       |
| Contract  volumes (MMBtu):                 |       |                                     |       |
| Floor                                      |       | 730,000                                  |       |
| Ceiling                                    |       | 730,000                                  |       |
| Weighted-average  fixed price per MMBtu(1) |       |                                     |       |
| Floor                                      |       | $                                        | 6.50       |   |
| Ceiling                                    |       | $                                        | 7.50       |   |
| Fixed-price  sales(2)                      |       | $                                        | 7.50       |   |
| Fair  value, net (thousands)(3)            |       | $                                        | 1,707      |   |
| ** **                                 |       |                                     |       |
| **Natural Gas Swaps:**                     |       |                                     |       |
| Contract  volumes (MMBtu)                  |       | 912,500                                  |       |
| Weighted-average  fixed price per MMBtu(1) |       | $                                        | 7.17       |   |
| Fair  value, net (thousands)(3)            |       | $                                        | 2,638      |   |
| ** **                                 |       |                                     |       |
| **Total Natural Gas Contracts:**           |       |                                     |       |
| Contract  volumes (MMBtu)                  |       | 1,642,500                                |       |
| Fixed-price  sales(2)                      |       | $                                        | 7.32       |   |
| Fair  value, net (thousands)(3)            |       | $                                        | 4,345      |   |

 

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

(2) Assumes ceilingprices for natural gas collar volumes.

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

 

***Competition***

 

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

 

In addition tocompetition for leasehold acreage in the Powder River Basin, the oil and gasexploration and production industry is intensely competitive as a whole. Wecompete against well-established companies that have significantly greaterfinancial, marketing, personnel and other resources than we do. Thiscompetition could have a material adverse effect on our ability to execute ourplan and our profitability.

 

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***Seasonal Nature of Business***

 

Generally, but notalways, the demand for natural gas decreases during the summer months andincreases during the winter months. Seasonal anomalies such as mild winters orhot summers sometimes lessen this fluctuation. In addition, certain natural gasusers utilize natural gas storage facilities and purchase some of theiranticipated winter requirements during the summer. This can also lessenseasonal demand fluctuations. Seasonal weather conditions and leasestipulations can limit our drilling and producing activities and other oil andnatural gas operations in certain areas of the Rocky Mountain region. Theseseasonal anomalies can pose challenges for meeting our well drilling objectivesand increase competition for equipment, supplies and personnel during thespring and summer months, which could lead to shortages and increase costs ordelay our operations.

 

**Employeeand Labor Relations**

 

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

 

We depend to a largeextent on the services of certain key management personnel and the loss of anycould have a material adverse effect on our operations. We do not maintainkey-man life insurance with respect to any of our employees, including ourexecutive officers.

 

**Regulations**

 

The natural gas industryis subject to regulation by federal, state and local authorities on matterssuch as employee health and safety, permitting, bonding and licensingrequirements, air quality standards, water pollution, the treatment, storageand disposal of wastes, plant and wildlife protection, storage tanks, thereclamation of properties and plugging of oil wells after gas operations arecompleted, the discharge or release of materials into the environment, and theeffects of gas well operations on groundwater quality and availability and onother resources.

 

In addition, thepossibility exists that new legislation or regulations may be adopted or newinterpretations of existing laws and regulations may be issued that would havea significant impact on our operations or our customers’ ability to use gas andmay require us or our customers to change our or their operations significantlyor incur substantial costs.

 

Climate change regulationis one area of potential future environmental law development. Studies havesuggested that emissions of certain gases, commonly referred to as “greenhousegases,” may be contributing to warming of the Earth’s atmosphere. Methane, aprimary component of natural gas, and carbon dioxide, a byproduct of theburning of natural gas, are examples of greenhouse gases. The U.S. Congress isactively considering legislation to reduce emissions of greenhouse gases fromsources within the U.S. between 2012 and 2050. In addition, at least 17 stateshave developed initiatives to regulate emissions of greenhouse gases, primarilythrough the planned development of greenhouse gas emission inventories and/orregional greenhouse gas cap and trade programs. The Environmental ProtectionAgency, or EPA, is separately considering whether it will regulate greenhousegases as “air pollutants” under the existing federal Clean Air Act. Passage ofclimate control legislation or other regulatory initiatives by Congress orvarious states of the U.S. or the adoption of regulations by the EPA oranalogous state agencies that regulate or restrict emissions of greenhousegases, including methane or carbon dioxide in areas in which we conductbusiness, could result in changes to the consumption and demand for natural gasand could have adverse effects on our business, financial position, results ofoperations and prospects. These changes could increase the costs of ouroperations, including costs to operate and maintain our facilities, install new

 

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emission controls on ourfacilities, acquire allowances to authorize our greenhouse gas emissions, payany taxes related to our greenhouse gas emissions and administer and manage agreenhouse gas emissions program.

 

Failure to comply withthese 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 materialadverse effect on our business. In view of the many uncertainties with respectto current and future laws and regulations, including their applicability tous, we cannot predict the overall effect of such laws and regulations on ourfuture operations.

 

We believe that ouroperations comply in all material respects with applicable laws and regulationsand that the existence and enforcement of such laws and regulations have nomore restrictive effect on our method of operations than on other similarcompanies in the energy industry. We have internal procedures and policies toensure that our operations are conducted in substantial regulatory compliance.

 

***Environmental Regulation of Gas Operations***

 

Numerous governmentalpermits, authorizations and approvals are required for gas operations. In orderto obtain such permits, authorizations and approvals, we are, or may be,required to prepare and present to federal, state or local authorities datapertaining to the effect or impact that any proposed exploration for orproduction of gas or related activities may have upon the environment.Compliance with the terms of such permits, authorizations and approvals and allother requirements imposed by such authorities may be costly and time consumingand may delay or limit commencement or continuation of exploration orproduction operations. Moreover, failure to comply may result in the impositionof significant fines, penalties and injunctions. Future legislation orregulations may increase and/or change the requirements for the protection ofthe environment, health and safety and, as a consequence, our activities may bemore closely regulated. This type of legislation and regulation, as well asfuture interpretations of existing laws, may result in substantial increases inequipment and operating costs to us and delays, interruptions or a terminationof operations, the extent of which cannot be predicted. Further, the impositionof new or revised environmental laws, regulations or requirements could includerestrictions on our ability to conduct certain operations such as hydraulicfracturing or disposal of waste.

 

While it is not possibleto quantify the costs of compliance with all applicable federal, state andlocal environmental laws, those costs have been and are expected to continue tobe significant. We did not make any capital expenditures for environmentalcontrol facilities for the years ended December 31, 2007 or 2008. Anyenvironmental costs are in addition to well closing costs, property restorationcosts and other, significant, non-capital environmental costs, including costsincurred to obtain and maintain permits, gather and submit required data toregulatory authorities, characterize and dispose of wastes and effluents, andmaintain management operational practices with regard to potentialenvironmental liabilities. Compliance with these federal and stateenvironmental laws has substantially increased the cost of gas production, butis, in general, a cost common to all domestic gas producers.

