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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on April 27, 2007

Registration No. 333-139556

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 3
to
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

Pinnacle Gas Resources, Inc.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

1311
(Primary Standard Industrial
Classification Code Number)

30-0182582
(I.R.S. Employer
Identification Number)

1 E. Alger Street
Sheridan, Wyoming 82801
(307) 673-9710
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Peter G. Schoonmaker
President and Chief Executive Officer
Pinnacle Gas Resources, Inc.
1 E. Alger Street
Sheridan, Wyoming 82801
(307) 673-9710
(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:
David C. Buck Andrews Kurth LLP 600 Travis, Suite 4200 Houston, Texas 77002 (713) 220-4200		Mark Zvonkovic Akin Gump Strauss Hauer & Feld LLP 590 Madison Avenue New York, New York 10022-2524 (212) 872-8008

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this registration statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

Subject to Completion, dated April 27, 2007

The information in this prospectus is not complete and may be changed. These securities may not be sold pursuant to the registration statement of which this prospectus is a part until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

PROSPECTUS

3,750,000 Shares of
Common Stock

This is the initial public offering of shares of common stock of Pinnacle Gas Resources, Inc. We are offering a total of 3,750,000 shares of common stock.

Prior to this offering, there has been no public market for our common stock. The initial public offering price of our common stock is currently expected to be between $10.00 per share and $12.00 per share. Our common stock has been approved for listing on The NASDAQ Global Market, subject to official notice of issuance, under the symbol "PINN."

Please read "Risk Factors" beginning on page 12 to read about factors you should consider before buying our common stock.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

		Price to Public			Underwriting Discounts and Commissions			Net Proceeds to Pinnacle
Per Share		$			$			$
Total		$			$			$

The selling stockholders have granted the underwriters a 30-day option to purchase up to an additional 562,500 shares of common stock from the selling stockholders on a pro rata basis on the same terms and conditions as set forth in this prospectus to cover over-allotments, if any. We will not receive any proceeds from any shares of common stock sold by the selling stockholders.

The underwriters expect to deliver the shares of common stock on or about , 2007.

Book-Running Manager

FRIEDMAN BILLINGS RAMSEY

RBC CAPITAL MARKETS

A.G. EDWARDS

JOHNSON RICE & COMPANY L.L.C.

Prospectus dated , 2007

PINNACLE GAS RESOURCES, INC.
PINNACLE POWDER RIVER BASIN LEASES
(as of December 31, 2006)

PINNACLE POWDER RIVER BASIN LEASES
GROSS ACREAGE:		422,000
NET ACREAGE:		277,000

TABLE OF CONTENTS

About this Prospectus		ii
Where You Can Find More Information		ii
Cautionary Statement Concerning Forward-Looking Statements		iii
Summary		1
Risk Factors		12
Use of Proceeds		27
Dividend Policy		27
Capitalization		28
Dilution		29
Selected Financial Data		30
Management's Discussion and Analysis of Results of Operations and Financial Condition		32
Business		49
Management		76
Certain Relationships and Related Party Transactions		94
Security Ownership of Certain Beneficial Owners and Management		97
Selling Stockholders		99
Description of Capital Stock		101
Shares Eligible for Future Sale		104
Underwriting		106
Registration Rights		110
Material U.S. Federal Tax Considerations for Non-U.S. Holders of Our Common Stock		112
Legal Matters		115
Experts		115
Change in Independent Registered Public Accounting Firm		115
Index to Financial Statements		F-1
Glossary of Certain Natural Gas Terms		A-1

ABOUT THIS PROSPECTUS

This prospectus highlights selected information about us and our common stock but does not contain all information that you should consider before investing in the shares. You should read this entire prospectus carefully, including the information included under the heading "Risk Factors."

You should rely only on the information contained in this prospectus. We have not, and the underwriters and selling stockholders have not, authorized anyone else to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters and selling stockholders are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since such date.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC, under the Securities Act of 1933, as amended (the Securities Act), a registration statement on Form S-1 with respect to the common stock offered in this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all the information set forth in the registration statement or the exhibits and schedules which are part of the registration statement, portions of which are omitted as permitted by the rules and regulations of the SEC. Statements made in this prospectus regarding the contents of any contract or other document are summaries of the material terms of the contract or document. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. For further information pertaining to us and to the common stock offered by this prospectus, reference is made to the registration statement, including the exhibits and schedules thereto, copies of which may be inspected, without charge, at the public reference facilities of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of all or any portion of the registration statement may be obtained from the SEC at prescribed rates. Information on the public reference facilities may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a web site that contains reports, proxy and information statements, and other information that is filed electronically with the SEC. The web site can be accessed at www.sec.gov.

After effectiveness of the registration statement, which includes this prospectus, we will be required to comply with the informational requirements of the Securities Exchange Act of 1934, as amended (the Exchange Act), and, accordingly, will file current reports on Form 8-K, quarterly reports on Form 10-Q, annual reports on Form 10-K, proxy statements and other information with the SEC. Those reports, proxy statements and other information will be available for inspection and copying at the public reference facilities and on the SEC web site referred to above.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

We are including the following discussion to inform you of some of the risks and uncertainties that can affect our company. Various statements in this prospectus, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. These include statements relating to such matters as:

•: projections and estimates concerning the timing and success of specific projects;
•: our financial position or operating results;
•: our business strategy;
•: our budgets;
•: the amount, nature and timing of capital expenditures;
•: the drilling of wells;
•: the development of recently acquired natural gas and oil properties, including our acquisition of Green River Basin assets;
•: the timing and amount of future production of natural gas and oil;
•: our operating costs and other expenses;
•: our estimated future net revenues from natural gas and oil reserves and the present value thereof;
•: our cash flow and anticipated liquidity; and
•: our other plans and objectives for future operations.

When we use the words "believe," "intend," "expect," "may," "should," "anticipate," "could," "estimate," "plan," "predict," "project," their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this prospectus speak only as of the date of this prospectus. We disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

•: our ability to implement our business strategy;
•: the extent of our success in discovering, developing and producing reserves, including the risks inherent in exploration and development drilling, well completion and other development activities;
•: fluctuations in the commodity prices for natural gas and crude oil;
•: engineering, mechanical or technological difficulties with operational equipment, in well completions and workovers, and in drilling new wells;
•: the effects of government regulation and permitting and other legal requirements;
•: labor problems;

iii

•: environmental-related problems;
•: the uncertainty inherent in estimating future natural gas and oil production or reserves;
•: production variances from expectations;
•: the substantial capital expenditures required for construction of pipelines and the drilling of wells and the related need to fund such capital requirements through commercial banks and/or public securities markets;
•: disruptions, capacity constraints in or other limitations on our or others' pipeline systems;
•: our ability to effectively market our production;
•: land issues and the costs associated with perfecting title for natural gas rights in some of our properties;
•: our ability to develop and replace reserves;
•: dependence upon key personnel;
•: the lack of liquidity of our equity securities;
•: operating hazards attendant to the natural gas and oil business, including down-hole drilling and completion risks that are generally not recoverable from third parties or insurance;
•: potential mechanical failure or under-performance of significant wells;
•: climatic conditions or natural disasters;
•: acts of terrorism;
•: the availability and cost of materials and equipment;
•: delays in anticipated start-up dates;
•: our ability to find and retain skilled personnel;
•: the availability of capital;
•: competition from, and the strength and financial resources of, our competitors; and
•: general economic conditions.