 

The magnitude of theliability and the cost of complying with environmental laws cannot be predictedwith certainty due to the lack of specific environmental, geologic, andhydrogeologic information available with respect to many sites, the potentialfor new or changed laws and regulations, the development of new drilling,remediation, and detection technologies and environmental controls, and theuncertainty regarding the timing of work with respect to particular sites. As aresult, we may incur material liabilities or costs related to environmentalmatters in the future and such environmental liabilities or costs couldadversely affect our results and financial condition. In addition, there can beno assurance that changes in laws or regulations would not affect the manner inwhich we are required to conduct our operations. Further, given the retroactivenature of certain environmental laws, we have incurred, and may in the futureincur, liabilities associated with: the investigation and remediation of therelease of hazardous substances, oil, natural gas, other petroleum products orother substances; environmental conditions; and damage to natural resourcesarising from properties and facilities currently or previously owned oroperated as well as sites owned by third parties to which we sent wastematerials for disposal.

 

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We may be subject tovarious generally applicable federal environmental and related laws, includingthe following:

 

·the Clean Air Act;

·the Federal Water Pollution ControlAct/Clean Water Act;

·the National Environmental Policy Act;

·the Federal Land Policy and ManagementAct;

·the Safe Drinking Water Act;

·the Toxic Substances Control Act;

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

·the Solid Waste Disposal Act/ResourceConservation and Recovery Act;

·the Emergency Planning and CommunityRight to Know Act; and

·the Endangered Species Act;

 

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

 

Regulatory requirementsnot directly applicable to us, but governing the ability of federal, state, orlocal governments to issue approvals, permits, or authorizations, or to takeother actions, may also affect our operations. Such requirements include,without limitation, the National Environmental Policy Act and similar statestatutory or regulatory requirements.

 

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

 

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

 

Common law theories ofrecovery may apply to operations where the presence, release, storage,transportation or use of natural gas or production waste is alleged to causepersonal injury, illness or property damage as a result. The theories ofnegligence, 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, suchcommon law claims by third parties are not preempted by federal or stateenvironmental laws, rules or regulations and may be used by plaintiffs instate law claims or as supplemental jurisdiction claims in conjunction withfederal or state statutory environmental litigation.

 

In addition, state lawsoften require some form of remedial action such as closure of inactive pits andplugging of abandoned wells to prevent pollution from former or suspendedoperations. Legislation has been proposed and continues to be evaluated inCongress from time to time that would reclassify certain natural gas and oilexploration and production wastes as “hazardous wastes.” This reclassificationwould make such wastes subject to much more stringent and expensive storage,treatment, disposal and clean up requirements. If such legislation were to beenacted, it could have a significant adverse impact on our operating costs, aswell as the natural gas and oil industry 

 

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in general. Initiativesto regulate further the disposal of natural gas and oil wastes are alsoproposed in certain states from time to time and may include initiatives atcounty, municipal and local government levels. These various initiatives couldhave a similar adverse impact on us.

 

From time to time, wehave been the subject of investigations, administrative proceedings andlitigation by government agencies and third parties relating to environmentalmatters. We may become involved in future proceedings, litigation orinvestigations and incur liabilities that could be materially adverse to us.

 

***Federal Regulation of the Sale and Transportation of Gas***

 

Various aspects of ouroperations are regulated by agencies of the federal government. The FederalEnergy Regulatory Commission, or FERC, regulates the transportation and sale ofnatural gas in interstate commerce pursuant to the Natural Gas Act of 1938 andthe Natural Gas Policy Act of 1978. In the past, the federal government hasregulated the prices at which gas could be sold. While “first sales” byproducers of natural gas, and all sales of condensate and natural gas liquids,can be made currently at uncontrolled market prices, Congress could reenactprice controls in the future. Deregulation of wellhead sales in the natural gasindustry began with the enactment of the Natural Gas Policy Act in 1978. In1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removedall Natural Gas Act and Natural Gas Policy Act price and non-price controlsaffecting wellhead sales of natural gas effective January 1, 1993.

 

We own certain naturalgas in-field low-pressure pipelines that we believe meet the traditional testswhich FERC has used to establish a pipeline’s status as a gatherer undersection 1(b) of the Natural Gas Act, 16 U.S.C. § 717(b) andare therefore not subject to FERC jurisdiction.

 

Additional proposals andproceedings that might affect the gas industry are pending before Congress,FERC, the Minerals Management Service, state commissions and the courts. Wecannot predict when or whether any such proposals may become effective. In thepast, the natural gas industry has been heavily regulated. There is noassurance that the regulatory approach currently pursued by various agencieswill continue indefinitely. Notwithstanding the foregoing, we do not anticipatethat compliance with existing federal, state and local laws, rules andregulations will have a material or significantly adverse effect upon ourcapital expenditures, earnings or competitive position. No material portion ofour business is subject to renegotiation of profits or termination of contractsor subcontracts at the election of the federal government.

 

Beginning in 1992, FERCissued a series of orders (“Order No. 636”) which required interstatenatural gas pipelines to provide transportation service separate or unbundledfrom the pipeline’s sales of gas. In addition, Order No. 636 requiredinterstate natural gas pipelines to provide open access transportation on anon-discriminatory basis that treats similarly situated shippers equally. Thecourts affirmed the significant features of Order No. 636 and numerousrelated orders pertaining to the individual pipelines, and FERC has sincereviewed and modified its open access regulations. In particular, FERC hasreviewed its transportation regulations, including how they operate inconjunction 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 competitiveauctions, and whether changes to its long-term transportation policies may alsobe appropriate to avoid a market bias toward short-term contracts. In February 2000,FERC issued Order No. 637 amending certain regulations governinginterstate natural gas pipeline companies in response to the development ofmore competitive markets for natural gas and natural gas transportation. Thegoal of Order No. 637 is to “fine tune” the open access regulationsimplemented by Order No. 636 to accommodate subsequent changes in the market.Key provisions of Order No. 637 include:

 

(1)   waivingthe 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)   permittingvalue oriented peak/off peak rates to better allocate revenue responsibilitybetween short-term and long-term markets;

 

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(3)   permittingterm differentiated rates, in order to better allocate risks between shippersand the pipeline;

 

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

 

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

 

(6)   adoptingnew web site reporting requirements that include daily transactional data onall firm and interruptible contracts and daily reporting of scheduledquantities at points or segments.

 

The new reportingrequirements became effective on September 1, 2000. FERC has also issuednumerous orders confirming the sale and abandonment of natural gas gatheringfacilities previously owned by interstate pipelines and acknowledging that ifFERC does not have jurisdiction over services provided by these facilities,then such facilities and services may be subject to regulation by stateauthorities in accordance with state law. A number of states have eitherenacted new laws or are considering the adequacy of existing laws affectinggathering rates and/or services. Other state regulation of gathering facilitiesgenerally includes various safety, environmental, and in some circumstances,nondiscriminatory take requirements, but does not generally entail rateregulation. Thus, natural gas gathering may receive greater regulatory scrutinyof state agencies in the future. Our low-pressure gathering operations could beadversely affected should they be subject in the future to increased stateregulation of rates or services. In addition, FERC’s approval of transfers ofpreviously regulated gathering systems to independent or pipeline affiliatedgathering companies that are not subject to FERC regulation may affectcompetition for gathering or natural gas marketing services in areas served bythose systems and thus may affect both the costs and the nature of gatheringservices that will be available to interested producers or shippers in thefuture.

 

***State Regulation of Gas Operations***

 

Our operations are alsosubject to regulation at the state and, in some cases, the county, municipaland local governmental levels. Such regulations include requiring permits forthe construction, drilling and operation of wells, maintaining bondingrequirements in order to drill or operate wells, regulating the surface use andrequiring the restoration of properties upon which wells are drilled, requiringthe proper plugging and abandonment of wells, and regulating the disposal offluids used and produced in connection with operations. Our operations are alsosubject to various state conservation laws and regulations. These includeregulations that may affect the size of drilling and spacing units or prorationunits, the density of wells which may be drilled, and the mandatory unitizationor pooling of gas properties. In addition, state conservation regulations mayestablish the allowable rates of production from gas wells, may prohibit orregulate the venting or flaring of gas, and may impose certain requirementsregarding the ratability of gas production. State regulation of gatheringfacilities generally includes various safety, environmental and, in somecircumstances, nondiscriminatory and nonpreferential purchase and/ortransportation requirements, but does not generally entail rate regulation.These regulatory burdens may affect profitability, and we are unable to predictthe 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. federalland. Federal leases in Montana and Wyoming must be developed pursuant to theU.S. BLM’s Resource Management Plans. Federal leases are also subject to theNational Environmental Policy Act and Federal Land Policy Management Act. TheNational Environmental Policy Act process imposes obligations on the federalgovernment that may result in legal challenges and potentially lengthy delaysin obtaining project permits or approvals. The Montana and WyomingBLMs have been subject to several lawsuits from various environmental andtribal groups challenging Resource Management Plan amendments and supportingEnvironmental Impact Statements addressing CBM development in Montana andWyoming. In 2003, the Montana BLM and Wyoming BLM each amended their ResourceManagement Plans based in part on Environmental Impact Statements prepared

 

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pursuant to the NationalEnvironmental Policy Act. Shortly after the issuance of the EnvironmentalImpact Statements and amended Resource Management Plans, various plaintiffsbrought legal actions challenging the Montana and Wyoming Environmental ImpactStatements and Resource Management Plans. There have been at least five federaldistrict court challenges to the Montana Environmental Impact Statements. Thereare also at least three federal district court challenges to the WyomingEnvironmental Impact Statements currently pending before the United StatesDistrict Court for the District of Wyoming.

 

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

 

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

 

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

 

In addition to federalregulation, our federal leases are subject to certain state regulations whichrequire governmental agencies to evaluate the potential environmental impact ofa proposed project on government owned lands.

 

We have dedicatedsignificant resources to managing regulatory and permitting matters to achieveefficient processing of federal permits and resource management plans. Webelieve we are making significant progress in resolving the outstandingregulatory and environmental issues in Montana and Wyoming.

 

***Employee Health and Safety***

 

We are subject to therequirements of the Occupational Safety and Health Act, or OSHA, and comparablestate laws that regulate the protection of the health and safety of workers. Inaddition, the OSHA hazard communication standard requires that information bemaintained about hazardous materials used or produced in operations and thatthis information be provided to employees, state and local governmentauthorities and citizens. We believe that our operations are in substantialcompliance with the OSHA requirements and general industry standards regardingrecordkeeping requirements and the monitoring of occupational exposure toregulated substances.

 

**ITEM1A    *RISK FACTORS***

 

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

 

**RisksRelated to Our Business**

 

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

 

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The continued creditcrisis and the related turmoil in the global financial system have had anadverse impact on our business and financial condition, and we may face majorchallenges if conditions in the financial markets do not improve. Currently, weare not able to borrow additional amounts under our credit facility. As aresult, we curtailed substantially all new drilling in the fourth quarter of2008, and if our operating cash flow is not sufficient to carry out ourdrilling plans for 2009, we will be required to reduce the number of wells wedrill or seek alternative sources of financing. However, due to the financialcrisis, financing through the capital markets or otherwise may not be availableto us on acceptable terms or at all. If additional funding is not available, oris available only on unfavorable terms, we may be unable to implement ourdrilling plans, make capital expenditures, withstand a further downturn in ourbusiness or the economy in general, or take advantage of business opportunitiesthat may arise. Any further curtailment of our operations would have anadditional adverse effect on our revenues and results of operations. Inaddition, current economic conditions have led to reduced demand for, and lowerprices of, oil and natural gas, and a sustained decline in the price of naturalgas would adversely affect our business, results of operations and financialcondition. Please read “The volatility of natural gas and oil prices could havea material adverse effect on our business” below. Further, the economicsituation could have an impact on our lenders or customers, causing them tofail to meet their obligations to us, and on the liquidity of our operatingpartners, resulting in delays in operations or their failure to make requiredpayments. Also, market conditions could have an impact on our natural gas andoil derivatives transactions if our counterparties are unable to perform theirobligations or seek bankruptcy protection.

 

***Our credit facility has substantial restrictions andfinancial covenants that may affect our ability to successfully operate ourbusiness. In addition, we may have difficulty returning to compliance withcertain financial covenants.***

 

Our credit facility imposescertain operational and financial restrictions on us. These restrictions, amongother things, limit our ability to:

 

·incur additional indebtedness;

·create liens;

·sell our assets or consolidate or mergewith or into other companies;

·make investments and other restrictedpayments, including dividends; and

·engage in transactions with affiliates.

 

These limitations aresubject to a number of important qualifications and exceptions. In addition,our credit facility requires us to maintain certain financial ratios and tosatisfy certain financial conditions which may require us to reduce our debt orto take some other action in order to comply with them. These restrictions inour credit facility could also limit our ability to obtain future financings, makeneeded capital expenditures, withstand a downturn in our business or theeconomy in general, or otherwise conduct necessary corporate activities. Wealso may be prevented from taking advantage of business opportunities thatarise because of the limitations imposed on us by the restrictive covenantsunder our credit facility.

 

We are not in compliancewith the current ratio financial covenant and certain other covenants relatedto 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 baseredetermination expected in the fall of 2009. We have also not been incompliance with certain financial covenants for the last four quarters,including the first quarter of 2009, but obtained waivers and/or amendments ineach instance. As a result of such non-compliance, we are unable to borrowadditional funds under our credit agreement. We believe that we may not be incompliance with certain restrictive covenants throughout 2009, but will seekadditional waivers. There can be no assurance that we will be able to obtainsuch waivers or that such waivers will be obtained on acceptable terms. If weare unable to obtain future waivers and/or to comply with the restrictivecovenants, the lenders could accelerate our indebtedness or foreclose onproperties held by liens. In addition, due to borrowing base limitations, weare currently unable to borrow additional funds under the credit facility. Inconnection with the waiver of the restrictive covenants, the lenders reducedour borrowing base to $9.0 million, with further monthly reductions untilthe borrowing base reaches $6.5 million on October 1, 2009. Ifnatural gas prices do not improve, we expect that our borrowing base could befurther reduced in the future.

 

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Please see Item 7, “Management’sDiscussion and Analysis of Financial Condition and Results ofOperations—Liquidity and Capital Resources—Credit Facility,” for a discussionof our credit facility.

 

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

 

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

 

·the level of production from existingwells;

·prices of natural gas and oil;

·our results in locating and producing newreserves;

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

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

 

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

 

If our revenues decreasedue 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 ourreserves or maintain production levels could be greatly limited.

 

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

 

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

 

·the domestic and foreign supply ofnatural gas and oil;

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

·overall domestic and global economic andpolitical conditions;

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

·the availability of transportationsystems with adequate capacity;

·price and availability of alternativefuels;

·weather conditions and fluctuatingseasonal demand;

·natural disasters;

·acts of terrorism;

 

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·political stability in the Middle Eastand elsewhere;

·domestic and foreign governmentalregulations, including conservation efforts and taxation;

·the price and quantity of foreignimports; and

·the price and availability of alternativefuels.