When you consider these forward-looking statements, you should keep in mind these factors and the other factors discussed under "Risk Factors."

SUMMARY

This summary highlights information contained elsewhere in this prospectus but does not contain all the information you should consider before investing in our shares of common stock. You should read the entire prospectus carefully, including the risks discussed in the "Risk Factors" section, the historical financial statements and the notes to those financial statements. Unless otherwise indicated, this prospectus assumes that the underwriters' over-allotment option will not be exercised.

All references in this prospectus to "we," "us," "our" and "Pinnacle" refer to Pinnacle Gas Resources, Inc. We have included as Appendix A to this prospectus a glossary of certain technical terms and abbreviations used in this prospectus that are important to an understanding of our business.

PINNACLE GAS RESOURCES, INC.

Overview

We are an independent energy company engaged in the acquisition, exploration and development of domestic onshore natural gas reserves. We currently focus our efforts on the development of coalbed methane, or CBM, properties located in the Rocky Mountain region, and we are a substantial holder of CBM acreage in the Powder River Basin. We have assembled a large, predominantly undeveloped CBM leasehold position, which we believe positions us for significant long-term growth in production and proved reserves. In addition, we own over 94% of the rights to develop conventional and unconventional oil and gas in zones below our existing CBM reserves. Substantially all our undeveloped acreage as of December 31, 2006 was located on the northern end of the Powder River Basin in northeastern Wyoming and southern Montana.

As of December 31, 2006, we owned natural gas and oil leasehold interests in approximately 454,000 gross (308,000 net) acres, approximately 92% of which are undeveloped. As of December 31, 2006, we had identified approximately 5,000 CBM drilling locations on our existing acreage, primarily on 80-acre well spacing, targeting an average of three coal seams per location. At December 31, 2006, we had estimated net proved reserves of 20.3 Bcf based on a year-end Colorado Interstate Gas, or CIG, index price of $4.46 per Mcf, with a pre-tax PV-10 value of $25.3 million. These net proved reserves were located on approximately 8% of our net acreage. Based on our drilling results to date, analysis of core samples and third-party results in adjacent areas, we believe that our remaining undeveloped CBM acreage has substantial commercial potential. None of our acreage or producing wells is associated with coal mining operations.

As of December 31, 2006, we owned interests in 529 gross (281 net) producing wells and operated 98% of these wells. During 2006, we drilled 230 gross (139 net) wells and produced an average of 6.6 MMcf per day net to our interest. We exited 2006 producing 7.5 MMcf per day net to our interest. We incurred capital expenditures of $68.5 million during 2006, of which $39.9 million was primarily related to drilling, completion and infrastructure costs on our undeveloped acreage in our Kirby, Deer Creek, Cabin Creek and Green River Basin areas and the remaining $28.6 million was related to acquisitions, including $27.0 million for our Green River Basin acquisition. For 2007, we have a total capital expenditure budget of approximately $52.6 million to drill and complete approximately 260 gross (207 net) wells, to construct related gas and water infrastructure, to fund plans of development costs for future wells, to fund undeveloped leasehold acquisition costs carried over from 2006, to recomplete certain wells, and to fund infrastructure and completion costs related to wells drilled in 2006.

Recent Developments

Based on an updated reserve report by Netherland, Sewell & Associates, Inc., or NSAI, at February 28, 2007, we had estimated net proved reserves of approximately 25.9 Bcf based on the CIG index price of $6.28 per Mcf, with a pre-tax PV-10 value of $54.8 million. The difference in our net proved reserves between December 31, 2006 and February 28, 2007 included an approximate 2.3 Bcf

increase due to extensions of existing fields and discoveries of new fields, an approximate 3.8 Bcf increase due to an increase in the price of natural gas from $4.46 per Mcf at December 31, 2006 to $6.28 per Mcf at February 28, 2007, and an approximate 0.5 Bcf decrease due to new production in the first two months of 2007. At the end of 2006 and in the first two months of 2007, 35 gross (10 net) wells became commercially productive. Please see "Risk Factors—The volatility of natural gas and oil prices could have a material adverse effect on our business."

During the three months ended March 31, 2007, we drilled 20 gross (11 net) wells and completed 39 gross (22 net) wells compared to 74 gross (46 net) wells drilled and 29 gross (15 net) wells completed during the three months ended March 31, 2006. As of March 31, 2007, we had 598 gross (319 net) wells producing gas or dewatering compared to 529 gross (281 net) wells and 409 gross (206 net) wells producing gas or dewatering as of December 31, 2006 and March 31, 2006, respectively. As of March 31, 2007, we had a total of 539 gross (288 net) wells producing gas compared to 487 gross (257 net) wells and 374 gross (187 net) wells producing gas as of December 31, 2006 and March 31, 2006, respectively. During the three months ended March 31, 2007, we had net gas sales volume of approximately 725.0 MMcf compared to 565.3 MMcf during the three months ended March 31, 2006. During the three months ended March 31, 2007, we had an average daily gas volume of 8.1 MMcf per day compared to 6.6 MMcf and 6.3 MMcf per day during the year ended December 31, 2006 and the three months ended March 31, 2006, respectively.

Our Powder River Basin and Green River Basin CBM Projects

During the period from our formation in June 2003 to December 31, 2006, we completed 560 gross (278 net) of the 613 gross (327 net) CBM wells we drilled in the Powder River and Green River Basins. We expect to complete an additional 53 gross (49 net) of these wells as soon as necessary infrastructure becomes available. If, as expected, we complete these additional wells, we will have completed over 99% of the wells drilled through December 31, 2006.

Powder River Basin

Our Powder River Basin properties are located in Wyoming and Montana. Our acreage position in the northern end of the Powder River Basin is generally contiguous, providing us with critical mass and the ability to execute large-scale development projects in our operating areas. CBM wells in the Powder River Basin typically have a shorter reserve life of seven to eight years and produce at lower rates and have lower total reserve amounts than most conventional natural gas wells. As a result, we depend on drilling a large number of wells each year to replace production and reserves in the Powder River Basin.