 

In the past, natural gasprices have been extremely volatile, and we expect this volatility to continue.During the year ended December 31, 2007, the NYMEX natural gas index priceranged from a high of $8.64 per MMBtu to a low of $5.38 per MMBtu, while theCIG 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, theNYMEX natural gas index price ranged from a high of $13.58 per MMBtu to a lowof $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 downwardpressure on prices caused by reduced domestic demand, some analysts expectnear-term domestic gas prices to fall further due to additional gas suppliesfrom lower-cost resource plays, including shale, that use new exploration andproduction technologies and from foreign gas imports through existing and newnatural gas liquefaction capacity.

 

A sharp decline innatural gas prices would result in a commensurate reduction in our revenues,income and cash flows from the production of natural gas and could have amaterial adverse effect on our borrowing base and proved reserves. In the eventprices fall substantially, we may not be able to realize a profit from ourproduction and would operate at a loss, and even relatively modest drops inprices 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 thebeginning of the fourth quarter, we curtailed substantially all new drillingfor the fourth quarter of 2008 and have shut-in a number of wells that are noteconomic at current natural gas price levels.

 

Lower natural gas pricesmay not only decrease our revenues on a per unit basis, but also may reduce theamount of natural gas that we can produce economically. This may result in ourhaving to make substantial downward adjustments to our estimated provedreserves. 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, 2008would decrease from $32.8 million to $31.7 million.

 

***Low natural gas prices may result in impairments of our oiland gas properties.***

 

Accounting rules mayrequire us to write down, as a non-cash charge to earnings, the carrying valueof our properties for impairments. As such, we may incur impairment charges inthe future, which could have a material adverse effect on our results ofoperations in the period such impairment charges are taken. We reportedimpairments of our oil and gas properties of approximately $21.5 millionand $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 atotal impairment of approximately $46.7 million at December 31, 2008.A further decline in gas prices or an increase in operating costs subsequent tothe measurement date or reductions in the economically recoverable quantitiescould result in the recognition of additional impairments of our gas propertiesin future periods.

 

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

 

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

 

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** **

**Ourestimated reserves are based on many assumptions, some of which may prove to beinaccurate. Any material inaccuracies in our reserve estimates or underlying assumptionswill materially affect the quantities and present value of our reserves.**

 

This annual reportcontains estimates of natural gas reserves, and the future net cash flowsattributable to those reserves, prepared by Netherland, Sewell &Associates, Inc., our independent petroleum and geological engineers.There are numerous uncertainties inherent in estimating quantities of provedreserves and cash flows from such reserves, including factors beyond our andNetherland, Sewell & Associates, Inc.’s control. Reserveengineering is a subjective process of estimating underground accumulations ofnatural gas and oil that cannot be measured in an exact manner. The accuracy ofan estimate of quantities of reserves, or of cash flows attributable to thosereserves, is a function of: (1) the available data; (2) the accuracyof assumptions regarding future natural gas and oil prices and futuredevelopment and exploitation costs and activities; and (3) engineering andgeological interpretation and judgment. Reserves and future cash flows may besubject to material downward or upward revisions based upon production history,development and exploitation activities and natural gas and oil prices. Actualfuture production, revenue, taxes, development expenditures, operatingexpenses, quantities of recoverable reserves and value of cash flows from thosereserves may vary significantly from the assumptions and estimates in thisreport. Any significant variance between these assumptions and actual figurescould greatly affect our estimates of reserves, the economically recoverablequantities of natural gas attributable to any particular group of properties,the classification of reserves based on risk of recovery, and estimates offuture net cash flows. In addition, reserve engineers may make differentestimates of reserves and cash flows based on the same available data. Theestimated quantities of proved reserves and the discounted present value offuture net cash flows attributable to those reserves included in this annual reportwere prepared by Netherland, Sewell & Associates, Inc. inaccordance with the rules of the Securities and Exchange Commission, orSEC, and are not intended to represent the fair market value of such reserves.

 

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

 

·geological conditions;

·changes in governmental regulations andtaxation;

·assumptions governing future prices;

·the amount and timing of actualproduction;

·future operating costs; and

·the capital costs of drilling new wells.

 

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

*** ***

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

 

The rate of productionfrom natural gas and oil properties declines as reserves are depleted. As aresult, we must locate, acquire and develop new natural gas and oil reserves toreplace those being depleted by production. We must do this even during periodsof low natural gas and oil prices when it is difficult to raise the capitalnecessary to finance activities. Our future natural gas reserves and productionand, therefore, our cash flow and income, are highly dependent on our successin efficiently developing and exploiting our current reserves and economicallyfinding or acquiring additional recoverable reserves. We may not be able tofind or acquire and develop additional reserves at an acceptable cost or havenecessary financing for these activities in the future.

 

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

 

The business of exploringfor, developing and operating natural gas and oil properties involves a highdegree of business and financial risks, and thus a substantial risk ofinvestment loss that even a combination of experience, knowledge and carefulevaluation may not be able to overcome. The cost of drilling, completing andoperating wells is often uncertain, and a number of factors can delay orprevent drilling operations or production, including:

 

·unexpected or adverse drillingconditions;

·elevated pressure or irregularities ingeologic 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 drillingrigs, other field services, equipment and labor; and

·limitations in the market for oil andgas.

 

A productive well maybecome uneconomic in the event that unusual quantities of water or otherdeleterious substances are encountered, which impair or prevent the productionof natural gas and/or oil from the well. In addition, production from any wellmay be unmarketable if it is contaminated with unusual quantities of water orother deleterious substances. We may drill wells that are unproductive or,although productive, do not produce natural gas and/or oil in economicquantities. Unsuccessful drilling activities could result in higher costswithout any corresponding revenues. Furthermore, a successful completion of awell does not ensure a profitable return on the investment.

*** ***

***We may not adhere to our proposed drilling schedule.***

 

Our final determinationof whether to drill any scheduled or budgeted wells will be dependent on anumber of factors, including:

 

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

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

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

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

·the availability of leases and permits onreasonable terms for the prospects.

 

***We must obtain governmental permits and approvals fordrilling operations, which can result in delays in our operations, be a costlyand time consuming process, and result in restrictions on our operations.***

 

Regulatory authoritiesexercise considerable discretion in the timing and scope of permit issuances inthe Rocky Mountain region. Compliance with the requirements imposed by theseauthorities can be costly and time consuming and may result in delays in thecommencement or continuation of our exploration or production operations and/orfines. For example, in the ordinary course of our business, we have receivednotices of violation or orders to cease production with respect to certain ofour wells that have resulted in production delays and/or fines. Similarregulatory or legal actions in the future may materially interfere with ouroperations or otherwise have a material adverse effect on us. In addition, weare often required to prepare and present to federal, state or localauthorities data pertaining to the effect or impact that a proposed project mayhave on the environment, threatened and endangered species, and cultural andarchaeological artifacts. Further, the public may comment on and otherwiseengage 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 involverequirements that restrict our ability to conduct our operations or to do soprofitability. For example, in December 2007, the U.S. BLM imposed apermitting application fee of $4,000 per well drilled on federal lands. Thisfee increased our regulatory costs in 2008 by an additional $1.0 millionand affected the timing of our development of federal leases.

 

***Our natural gas sales are dependent on two customers and theloss of these customers or their inability to pay for our gas would adverselyaffect our ability to market our gas.***

 

We market substantiallyall 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 gassold, respectively. In the event that Enserco Energy or United Energy Tradingexperienced financial difficulties or no longer purchased our natural gas, wecould, 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 theRocky Mountain region.***

 

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

*** ***

***The majority of our properties are located in a five-countyregion in the northern end of the Powder River Basin in northeastern Wyomingand southern Montana, making us vulnerable to risks associated with having ourproduction concentrated in one area.***

 

The majority of ourproperties are geographically concentrated in a five-county region in thenorthern end of the Powder River Basin in northeastern Wyoming and southernMontana. As a result of this concentration, we may be disproportionatelyexposed to the impact of delays or interruptions of production from theseproperties caused by significant governmental regulation, transportationcapacity constraints, curtailment of production, natural disasters, adverseweather conditions or other events which impact this area.

*** ***

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

 

Our operations aresubject to hazards and risks inherent in producing and transporting natural gasand oil, such as fires, natural disasters, explosions, pipeline ruptures,spills and acts of terrorism, all of which can result in the loss ofhydrocarbons, environmental pollution, personal injury claims and other damageto our and others’ properties. As protection against operating hazards, wemaintain insurance coverage against some, but not all, potential losses. Inaddition, pollution and environmental risks generally are not fully insurable.As a result of market conditions, existing insurance policies may not berenewed and other desirable insurance may not be available on commercially reasonableterms, if at all. The occurrence of an event that is not covered, or not fullycovered, 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 financiallosses or reduce our income.***

 

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

 

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may limit the benefits wewould otherwise receive from increases in prices for natural gas. Please seeItem 7, Management’s Discussion and Analysis of Financial Condition andResults of Operations, Item 7A, Quantitative and Qualitative DisclosuresAbout Market Risk—Commodity Price Risk and Items 1 and 2, Businessand Properties—Operations—Hedging Activities.

*** ***

***Our business depends on gathering and transportationfacilities owned by others. Any limitation in the availability of thosefacilities would interfere with our ability to market the natural gas weproduce.***

 

The marketability of ournatural gas production depends in part on the availability, proximity andcapacity of gathering and pipeline systems owned by third parties. The amountof natural gas that can be produced and sold is subject to curtailment incertain circumstances, such as pipeline interruptions due to scheduled andunscheduled maintenance, excessive pressure, physical damage to the gatheringor transportation system, or lack of contracted capacity on such systems. Thecurtailments arising from these and similar circumstances may last from a fewdays to several months. In many cases, we are provided only with limited, ifany, notice as to when these circumstances will arise and their duration. Forexample, although volumes increased in 2008 overall, our volumes were reducedby approximately 1.3 MMcf per day from September 1, 2008 through December 31,2008 due to low natural gas pricing, weather interruptions and pipeline flowinterruptions due to hydrostatic testing.

 

In addition, some of ourwells are drilled in locations that are not serviced by gathering andtransportation pipelines, or the gathering and transportation pipelines in thearea 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 thesewells until the necessary gathering and transportation systems are constructed.Any significant curtailment in gathering system or pipeline capacity, orsignificant delay in the construction of necessary gathering and transportationfacilities, would have an adverse effect on our business.

 

***Shortages of drilling rigs and equipment and experiencedpersonnel could delay our operations.***

 

Higher natural gas pricesgenerally increase the demand for drilling rigs and equipment, field servicesand personnel with drilling or other oil and gas operational experience, andcan lead to shortages of, and increasing costs or wages for, such equipment,services and personnel. Shortages of, or increasing costs for, experiencedoperational personnel and oil field equipment and services could restrict ourability to drill the wells and conduct the operations which we currently haveplanned. Any delay in the drilling of new wells or significant increase inwages or drilling or other operational costs could reduce our revenues.

*** ***

***We may incur losses as a result of title deficiencies in theproperties in which we invest.***

 

It is our practice inacquiring natural gas and oil leases or interests not to incur the expense ofretaining lawyers to examine the title to the mineral interest. Rather, we relyupon the judgment of natural gas and oil lease brokers or landmen who performthe fieldwork in examining records in the appropriate governmental officebefore attempting to acquire a lease in a specific mineral interest.

 

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

 

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***We may incur losses in our acreage position due to theexpiration of leases.***

 

Our leasehold position issubject to leases with terms which expire from 2009 to 2018. Our leases may notbe held by production and may consequently expire if we are unable to developthem in a timely manner. In addition, leases held by production which aresubsequently shut-in due to low natural gas prices may also expire if we areunable to make shut-in payments.

*** ***

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

 

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

 

Our operations couldresult in liability for personal injuries, property damage, discharge ofhazardous materials, remediation and clean up costs and other environmentaldamages. We could also be liable for environmental damages caused by previousproperty owners. As a result, substantial liabilities to third parties orgovernmental entities may be incurred which could have a material adverseeffect on our financial condition and results of operations. We maintaininsurance coverage for our operations, but we do not believe that insurancecoverage for environmental damages that occur over time, or complete coveragefor sudden and accidental environmental damages, is available at a reasonablecost. Accordingly, we may be subject to liability or may lose the right tocontinue exploration or production activities upon substantial portions of ourproperties if certain environmental damages occur.

*** ***

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

 

Numerous departments andagencies, both federal and state, are authorized by statute to issue and haveissued rules and regulations binding on the natural gas and oil industryand its individual members, some of which carry substantial penalties forfailure to comply. We may be required to make large expenditures to comply withthese regulatory requirements. Any increases in the regulatory burden on thenatural gas and oil industry created by new legislation would increase our costof doing business and could result in delays in our operations, andconsequently, adversely affect our profitability. For example, in December 2007the U.S. BLM imposed a permitting application fee of $4,000 per well drilled onfederal 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 totime we may be subject to legal proceedings and claims as a result of theseregulations. Please see Item 3, Legal Proceedings, for a description ofmaterial pending litigation.

 

***We operate in a highly competitive environment and ourcompetitors may have greater resources than us.***

 

The natural gas and oilindustry is intensely competitive and we compete with other companies, many ofwhich are larger and have greater financial, technological, human and otherresources. Many of these companies not only explore for and produce crude oiland natural gas but also carry on refining operations and market petroleum andother products on a regional, national or worldwide basis. Such companies maybe able to pay more for productive natural gas and oil properties andexploratory prospects or define, evaluate, bid for and purchase a greaternumber of 

 

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properties and prospectsthan our financial or human resources permit. In addition, such companies mayhave a greater ability to continue exploration activities during periods of lowoil and gas market prices. Our ability to acquire additional properties and todiscover reserves in the future will be dependent upon our ability to evaluateand select suitable properties and to consummate transactions in a highlycompetitive environment. If we are unable to compete, our operating results andfinancial position may be adversely affected.

 

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

 

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

 

·we cannot obtain future permits fromapplicable regulatory agencies;

·water of lesser quality is produced;

·our wells produce excess water; or

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

 

Our ability to remove anddispose of sufficient quantities of water from a coal seam will determinewhether or not we can produce gas in commercial quantities from that seam. Thecost of water disposal may affect our profitability.

*** ***

***Our coalbed methane wells typically have a shorter reservelife and lower rates of production than conventional natural gas wells, whichmay adversely affect our profitability during periods of low natural gasprices.***

 

The shallow coals fromwhich we produce natural gas in the Powder River Basin typically have a sevento eight year reserve life and have lower total reserves and produce at lowerrates than most conventional natural gas wells. We depend on drilling a largenumber of wells each year to replace production and reserves in the PowderRiver Basin and to distribute operational expenses over a larger number ofwells. A decline in natural gas prices could make certain wells uneconomicalbecause production rates are lower on an individual well basis and may beinsufficient to cover operational costs.