•: Wyoming. Our principal Wyoming properties in the Powder River Basin are located in two distinct project areas: Recluse and Cabin Creek. Substantially all of our natural gas production has come from the Recluse area. As of December 31, 2006, we held approximately 97,000 gross (55,000 net) acres in the Powder River Basin in Wyoming for prospective CBM development and we operated over 97% of this acreage.
•: Montana. Our Montana properties are located in four project areas: Kirby, Deer Creek, Bear Creek and Bradshaw. As of December 31, 2006, we held approximately 325,000 gross (222,000 net) acres in Montana for prospective CBM development and we operated 100% of this acreage.

Green River Basin

On April 20, 2006, we acquired properties and assets located in the Green River Basin in the northeast area of Sweetwater County, Wyoming. As of December 31, 2006, our properties in the Green River Basin consisted of approximately 32,000 gross (31,000 net) undeveloped acres for prospective CBM development in the Fort Union Big Red Coal formation. As of December 31, 2006, we operated

100% of this acreage. Please see "Business—Powder River Basin and Green River Basin CBM Projects—Green River Basin" for further information about this acquisition.

Regulation of CBM Projects

CBM drilling operations are regulated by federal, state and local authorities. Compliance with the requirements imposed by regulatory authorities can be costly and time consuming and can result in delays in our operations and/or fines. For example, we are currently subject to an injunction which prohibits the Montana Bureau of Land Management from approving any CBM drilling permits on U.S. federal lands in the Powder River Basin of Montana. In addition, in the ordinary course of our business, we have received notices of violation or orders to cease production with respect to certain of our wells that have resulted in production delays and/or fines. Although we are not aware of any pending or threatened notices of violation or orders to cease production that would reasonably be expected to have a material adverse effect on us, similar regulatory or legal action in the future could materially interfere with our operations. Please see "Risk Factors," "Business—Regulations" and "Business—Legal Proceedings" for further information regarding the regulations and legal proceedings we may encounter in conducting our business.

Summary of Our Powder River and Green River Basin Properties and 2007 Capital Budget

		Producing Wells as of December 31, 2006		Producing Wells as of December 31, 2005
						2007 Capital Budget(1)(2)
						2007 Capital Budget(1)(2)				Estimated Potential Drilling Locations (Approximate)
		Gross	Net	Gross	Net	Gross Wells	Net Wells	Capital Expenditures		Estimated Potential Drilling Locations (Approximate)	Estimated Total Net Acres (Approximate)
Recluse(3)		407	208	395	198	54	27	$	3.9	350	17,000
Cabin Creek		29	15	0	0	132	116		24.7	450	31,000
Kirby		93	58	9	5	2	1		0.2	1,650	51,000
Deer Creek		0	0	0	0	71	62		8.4	620	47,000
Bear Creek		0	0	0	0	0	0		0	710	53,000
Bradshaw		0	0	0	0	0	0		0	1,000	71,000
Green River Basin(4)		0	0	0	0	1	1		7.5	160	31,000
Other		0	0	0	0	0	0		0	60	7,000

	Total	529	281	404	203	260	207	$	44.7	5,000	308,000

(1): For the year ended December 31, 2006, capital expenditures for drilling 230 gross (139 net) wells totaled $34.7 million.
(2): Excludes approximately $5.9 in capital expenditures relating to plans of development costs for wells to be drilled in the future and $2.0 million of undeveloped leasehold acquisition costs in 2006.
(3): Includes approximately $0.5 million for recompletions.
(4): Includes approximately $7.3 million of infrastructure and completion costs related to wells drilled in 2006.

Strategy

The principal elements of our business strategy are designed to generate growth in natural gas reserves, production volumes and cash flows at an attractive return on invested capital. We seek to achieve these goals through the application of the following strategies:

•: Accelerating the development of our acreage position by increasing the level of our drilling activity;

•: Maintaining operational control over our assets in order to control the costs and timing of our exploration, development and production activities;
•: Constructing and maintaining control over our low-pressure gas gathering systems that collect and transport our production;
•: Maintaining a low-cost and efficient operating environment by exploiting the economies of scale that arise from developing our large contiguous acreage position;
•: Proactively managing legal, regulatory and environmental issues to ensure the efficient and timely development of our asset base;
•: Pursuing selective acquisitions that add attractive exploitation and development opportunities and also enhance the critical mass of our asset base;
•: Pursuing selective acquisition opportunities that would allow us to apply our CBM development expertise in other areas in the Rocky Mountain region; and
•: Exploring the potential of the deeper lease rights below the Fort Union formation coal seams on our existing acreage position.

Competitive Strengths

We have a number of strengths that we believe will help us successfully implement our strategy.

•: Experienced Management Team. Our key personnel have significant experience managing CBM operations, particularly in the Powder River Basin. Our management team has an average of 20 years of experience in acquiring, developing and operating oil and gas properties, primarily in the Rocky Mountain region.
•: Significant Reserve Potential. According to the U.S. Department of Energy 2002 Powder River Basin Coalbed Methane Development and Produced Water Management Study, the Montana portion of the Powder River Basin is estimated to have substantial recoverable reserves. We hold a significant portion of the acreage that is prospective for CBM development in the Montana portion of the Powder River Basin.
•: Low Geological Risk. The coal seams in the Powder River Basin that we target have been extensively mapped as a result of a variety of natural resource development that has occurred in the region. Industry data from over 23,500 wellbores drilled through the Fort Union formation allows us to determine the aerial extent, thickness, gas saturation, formation pressure and relative permeability of the coal seams we target for development, which reduces our dry hole risk.
•: Low Development Risk and Predictable Results. As of December 31, 2006, we had completed 560 gross (278 net) of the 613 gross (327 net) CBM wells that we had drilled on our acreage. We expect to complete an additional 53 gross (49 net) of these wells as soon as necessary infrastructure becomes available. If, as expected, we complete these additional wells, we will have completed over 99% of the wells drilled through December 31, 2006. Our overall drilling program is relatively predictable on an average well basis in terms of recoverable reserves, production rates and decline curves, which results in lower development risk.
•: Large, Contiguous Acreage Position. Our acreage position of approximately 454,000 gross (308,000 net) acres includes one of the largest contiguous acreage positions in the Powder River Basin. Many of our leases are in large blocks generally along the Wyoming and Montana border, adjacent to newly established areas of development activities. We believe the contiguous nature of the majority of our Powder River Basin properties gives us the necessary critical mass to better manage operating and development costs and surface issues, obtain pipeline access and execute our plan of development.

•: Extensive Inventory of Drilling Locations. As of December 31, 2006, our net acreage position was only 8% developed. As of December 31, 2006, we had identified approximately 5,000 CBM drilling locations on our existing acreage, primarily on 80-acre well spacing, targeting an average of three coal seams per location.
•: Large Inventory of Drilling Permits. As of December 31, 2006, we had 407 approved drilling permits for our Wyoming acreage and we are in the process of applying for an additional 415 permits in Wyoming which we expect to be approved before the end of 2007. As of December 31, 2006, we had four plans of development approved for our Montana acreage allowing us to drill 67 additional wells and we are in the process of applying for an additional 1,344 permits which we expect to be approved before the end of 2007. We believe that in the near future, we will have sufficient permits to support at least two years of our planned drilling activity.
•: Attractive Cost Structure. We believe our average cost structure is attractive due to the low geological risk, high completion rates, generally shallow drilling depths and low-cost completions, including multiple zone completions, associated with developing our CBM acreage position. Although our lease operating costs are higher than average on a per Mcf basis while we are in our initial stages of development, we expect that our lease operating expenses will benefit from economies of scale as we grow, our maintaining high operatorship of our reserves and production, and our continuing cost management initiatives.
•: Control of Low-Pressure Gas Gathering Infrastructure. As of December 31, 2006, we owned and operated approximately 208 miles of low-pressure gas gathering pipelines that collect and transport our production in the Recluse area of Wyoming. We intend to construct, own and operate the additional low-pressure gas gathering system assets required to develop our acreage position.
•: Marketing Flexibility. Production from our acreage has access to several regional and interstate pipelines, providing sufficient takeaway capacity from our operating region and access to major gas demand centers in the United States.
•: Local Presence. We are headquartered in Sheridan, Wyoming, which is the center of our project areas in the Powder River Basin. Our local presence gives us insight into the issues associated with Powder River Basin CBM development and the ability to quickly and effectively communicate with landowners, mineral owners and regulatory agencies.

Our History

We were formed in June 2003 by funds affiliated with DLJ Merchant Banking III, Inc., which we refer to collectively as DLJ Merchant Banking, and subsidiaries of Carrizo Oil & Gas, Inc., or Carrizo, and U.S. Energy Corporation, or U.S. Energy. DLJ Merchant Banking III, Inc. is an affiliate of Credit Suisse's asset management business. As of December 31, 2006, our two primary stockholders, DLJ Merchant Banking and Carrizo, beneficially owned approximately 38.9% and 9.8%, respectively, of our outstanding common stock. After this offering, DLJ Merchant Banking and Carrizo will beneficially own approximately 32.5% and 8.2%, respectively, of our outstanding common stock if the over-allotment option is exercised in full. For more information regarding our formation and ownership history, please read "Business—Our History."

We have completed two significant acquisitions since our inception, not including the Green River Basin acquisition:

•: In June 2003, we acquired approximately 57,000 gross (22,000 net) acres along with 210 gross (96 net) producing wells and shut-in wells in Wyoming from Gastar Exploration, Ltd. and certain of its affiliates.
•: In March 2005, we acquired approximately 223,000 gross (196,000 net) undeveloped acres for prospective CBM development in Montana and Wyoming from a subsidiary of Marathon Oil Corporation.

The Offering

Common stock offered:
	By us	3,750,000 shares
	By the selling stockholders	562,500 shares if the underwriters' over-allotment option is fully exercised
	Total	3,750,000 shares (4,312,500 shares if the underwriters' over-allotment option is fully exercised)
Common stock to be outstanding after this offering		28,928,301 shares(1)
Common stock owned by the selling stockholders after the offering		14,616,756 shares if the underwriters' over-allotment option is fully exercised
Use of proceeds		We estimate that our net proceeds from the sale of the shares offered by us, after deducting estimated expenses and underwriting discounts and commissions, will be approximately $37.7 million, assuming an initial public offering price of $11.00 per share. We plan to use the net proceeds:
		•	to pay down all of the outstanding indebtedness under our credit facility; and
		•	for accelerated capital expenditures, infrastructure development and general corporate purposes.
		Please see "Use of Proceeds."
		We will not receive any proceeds from the sale of the shares of common stock by the selling stockholders.
Reserved NASDAQ symbol		PINN
Dividend Policy		We do not expect to pay dividends in the foreseeable future.
Risk factors		Please see "Risk Factors" beginning on page 12 of this prospectus for a discussion of factors that you should carefully consider before deciding to invest in shares of our common stock.

(1): The number of shares of our common stock outstanding after this offering does not include 964,000 shares issuable upon the exercise of options outstanding as of March 31, 2007 under our stock incentive plan but does include 74,270 shares of restricted common stock issued and outstanding as of March 31, 2007 under our stock incentive plan.

Summary of Financial Data

The following tables set forth a summary of our historical financial data for, and as of the end of, each of the periods indicated. The statement of operations, statement of cash flows and other financial data for the period from inception (June 23, 2003) to December 31, 2003, and the balance sheet data as of December 31, 2004, are derived from our audited financial statements not included in this prospectus. The statement of operations, statement of cash flows and other financial data for the years ended December 31, 2004, 2005 and 2006, and the balance sheet data as of December 31, 2005 and 2006, are derived from our audited financial statements included elsewhere in this prospectus. The as adjusted balance sheet data gives effect to (a) the issuance by us of 3,750,000 shares of common stock in this offering based on an assumed offering price of $11.00 per share, net of the underwriters' discounts and commissions, and (b) the use of all of the net proceeds we receive from this offering as described in this prospectus.

Our historical results are not necessarily indicative of the results that may be expected for any future period. The following data should be read in conjunction with "Management's Discussion and Analysis of Results of Operations and Financial Condition" and our financial statements and related notes included elsewhere in this prospectus.

			Period from Inception (June 23) to December 31,			Year Ended December 31,
			2003			2004			2005			2006
			(in thousands, except share and per share data)
Statement of Operations Data:
Revenues
	Gas sales		$	1,679		$	7,393		$	14,136		$	12,196
	Income from earn-in joint venture agreement			41			368			1,629			379
	Gains (losses) on derivatives			—			(766	)		(4,815	)		7,362

		Total revenues		1,720			6,995			10,950			19,937
Operating expenses
	Lease operating expenses			772			1,445			1,781			2,993
	Production taxes			186			838			1,637			1,198
	Marketing and transportation			299			1,218			1,582			1,962
	General and administrative, net			729			1,552			2,267			4,343
	Organization costs			311			—			—			—
	Depreciation, depletion, amortization and accretion			850			3,328			5,622			6,673

		Total operating expenses		3,147			8,381			12,889			17,169

Operating income (loss)				(1,427	)		(1,386	)		(1,939	)		2,768
Other income (expense)
	Interest income			33			61			17			720
	Other income			3			4			129			484
	Unrealized derivative loss			—			—			—			(26	)
	Interest expense			—			(2	)		(47	)		(168	)

		Total other income (expense)		36			63			99			1,010

Net income (loss)				(1,391	)		(1,323	)		(1,840	)		3,778
Preferred dividends, related party				(719	)		(2,623	)		(5,409	)		(20,964	)

Net income (loss) attributable to common stockholders			$	(2,110	)	$	(3,946	)	$	(7,249	)	$	(17,186	)

Net income (loss) per common share
	Basic and diluted		$	(0.42	)	$	(0.79	)	$	(1.42	)	$	(0.87	)
Weighted average shares outstanding
	Basic and diluted(1)			5,000,000			5,000,000			5,094,800			19,783,118

(1): For all periods presented, all of our stock options and warrants were anti-dilutive as a result of the losses incurred. Common stock equivalents of 4,965,000, 9,187,500, 13,676,200 and 1,035,000 at December 31, 2003, 2004, 2005 and 2006, respectively, were excluded because they were anti-dilutive.