*** ***

***We may have difficulty managing growth in our business.***

 

Because of our smallsize, growth in accordance with our business plan, if achieved, will place asignificant strain on our financial, technical, operational and managementresources. If we expand our activities and increase the number of projects weare evaluating or in which we participate, there will be additional demands onour financial, technical and management resources. The failure to continue toupgrade our technical, administrative, operating and financial control systemsor the occurrence of unexpected expansion difficulties, including the failureto recruit and retain experienced managers, geoscientists and engineers, couldhave a material adverse effect on our business, financial condition and resultsof operations and our ability to timely execute our business plan.

 

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

 

The success of ouroperations and activities is dependent to a significant extent on the effortsand abilities of our management. The loss of services of any of our keymanagers could have a material adverse effect on our business. We have notobtained “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. Theloss of the services of either of these individuals, or other key personnel, 

 

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may adversely affect ourbusiness and prospects. We currently do not have employment agreements ornon-competition agreements with any of the members of our management other thanMr. Schoonmaker and Mr. Barnes.

*** ***

***Some of our directors may have conflicts of interest becausethey are also currently affiliates, directors or officers of entities that makeinvestments in the energy sector and/or may compete with us. The resolution ofthese conflicts of interest may not be in our or our stockholders’ bestinterests.***

 

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

*** ***

***Our failure to complete and integrate future acquisitionssuccessfully could reduce our earnings and slow our growth.***

 

We may be unable toidentify potential acquisitions or to make acquisitions on terms that weconsider economically acceptable. Furthermore, there is intense competition foracquisition opportunities in our industry. Competition for acquisitions mayincrease the cost of, or cause us to refrain from, completing acquisitions. Ourstrategy of completing acquisitions is dependent upon, among other things, ourability to obtain debt and equity financing and, in some cases, regulatoryapprovals. Our ability to pursue our growth strategy may be hindered if we arenot able to obtain such financing or regulatory approvals. The inability toeffectively manage the integration of acquisitions could reduce our focus onsubsequent acquisitions and current operations, which, in turn, couldnegatively impact our earnings and growth. Our financial position and resultsof operations may fluctuate significantly from period to period, based onwhether or not significant acquisitions are completed in particular periods.

*** ***

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

 

Properties we acquire maynot produce as expected, may be in an unexpected condition and may subject usto increased costs and liabilities, including environmental liabilities.Although we review acquired properties prior to acquisition in a mannerconsistent with industry practices, even a detailed review of records andproperties may not necessarily reveal existing or potential problems or permitus to become sufficiently familiar with the properties to assess fully theircondition, any deficiencies, and development potential. Generally, it is notfeasible to review in depth every individual property involved in eachacquisition. Ordinarily, we will focus our review efforts on the higher valueproperties or properties with known adverse conditions and will sample theremainder. In addition, environmental problems, such as ground watercontamination, are not necessarily observable even when an inspection isundertaken.

*** ***

***The coal beds from which we produce may be drained byoffsetting production wells.***

 

Our drilling locationsare spaced primarily using 80-acre spacing. Producing wells located on the80-acre spacing units contiguous with our drilling locations may drain theacreage underlying our wells. If a substantial number of productive wells aredrilled on spacing units adjacent to our properties, it could have an adverseimpact on the economically recoverable reserves of our properties that aresusceptible to such drainage.

 

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***We may not be able to keep pace with technologicaldevelopments in our industry.***

 

The natural gas and oilindustry is characterized by rapid and significant technological advancementsand introductions of new products and services using new technologies. Asothers use or develop new technologies, we may be placed at a competitivedisadvantage, and competitive pressures may force us to implement those newtechnologies at substantial cost. In addition, other natural gas and oilcompanies may have greater financial, technical and personnel resources thatallow them to enjoy technological advantages and may in the future allow themto implement new technologies before we can. We may not be able to respond tothese competitive pressures and implement new technologies on a timely basis orat an acceptable cost. If one or more of the technologies we use now or in thefuture were to become obsolete or if we are unable to use the most advancedcommercially available technology, our business, financial condition andresults of operations could be materially adversely affected.

 

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

 

The Sarbanes-Oxley Act of2002, or the Act, which became law in July 2002, has required changes inthe corporate governance, securities disclosure and compliance practices ofpublic companies. The SEC has promulgated rules pursuant to the Act coveringa variety of subjects, including corporate governance guidelines. Compliancewith these rules has significantly increased our legal, financial andaccounting costs. In addition, compliance with these rules has requiredthe dedication of a significant amount of the time of management and the boardof directors and may make it more difficult for us to attract and retainqualified directors, particularly independent directors, or qualified executiveofficers. Because we are a small company with relatively few employees, we havebeen disproportionately negatively impacted by these rules andregulations.

 

As directed by Section 404of the Act, the SEC adopted rules requiring public companies to include areport of management on the company’s internal control over financial reportingin their annual reports on Form 10-K that contains an assessment bymanagement of the effectiveness of the company’s internal control overfinancial reporting. In addition, the public accounting firm auditing thecompany’s financial statements must attest to and report on management’sassessment of the effectiveness of the company’s internal control overfinancial reporting. The requirement to include management’s report firstapplies to this annual report. Our accounting firm will first be required toattest to and report on management’s assessment in the annual report for theyear ended December 31, 2009. If management is unable to conclude that wehave effective internal control over financial reporting, or if our independentauditors are unable to provide us, when required, with an unqualified report asto 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 companywith limited resources. The number and qualifications of our finance andaccounting staff are limited, and we have limited monetary resources. Weexperience difficulties in attracting qualified staff with requisite expertisedue to our profile and a generally tight market for staff with expertise inthese areas. We retained a consultant to assist us in the process of testingand evaluating our internal control over financial reporting. A key risk isthat management will not timely remediate any deficiencies that may beidentified as part of the review process.

** **

**RisksRelated to our Relationship with DLJ Merchant Banking and Other InitialStockholders**

*** ***

***Our founding stockholders have substantial influence overthe outcome of certain stockholder votes and may exercise this voting power ina manner adverse to our other stockholders.***

 

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

 

In addition, Carrizobeneficially owns approximately 8.3% of our outstanding common stock. Thisownership, when combined with that of DLJ Merchant Banking, constitutesslightly less than a majority of our common stock 

 

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and could have the effectof delaying or preventing a change in control of or otherwise discouraging apotential acquirer from attempting to obtain control of us. In addition, theinterests of these stockholders may differ from those of our otherstockholders, and these stockholders may vote their common stock in a mannerthat may adversely affect our other stockholders.

** **

**RisksRelating to Our Common Stock**

 

***The price of our common stock may be volatile and you maynot be able to resell your shares at a favorable price.***

 

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

*** ***

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

 

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

*** ***

***We may not be able to maintain compliance with NASDAQ’scontinued listing requirements.***

 

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

 

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

 

The delisting of our commonstock would adversely affect the market liquidity for our common stock, the pershare price of our common stock and impair our ability to raise capital thatmay be needed for future operations. Delisting from NASDAQ could also haveother negative results, including the potential loss of confidence by customersand employees, the loss of institutional investor interest and fewer businessdevelopment opportunities. In addition, we would be subject to a number ofrestrictions regarding the registration and qualification of our common stockunder federal and state securities laws.

 

If our common stock isnot eligible for quotation on another market or exchange, trading of our commonstock could be conducted in the over-the-counter market or on an electronic bulletinboard established for unlisted securities such as the Pink Sheets or the OTCBulletin Board. In such event, it could become more difficult to dispose of, orobtain accurate quotations for the price of our common stock, and there wouldlikely also be a 

 

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reduction in our coverageby security analysts and the news media, which could cause the price of our commonstock to decline further.