	Period from Inception (June 23) to December 31,			Year Ended December 31,
	2003			2004			2005			2006
	(in thousands)
Statement of Cash Flows Data:
Net cash provided (used) by operating activities	$	1,315		$	1,350		$	8,792		$	6,029
Net cash provided (used) by investing activities		(14,313	)		(14,017	)		(25,301	)		(63,880	)
Net cash provided (used) by financing activities		17,524			11,740			15,582			59,941
Other Financial Data:
Capital expenditures—exploration and production	$	13,977		$	13,149		$	20,866		$	62,340
Adjusted EBITDA(1)		(574	)		2,584			7,016			3,226

(1): Adjusted EBITDA is defined as earnings (loss) before deducting net interest expense (interest expense less interest income), income taxes, depreciation, depletion and amortization, cumulative effect of accounting change, change in unrealized derivative value, asset retirement obligation accretion and gains on sale of assets. Reconciliations of this non-GAAP financial measure to net income (loss) and net cash provided by operating activities are presented below under "—Reconciliation of Non-GAAP Financial Measures."

	As of December 31,
	2004		2005		2006
					Actual		As Adjusted
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	3,599	$	2,672	$	4,762	$	42,432
Property and equipment, net		43,054		63,529		127,189		127,189
Total assets		54,504		77,081		150,332		188,002
Long-term debt (including current portion)(1)		345		926		807		807
Total liabilities		13,817		23,897		31,503		31,503
Redeemable preferred stock(2)		18,338		31,400		—		—
Total stockholders' equity	$	22,349	$	21,784	$	118,829	$	156,499

(1): Long-term debt does not include fair value of derivatives, asset retirement obligation and the long-term portion of production taxes.
(2): On April 11, 2006, we used approximately $53.6 million of the net proceeds from our private placement to redeem all of the outstanding shares of our Series A Redeemable Preferred Stock, all of which were held by DLJ Merchant Banking.

Reconciliation of Non-GAAP Financial Measures

Although Adjusted EBITDA is not a measure of performance calculated in accordance with generally accepted accounting principles, or GAAP, management considers it an important supplemental measure of our performance. Management also believes that Adjusted EBITDA is a useful tool for measuring our ability to meet our future debt service, capital expenditure and working capital requirements. Adjusted EBITDA is not a substitute for the GAAP measures of earnings or cash flow and is not necessarily a measure of our ability to fund our cash needs. In addition, it should be noted that companies calculate Adjusted EBITDA differently, and therefore Adjusted EBITDA as presented in this prospectus may not be comparable to Adjusted EBITDA reported by other companies. Adjusted EBITDA has material limitations as a performance measure because it excludes, among other things, (a) interest expense, which is a necessary element of our business to the extent that we incur debt, (b) depreciation, depletion, amortization and accretion, which are necessary elements of our business because we use capital assets, and (c) income taxes, which may become a material element of our operations in the future. Because of its limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We account for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.

A reconciliation of Adjusted EBITDA to net income (loss) is as follows:

	Period from Inception (June 23) to December 31,			Year Ended December 31,
	2003			2004			2005			2006
	(in thousands)
Net income (loss)	$	(1,391	)	$	(1,323	)	$	(1,840	)	$	3,778
Add: Interest expense		—			2			47			168
Less: Interest income		(33	)		(61	)		(17	)		(720	)
Add/Less: Change in unrealized derivative value		—			638			3,204			(6,673	)
Add: Asset retirement obligation accretion		10			53			70			162
Add: Depreciation, depletion and amortization		840			3,275			5,552			6,511

Adjusted earnings (loss) before interest, change in unrealized derivative value, asset retirement obligation accretion and depreciation, depletion and amortization (Adjusted EBITDA)	$	(574	)	$	2,584		$	7,016		$	3,226

A reconciliation of Adjusted EBITDA to net cash provided by operating activities is as follows:

	Period from Inception (June 23) to December 31,			Year Ended December 31,
	2003			2004			2005			2006
	(in thousands)
Net cash provided by operating activities	$	1,315		$	1,350		$	8,792		$	6,029
Add: Interest expense		—			2			47			168
Less: Interest income		(33	)		(61	)		(17	)		(720	)
Less/Add: Realized (gain) loss on derivatives		—			(128	)		(1,611	)		663
Less: Stock-based compensation expense		—			—			—			(368	)
Add: Settled asset retirement obligation		—			31			3			2
Less: Increase in prepaid expenses from third parties		—			—			—			(289	)
Less/Add: (Increase) decrease in revenue distribution payable		(502	)		(3,891	)		(3,672	)		764
Less/Add: (Increase) decrease in accounts payable and accrued liabilities		(2,963	)		(320	)		1,573			(6,179	)
Add/Less: Increase (decrease) in prepaid expense		175			227			(289	)		281
Add/Less: Increase (decrease) in inventory		—			505			(24	)		(209	)
Add: Increase in accounts receivable		1,434			4,869			2,214			3,184
Less: Allowance for doubtful accounts		—			—			—			(100	)

Adjusted EBITDA	$	(574	)	$	2,584		$	7,016		$	3,226

Summary Historical Reserve and Operating Data

The following tables present summary information regarding our estimated net proved reserves as of December 31, 2003, 2004, 2005 and 2006, and certain of our historical operating data for the period from inception (June 23, 2003) to December 31, 2003 and for the years ended December 31, 2004, 2005 and 2006. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the SEC, and, except as otherwise indicated, give no effect to federal or state income taxes. The estimates of net proved reserves are based on the reserve reports prepared by NSAI, our independent petroleum consultants. As of December 31, 2006, there were no proved reserves related to the Green River Basin assets which we acquired on April 20, 2006. For additional information regarding our reserves, please see "Business—Operations" and Note 22 to our audited financial statements.