 

If our stock price tradesbelow $1.00 for a sustained period and we face delisting on the NASDAQ, we mayseek to implement a reverse stock split. However, reverse stock splitsfrequently result in a loss in stockholder value as the actual post-split priceis often lower than the pre-split price, adjusted for the split. Accordingly, areverse stock split may not solve the listing requirement deficiency even ifimplemented.

*** ***

***The percentage ownership evidenced by the common stock issubject to dilution.***

 

We are authorized toissue up to 100,000,000 shares of common stock and are not prohibited fromissuing additional shares of such common stock. You do not have statutory “preemptiverights” and therefore are not entitled to maintain a proportionate share ofownership by buying additional shares of any new issuance of common stockbefore others are given the opportunity to purchase the same. Accordingly, yourpercentage ownership, as a holder of the common stock, will be subject tochange as a result of the sale of any additional common stock or other equityinterests in us.

*** ***

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

 

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

 

·authorize the issuance of blank checkpreferred stock that could be issued by our board of directors to thwart atakeover attempt;

·classify the board of directors intostaggered, three-year terms, which may lengthen the time required to gaincontrol of our board of directors;

·prohibit cumulative voting in theelection of directors, which would otherwise allow holders of less than amajority of stock to elect some directors;

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

·require super-majority voting by ourstockholders to effect any stockholder-initiated amendment to any provision ofour bylaws;

·limit who may call special meetings ofour stockholders;

·prohibit stockholder action by writtenconsent, thereby requiring all actions to be taken at a meeting of thestockholders;

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

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

 

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

*** ***

***Because we have no plans to pay dividends on our commonstock, investors must look solely to stock appreciation for a return on theirinvestment in us.***

 

We do not anticipatepaying any cash dividends on our common stock in the foreseeable future. Wecurrently intend to retain all future earnings to fund the development andgrowth of our business. Any payment of future dividends will be at thediscretion 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 contractualrestrictions applying to the payment of dividends and other considerations thatthe board of directors deems relevant. The terms of our credit facilityrestrict the payment of dividends without the prior written consent of thelenders. Investors must rely on sales of their common stock after priceappreciation, which may never occur, as the only way to realize a return ontheir investment. Investors seeking cash dividends should not purchase ourcommon stock.

 

**PART IV**

** **

**ITEM 15    *EXHIBITS AND FINANCIAL STATEMENT SCHEDULES***

 

(a)(3) Exhibits

 

The following documentsare filed as exhibits to this annual report:

 

| **Exhibit  Number** | ** ** | ** ** | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|---------------------|------------|------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2.1                 |       | —     |       | Amended and Restated  Agreement and Plan of Merger, dated as of February 6, 2008, among Quest  Resources Corporation, Pinnacle Gas Resources, Inc. and Quest  MergerSub, Inc. (incorporated by reference to Exhibit 2.1 to the  Current Report on Form 8-K (File No. 000-17371) filed by Quest  Resource Corporation on February 6, 2008).                                                                                               |
|                |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
| 3.1                 |       | —     |       | Second Amended and  Restated Certificate of Incorporation of Pinnacle Gas Resources, Inc.  (incorporated by reference to Exhibit 3.1 to the Registration Statement  on Form S-1 (File No. 333-133983) filed by Pinnacle Gas  Resources, Inc. on May 10, 2006).                                                                                                                                                                                |
|                |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
| 3.2                 |       | —     |       | Amended and Restated  Bylaws of Pinnacle Gas Resources, Inc. (incorporated by reference to  Exhibit 3.2 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  May 10, 2006).                                                                                                                                                                                                             |
|                |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
| 4.1                 |       | —     |       | Amended and Restated  Securityholders Agreement, dated February 16, 2006 (incorporated by  reference to Exhibit 4.1 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  May 10, 2006).                                                                                                                                                                                                 |
|                |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
| 4.2                 |       | —     |       | Registration Rights  Agreement, dated April 11, 2006 (incorporated by reference to  Exhibit 4.2 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources,  Inc.  on May 10, 2006).                                                                                                                                                                                                                    |
|                |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
| 10.1                |       | —     |       | Termination of AMI  Agreement, dated April 11, 2006, by and among Pinnacle Gas  Resources, Inc., CCBM, Inc., Carrizo Oil & Gas, Inc.,  U.S. Energy Corp., Crested Corp. and the CSFB Parties (as defined therein)  (incorporated by reference to Exhibit 10.1 to Amendment No. 1 to  the Registration Statement on Form S-1 (File No. 333-133983)  filed by Pinnacle Gas Resources, Inc. on September 15, 2006). |

 

| **Exhibit  Number** | ** ** | ** ** | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|---------------------|------------|------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.2                |       | —     |       | Credit Agreement, dated  February 12, 2007, by and among Pinnacle Gas Resources, Inc., as  Borrower, the Lenders from time to time party thereto and Royal Bank of  Scotland plc, individually and as Administrative Agent (incorporated by  reference to Exhibit 10.2 to Amendment No. 1 to the Registration  Statement on Form S-1 (File No. 333-139556) filed by Pinnacle  Gas Resources, Inc. on April 3, 2007). |
|                |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| 10.3                |       | —     |       | Letter regarding waiver  and amendment of Credit Agreement, dated March 9, 2007 (incorporated by  reference to Exhibit 10.3 to Amendment No. 1 to the Registration  Statement on Form S-1                                                                                                                                                                                                                                                          |

 

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|        |   |   |   | (File No. 333-139556)  filed by Pinnacle Gas Resources, Inc. on April 3, 2007).                                                                                                                                                                                                                                                                                                                            |
|-------------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.4        |   | — |   | Purchase and Sale  Agreement, dated February 7, 2006, between Kennedy Oil and Pinnacle Gas  Resources, Inc. (incorporated by reference to Exhibit 10.5 to  Amendment No. 1 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  September 15, 2006).                                                                        |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.5        |   | — |   | Gas Gathering Agreement  (Low Pressure Field Gathering) by and among Bitter Creek Pipelines, LLC  and Pinnacle Gas Resources, Inc., Quaneco L.L.C. and Dolphin Energy  Corporation (incorporated by reference to Exhibit 10.6 to Amendment  No. 1 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  September 15, 2006). |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.6        |   | — |   | Gas Gathering Agreement  (High Pressure Gathering Line) by and among Bitter Creek Pipelines, LLC  and Pinnacle Gas Resources, Inc., Quaneco L.L.C. and Dolphin Energy  Corporation (incorporated by reference to Exhibit 10.7 to Amendment  No. 1 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  September 15, 2006). |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.7        |   | — |   | Midstream  Transportation Agreement, effective December 1, 2003, by and between  Pinnacle Gas Resources, Inc. and Clear Creek Natural Gas, LLC  (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to  the Registration Statement on Form S-1 (File No. 333-133983)  filed by Pinnacle Gas Resources, Inc. on September 15, 2006).                                |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                           |
| †10.8  |   | — |   | Amended and Restated  Stock Incentive Plan, effective February 16, 2006 (incorporated by  reference to Exhibit 10.9 to Amendment No. 1 to the Registration  Statement on Form S-1 (File No. 333-133983) filed by Pinnacle  Gas Resources, Inc. on September 15, 2006).                                                                                                                 |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                           |
| †10.9  |   | — |   | Form of Stock  Option Agreement (incorporated by reference to Exhibit 10.10 to  Amendment No. 1 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources,  Inc.  on September 15, 2006).                                                                                                                                                       |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                           |
| †10.10 |   | — |   | Form of Restricted  Stock Grant Agreement (incorporated by reference to Exhibit 10.11 to  Amendment No. 1 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  September 15, 2006).                                                                                                                                              |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                           |
| †10.11 |   | — |   | Form of  Indemnification Agreement (incorporated by reference to Exhibit 10.13 to  Amendment No. 1 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources,  Inc.  on September 15, 2006).                                                                                                                                                    |