			As of December 31,
			2003			2004			2005			2006(3)
Reserve Data:
Estimated net proved reserves:
	Proved developed producing (MMcf)			1,653			5,154			5,522			3,588
	Proved developed non-producing (MMcf)			3,279			2,277			2,690			4,292

		Total proved developed (MMcf)		4,932			7,431			8,212			7,880
	Proved undeveloped (MMcf)			13,212			17,346			18,827			12,409

		Total proved reserves (MMcf)		18,144			24,777			27,039			20,289

	Future cash flows before income taxes (in millions)		$	35.1		$	49.4		$	84.4		$	34.8
	PV-10 (in millions)(1)		$	24.6		$	34.8		$	58.5		$	25.3
	Income tax effect discounted at 10%		$	(5.9	)	$	(6.4	)	$	(14.8	)	$	(2.9	)

	Standardized measure (in millions)(2)		$	18.7		$	28.4		$	43.7		$	22.4

	Price used for proved reserve PV-10 (CIG index price per Mcf as of December 31)		$	5.575		$	5.515		$	7.715		$	4.460

(1): PV-10 represents the present value of estimated future net revenues attributable to our reserves using constant prices, as of the calculation date, discounted at 10% per year on a pre-tax basis. PV-10 was determined based on the market prices for natural gas on December 31 of each year. PV-10 differs from standardized measure of discounted future net cash flows because it does not include the effects of income taxes on future net cash flows. Neither PV-10 nor standardized measure represent an estimate of fair market value of our reserves. Although PV-10 is not a financial measure calculated in accordance with GAAP, management believes that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to any given company affect the amount of estimated future income taxes, the use of a pre-tax measure is helpful when comparing companies in our industry.
(2): The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved reserves discounted at 10% after giving effect to income taxes, and as calculated in accordance with Statement of Financial Accounting Standards No. 69.
(3): Total proved reserves for 2006 declined primarily due to declines in the price of natural gas. Please see "Risk Factors—The volatility of natural gas and oil prices could have a material adverse effect on our business."

		Period from Inception (June 23) to December 31,		Year Ended December 31,
		2003		2004		2005		2006
Operating Data:
Gross Wells:
	Drilled		124		122		137		230
	Completed		101		155		93		218
	Producing(1)		149		312		404		529
Net Wells:
	Drilled		62		59		66		139
	Completed		51		70		38		119
	Producing(1)		89		166		203		281
Net Production Data:
	Net gas sales volume (MMcf)		423		1,508		2,207		2,413
	Average daily volumes (MMcf)		2.2		4.1		6.0		6.6
Average Sales Price:
	Average sales price excluding effects of financial settlements ($ per Mcf)	$	3.97	$	4.90	$	6.41	$	5.05
	Average sales price including effects of financial settlements ($ per Mcf)(2)	$	3.97	$	4.82	$	5.68	$	5.33
Expenses (per Mcf):
	Lease operating expenses	$	1.83	$	0.96	$	0.81	$	1.24
	Production and ad valorem taxes	$	0.44	$	0.56	$	0.74	$	0.50
	Marketing and transportation	$	0.71	$	0.81	$	0.72	$	0.81
	General and administrative net of overhead reimbursement	$	1.72	$	1.03	$	1.03	$	1.80
	Depreciation, depletion, amortization and accretion	$	2.01	$	2.21	$	2.55	$	2.77

(1): Producing wells include wells producing gas or dewatering at year end. Wells producing gas totaled 121 gross (72 net), 261 gross (141 net), 364 gross (183 net) wells and 487 gross (257 net) at December 31, 2003, 2004, 2005 and 2006, respectively.
(2): Average sales price including effects of financial settlements was calculated by dividing gas sales revenue, after realized gain (loss) on financial settlements, by net gas sales volume. For the period from inception to December 31, 2003, we had no realized gain or loss on financial settlements. For the years ended December 31, 2004 and 2005, we had a realized loss on financial settlements of $128,000 and $1,610,000, respectively. For the year ended December 31, 2006, we had a realized gain of $663,000. For further discussion of our realized gains and losses on financial settlements, please see Note 8 to our audited financial statements included in this prospectus.

Principal Executive Offices and Internet Address

We were formed as a Delaware corporation in June 2003. Our principal executive offices are located at 1 E. Alger, Sheridan, WY 82801 and our telephone number at that location is (307) 673-9710. Our website is located at www.pinnaclegas.com. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

RISK FACTORS

Investing in our common stock will provide you with equity ownership in us. As one of our stockholders, you will be subject to risks inherent in our business. The value of our common stock will be affected by the performance of our business in light of, among other things, our competition, industry conditions and general economic and market conditions. The value of your investment in us may decrease, resulting in a loss. You should carefully consider the following factors as well as the other information contained in this prospectus before deciding to invest in our common stock.

Risks Related to Our Business

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

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

•: the domestic and foreign supply of natural gas and oil;
•: the activities of the Organization of Petroleum Exporting Companies and state-owned oil companies relating to oil price and production controls;
•: overall domestic and global economic and political conditions;
•: the consumption pattern of industrial consumers, electricity generators and residential users;
•: weather conditions;
•: natural disasters;
•: acts of terrorism;
•: political stability in the Middle East and elsewhere;
•: domestic and foreign governmental regulations;
•: the price and quantity of foreign imports; and
•: the price and availability of alternative fuels.

In the past, natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2005, the NYMEX natural gas index price ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu while the CIG natural gas index price ranged from a high of $13.53 per MMBtu to a low of $4.94 per MMBtu. During the year ended December 31, 2006, the NYMEX natural gas index price ranged from a high of $11.23 per MMBtu to a low of $4.20 per MMBtu while the CIG natural gas index price ranged from a high of $7.90 per MMBtu to a low of $1.31 per MMBtu.

A sharp decline in the price of natural gas prices would result in a commensurate reduction in our revenues, income and cash flows from the production of natural gas and could have a material adverse effect on our borrowing base and our proved reserves. For example, our estimate of total proved reserves for 2006 included a downward adjustment of approximately 12.6 Bcf, of which approximately 11.7 Bcf was due to a decline in the price of natural gas. Similarly, our total proved reserves as of February 28, 2007 increased by approximately 3.8 Bcf due to an increase in the price of natural gas from $4.46 per Mcf at December 31, 2006 to $6.28 per Mcf at February 28, 2007. Further, in the event prices fall substantially, we may not be able to realize a profit from our production and would operate at a loss, and even relatively modest drops in prices can significantly affect our financial results and

impede our growth. Lower natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. For example, if natural gas prices decline by $0.10 per Mcf, then the pre-tax PV-10 of our proved reserves as of December 31, 2006 would decrease from $25.3 million to $23.9 million and the pre-tax PV-10 of our proved reserves as of February 28, 2007 would decrease from $54.8 million to $53.2 million. Further, if the pre-tax PV-10 of our proved reserves as of February 28, 2007 had been calculated using the CIG gas price as of December 31, 2006 of $4.46 per Mcf, it would have decreased from $54.8 million to $30.3 million. Accounting rules may also require us to write down, as a non-cash charge to earnings, the carrying value of our properties for impairments. As such, we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

Approximately 82% of our total proved reserves as of December 31, 2006 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.

As of December 31, 2006, approximately 61% of our total proved reserves were undeveloped and approximately 21% were developed non-producing. We plan to develop and produce all of our proved reserves, but ultimately some of these reserves may not be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced at the time periods we have planned, at the costs we have budgeted, or at all.

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

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

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

•: geological conditions;

•: changes in governmental regulations and taxation;
•: assumptions governing future prices;
•: the amount and timing of actual production;
•: future operating costs; and
•: the capital costs of drilling new wells.

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

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

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

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

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

•: unexpected drilling conditions;
•: pressure or irregularities in geologic formations;
•: equipment failures or repairs;
•: title problems;
•: fires, explosions, blowouts, cratering, pollution and other environmental risks or other accidents;
•: compliance with governmental regulations;
•: adverse weather conditions;
•: reductions in natural gas and oil prices;
•: pipeline ruptures;
•: unavailability or high cost of drilling rigs, other field services, equipment and labor; and
•: limitations in the market for oil and gas.

A productive well may become uneconomic in the event that unusual quantities of water or other deleterious substances are encountered, which impair or prevent the production of natural gas and/or

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

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

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuances in the Rocky Mountain region. Compliance with the requirements imposed by these authorities can be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations and/or fines. For example, in the ordinary course of our business, we have received notices of violation or orders to cease production with respect to certain of our wells that have resulted in production delays and/or fines. Similar regulatory or legal actions in the future may materially interfere with our operations or otherwise have a material adverse effect on us. In addition, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

The issuance of permits for CBM development relating to leases on federal land in Montana is subject to the approval of a Supplemental Environmental Impact Statement.

Approximately 59% of our gross acreage in Montana is on U.S. federal land. Federal leases in Montana are regulated by the Montana division of the U.S. Bureau of Land Management, or Montana BLM. Because CBM development in Montana is in its early stages, the permitting process is not as streamlined in Montana as it is in Wyoming. In addition, the Montana BLM has been subject to several lawsuits from various environmental groups in an attempt to block permit issuances for CBM development. In particular, the Ninth Circuit Court of Appeals has issued a blanket injunction which prohibits the Montana BLM from approving any CBM drilling permits on federal lands in the Powder River Basin of Montana until a Supplemental Environmental Impact Statement, or SEIS, is approved. We have intervened in several of the federal cases to protect our interests in these proceedings. We cannot predict how or when the courts will resolve these matters, nor can we foresee future challenges which may arise. Please see "Business—Regulations—Permitting Issues for Federal Lands" for further discussion on these issues.

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

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

Our natural gas sales are dependent on three customers and the loss of any customer would adversely affect our ability to market our gas.

We market our natural gas to three purchasers. During the year ended December 31, 2005, Enserco Energy, Inc. and Western Gas Resources, Inc. purchased 76% and 24% of our gas sold, respectively. During the year ended December 31, 2006, Enserco Energy, Western Gas Resources and United Energy Trading purchased 66%, 21% and 11% of our gas sold, respectively. In the event that Enserco Energy, Western Gas Resources or United Energy Trading were to experience financial difficulties or were to no longer purchase our natural gas, we could, in the short-term, experience difficulty in our marketing of natural gas, which could adversely affect our results of operations.

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

Substantially all of our properties are geographically concentrated at the northern end of the Rocky Mountain region. The price received by us for the natural gas production from these properties is determined mainly by factors affecting the regional supply of and demand for natural gas, as well as the general availability of pipeline capacity to deliver natural gas to the market. Based on recent experience, regional differences could cause a negative basis differential between the published indices generally used to establish the price received for regional natural gas production and the actual price we receive for natural gas production.

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

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

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

We currently engage in hedging arrangements to reduce our exposure to fluctuations in the prices of natural gas for a significant portion of our current natural gas production. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, the counterparty to the hedging contract defaults on its contract obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefits we would otherwise receive from increases in prices for natural gas. Please see "Management's Discussion and Analysis of Results of Operations and Financial Condition—Quantitative and Qualitative Disclosures About Market Risk—Hedging Activities" and "Business—Operations—Hedging Activities."

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

The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from

these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, would have an adverse effect on our business.

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

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

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

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

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

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

Our exploration and production activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, we are subject to legislation regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. Such laws and regulations have been frequently changed in the past, and we are unable to predict the ultimate cost of compliance as a result of any future changes. The adoption or enforcement of stricter regulations could have a significant impact on our operating costs, as well as on the natural gas and oil industry in general. Although we intend to fully comply with all such environmental laws and regulations in the future, such compliance can be very complex, and therefore, no assurances can be

given that such environmental laws and regulations will not have a material adverse effect on our business, financial condition and results of operations.

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

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

Numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. We may be required to make large expenditures to comply with these regulatory requirements. Any increases in the regulatory burden on the natural gas and oil industry created by new legislation would increase our cost of doing business and could result in delays in our operations, and consequently, adversely affect our profitability.

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

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

The natural gas and oil industry is intensely competitive and we compete with other companies, many of which are larger and have greater financial, technological, human and other resources. Many of these companies not only explore for and produce crude oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Such companies may be able to pay more for productive natural gas and oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may have a greater ability to continue exploration activities during periods of low oil and gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete, our operating results and financial position may be adversely affected.

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

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

•: we cannot obtain future permits from applicable regulatory agencies;

•: water of lesser quality is produced;
•: our wells produce excess water; or
•: new laws or regulations require water to be disposed of in a different manner.

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

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

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

Our business is difficult to evaluate because we have a limited operating history.

In considering whether to invest in our common stock, you should consider that we were formed in June 2003 and have a limited operating history. As a result, there is only limited historical financial and operating information available on which to base your evaluation of our performance.

We may have difficulty managing growth in our business.

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

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

The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management. The loss of services of any of our key managers could have a material adverse effect on our business. We have not obtained "key man" insurance for any members of our management. Mr. Peter G. Schoonmaker is our Chief Executive Officer and President, and Mr. Ronald T. Barnes is our Chief Financial Officer, Senior Vice President and Secretary. The loss of the services of either of these individuals, or other key personnel, may adversely affect our business and prospects. We currently do not have employment agreements or non-competition agreements with any of the members of our management other than Mr. Schoonmaker. However, we have agreed to the terms of new employment agreements with each of Messrs. Schoonmaker and Barnes and are in the process of preparing definitive agreements.