 

| **Exhibit  Number** |   |   |   | **Description**                                                                                                                                                                                                                                                                                                                                                                     |
|---------------------|--------|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.12               |   | — |   | Purchase/Placement  Agreement, dated March 31, 2006, between Pinnacle Gas  Resources, Inc. and Friedman, Billings, &  Ramsey & Co., Inc. (incorporated by reference to  Exhibit 10.18 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  May 10, 2006). |
|                |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                |
| †10.13         |   | — |   | Summary of Director  Compensation.                                                                                                                                                                                                                                                                                                                                                  |
|                |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                |
| †10.14         |   | — |   | Employment Agreement,  dated July 20, 2007, by and between Pinnacle Gas Resources, Inc.  and Peter G. Schoonmaker (incorporated by reference to Exhibit 10.1 to  the Current Report on Form 8-K (File No. 001-33457) filed by  Pinnacle Gas Resources, Inc. on July 24, 2007).                                                              |
|                |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                |
| †10.15         |   | — |   | Employment Agreement,  dated July 20, 2007, by and between Pinnacle Gas Resources, Inc.  and Ronald T. Barnes (incorporated by reference to Exhibit 10.2 to the  Current Report on Form 8-K (File No. 001-33457) filed by  Pinnacle Gas Resources, Inc. on July 24, 2007).                                                                  |

 

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| †10.16 |   | — |   | Pinnacle Gas  Resources, Inc. Management Incentive Plan (incorporated by reference to  Exhibit 10.3 to the Current Report on Form 8-K  (File No. 001-33457) filed by Pinnacle Gas Resources,  Inc. on  July 24, 2007).                                                                                                                                              |
|-------------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                   |
| 10.17       |   | — |   | Letter Agreement by and  between Pinnacle Gas Resources, Inc. and the Royal Bank of Scotland,  executed as of April 10, 2008, regarding the credit facility dated as of  February 12, 2007 (incorporated by reference to Exhibit 10.1 to the  Quarterly Report on Form 10-Q (File No. 001-33457) filed by  Pinnacle Gas Resources, Inc. on May 15, 2008). |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                   |
| 10.18       |   | — |   | Second Amendment to  Credit Agreement, dated August 4, 2008 (incorporated by reference to  Exhibit 10.1 to the Current Report on Form 8-K  (File No. 001-33457) filed by Pinnacle Gas Resources,  Inc. on  August 6, 2008).                                                                                                                                         |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                   |
| 10.19       |   | — |   | Third Amendment to  Credit Agreement, effective September 30, 2008 (incorporated by  reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q (File No. 001-33457)  filed by Pinnacle Gas Resources, Inc. on November 14, 2008).                                                                                                                              |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                   |
| †10.20 |   | — |   | Second Amended and  Restated Stock Incentive Plan, effective November 11, 2008 (incorporated  by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q  (File No. 001-33457) filed by Pinnacle Gas Resources, Inc. on  November 14, 2008).                                                                                                                 |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                   |
| 10.21       |   |   |   | Fourth Amendment to  Credit Agreement dated as of April 14, 2009 filed by Pinnacle Gas  Resources, Inc. on April 15, 2009.                                                                                                                                                                                                                                                              |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                   |
| *31.1       |   | — |   | Certification of President  and Chief Executive Officer of Pinnacle Gas Resources, Inc. pursuant to  Rules 13a-14(a) and 15d-14(a).                                                                                                                                                                                                                                                     |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                   |
| *31.2       |   | — |   | Certification of Senior  Vice President, Chief Financial Officer and Secretary of Pinnacle Gas  Resources, Inc. pursuant to Rules 13a-14(a) and 15d-14(a).                                                                                                                                                                                                                              |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                   |
| *32.1       |   | — |   | Certification of  President and Chief Executive Officer of Pinnacle Gas Resources, Inc.  pursuant to 18 U.S.C. Section 1350, as adopted pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                     |
|        |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                   |
| *32.2       |   | — |   | Certification of Senior  Vice President, Chief Financial Officer and Secretary of Pinnacle Gas  Resources, Inc. pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                              |

 

----

*              Filed herewith

 

†              Management contract or compensatory plan or arrangement

 

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**SIGNATURES**

 

Pursuant to therequirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the registrant has duly caused this report to be signed onits behalf by the undersigned, thereunto duly authorized.

 
|   |                               |
|--------|------------------------------------|
|   | PINNACLE GAS  RESOURCES, INC. |
|   |                               |
|   | By:                                | /s/ PETER G.  SCHOONMAKER |
|   |                               | Name: Peter G.  Schoonmaker   Title: *President and Chief Executive  Officer* |

 

Date: November 30,2009

 

Pursuant to therequirements of the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the registrant and in thecapacities and on the dates indicated.

 
| **Signature**                  | ** ** | **Title**                      | ** ** | **Date**                |
|--------------------------------|------------|--------------------------------|------------|-------------------------|
|                           |       |                           |       |                    |
|                           |       | President and  Chief           |       | November 30,  2009 |
| /s/ Peter G.  Schoonmaker      |       | Executive Officer              |       |                    |
| Peter G.  Schoonmaker          |       | (Principal  Executive Officer) |       |                    |
|                           |       | and Director                   |       |                    |
|                           |       |                           |       |                    |
|                           |       | Senior Vice  President, Chief  |       | November 30,  2009 |
| /s/ Ronald T.  Barnes          |       | Financial  Officer             |       |                    |
| Ronald T. Barnes               |       | and Secretary  (Principal      |       |                    |
|                           |       | Financial  Officer             |       |                    |
|                           |       | and Principal  Accounting      |       |                    |
|                           |       | Officer)                       |       |                    |
|                           |       |                           |       |                    |
| /s/ Thomas G.  McGonagle       |       | Chairman of the  Board of      |       |                    |
| Thomas G.  McGonagle           |       | Directors                      |       | November 30,  2009 |
|                           |       |                           |       |                    |
| /s/ Robert L.  Cabes, Jr. |       |                           |       |                    |
| Robert L.  Cabes, Jr.     |       | Director                       |       | November 30,  2009 |
|                           |       |                           |       |                    |
| /s/ Jeffrey P.  Gunst          |       |                           |       |                    |
| Jeffrey P. Gunst               |       | Director                       |       | November 30,  2009 |
|                           |       |                           |       |                    |
| /s/ S. P.  Johnson, IV         |       |                           |       |                    |
| S. P. Johnson,  IV             |       | Director                       |       | November 30,  2009 |

 

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Table of Contents

 
| /s/ F. Gardner  Parker |   |     |   |                    |
|------------------------|--------|----------|--------|-------------------------|
| F. Gardner  Parker     |   | Director |   | November 30,  2009 |
|                   |   |     |   |                    |
| /s/ Susan C.  Schnabel |   |     |   |                    |
| Susan C.  Schnabel     |   | Director |   | November 30,  2009 |

 

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