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

Steven A. Webster, the Chairman of our board of directors, is the Co-Managing Partner of Avista Capital Holdings, L.P., or Avista, a private equity firm that makes investments in the energy sector, and is also Chairman of Carrizo Oil & Gas, Inc. Robert L. Cabes, Jr. and Jeffrey P. Gunst, two of our directors, serve as Principal and Vice President of Avista, respectively. Messrs. Webster, Cabes and Gunst provide consulting services to certain DLJ Merchant Banking portfolio companies through arrangements with MB Advisory Partners, LLC, an affiliate of Avista. In addition, Sylvester P. Johnson, IV serves as President, Chief Executive Officer and a director of Carrizo. F. Gardner Parker is a director of Carrizo and Susan Schnabel is a Managing Director of DLJ Merchant Banking. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our stockholders' best interest.

In addition, our certificate of incorporation limits the fiduciary duties of our directors in conflict of interest situations, among other things. Please see "Description of Capital Stock—Related Party Transactions and Corporate Opportunities."

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

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

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

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

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

Our drilling locations are spaced primarily using 80-acre spacing. Producing wells located on the 80-acre spacing units contiguous with our drilling locations may drain the acreage underlying our wells. If a substantial number of productive wells are drilled on spacing units adjacent to our properties, it

could have an adverse impact on the economically recoverable reserves of our properties that are susceptible to such drainage.

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

We expect to make substantial capital expenditures in the development of natural gas reserves. For 2006, we had a total capital expenditure budget for drilling and completion (excluding acquisitions) of approximately $36.3 million. Our 2007 total capital expenditure budget for drilling and completion, the construction of related gas and water infrastructure and certain other development costs is approximately $52.6 million.

In general, we intend to finance our capital expenditures in the future through cash flow from operations and the incurrence of indebtedness. Our business may not continue to generate cash flow at or above current levels. Future cash flows and the availability of financing will be subject to a number of variables such as:

•: the level of production from existing wells;
•: prices of natural gas and oil;
•: our results in locating and producing new reserves;
•: the success and timing of development of proved undeveloped reserves; and
•: general economic, financial, competitive, legislative, regulatory and other factors beyond our control.

If we are unable to fund our planned activities with the combination of cash flow from operations and availability under our credit facility, we may have to obtain additional financing through the issuance of debt and/or equity. Any additional financing may not be available to us on acceptable terms. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our stockholders. The level of our debt financing could also materially affect our operations and significantly affect our financial risk profile.

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

Our credit facility imposes restrictions on us that may affect our ability to successfully operate our business.

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

•: incur additional indebtedness;
•: create liens;
•: sell our assets or consolidate or merge with or into other companies;
•: make investments and other restricted payments, including dividends; and
•: engage in transactions with affiliates.

These limitations are subject to a number of important qualifications and exceptions. In addition, our credit facility requires us to maintain certain financial ratios and to satisfy certain financial conditions which may require us to reduce our debt or to take some other action in order to comply with them. These restrictions could also limit our ability to obtain future financings, make needed

capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our credit facility. In addition, we are required to eliminate scheduled title defects within periods specified on or prior to August 12, 2007, and the failure to eliminate all of these title defects would result in an event of default under the credit facility. On March 9, 2007, we notified the lenders that we would be unable to comply with the initial deadline for the first phase of the curative title work and received a waiver from the lenders. Certain phase one curative title work has not been completed but we expect to receive an extension of the waiver. Failure to obtain an extension would result in an event of default under the credit facility. Please see "Management's Discussion and Analysis of Results of Operations and Financial Condition—Liquidity and Capital Resources—Credit Facility" for a discussion of our credit facility.

Because we are relatively small, management expects that we will be disproportionately negatively impacted by recently enacted changes in the securities laws and regulations, which are likely to increase our costs and require additional management resources.

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

As directed by Section 404 of the Act, the SEC adopted rules requiring public companies to include a report of management on the company's internal control over financial reporting in their annual reports on Form 10-K that contains an assessment by management of the effectiveness of the company's internal control over financial reporting. In addition, the public accounting firm auditing the company's financial statements must attest to and report on management's assessment of the effectiveness of the company's internal control over financial reporting. This requirement will first apply to our annual report on Form 10-K for the fiscal year ended December 31, 2008. If management is unable to conclude that we have effective internal control over financial reporting, or if our independent auditors are unable to provide us with an unqualified report as to the effectiveness of our internal control over financial reporting, investors could lose confidence in the reliability of our financial statements, which could result in a decrease in the value of our securities. We are a small company with limited resources. The number and qualifications of our finance and accounting staff are limited, and we have limited monetary resources. We experience difficulties in attracting qualified staff with requisite expertise due to our profile and a generally tight market for staff with expertise in these areas. We plan to retain a consultant to assist us in the process of testing and evaluating our internal control over financial reporting. A key risk is that management will not timely remediate any deficiencies that may be identified as part of the review process.

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

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

After this offering, DLJ Merchant Banking will beneficially own approximately 32.5% of our outstanding common stock. Accordingly, DLJ Merchant Banking is in a position to have a substantial

influence on the outcome of certain matters requiring a stockholder vote, including the election of directors and the adoption of certain amendments to our certificate of incorporation.

In addition, Carrizo will beneficially own approximately 8.2% of our outstanding common stock after this offering. DLJ Merchant Banking and Carrizo's combined ownership of in excess of 40% of our common stock could have the effect of delaying or preventing a change in control of or otherwise discouraging a potential acquirer from attempting to obtain control of us. Please see "Security Ownership of Certain Beneficial Owners and Management" and "Certain Relationships and Related Party Transactions—Transactions with Our Founders" for further information regarding these relationships. In addition, the interests of these stockholders may differ from those of our other stockholders, and these stockholders may vote their common stock in a manner that may adversely affect our other stockholders.

Risks Relating to this Offering and Our Common Stock

Certain stockholders' shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our common stock to drop significantly.

The 3,750,000 shares of common stock (4,312,500 shares if the underwriters exercise their over-allotment option in full) we, and if the underwriters exercise their over-allotment option, the selling stockholders, are selling in this offering will be freely tradable without restriction under the Securities Act. All of the remaining shares of our common stock are subject to either 180-day or 60-day lockup arrangements and are "restricted securities" within the meaning of the Securities Act, which means they generally may not be sold unless they are registered under the Securities Act or are sold pursuant to an exemption from registration. However, in connection with our April 2006 private placement, we agreed to use commercially reasonable efforts to file a shelf registration statement with the SEC registering the shares sold in our private placement for resale. We have filed a shelf registration statement with the SEC which will register all of the outstanding shares of our common stock (other than those sold in this offering and shares of restricted common stock issued to our non-employee directors and certain of our employees under our stock incentive plan) for resale, although this shelf registration statement has not been declared effective. We expect that the shelf registration statement will be declared effective subsequent to this offering. Upon the effectiveness of this shelf registration statement and the expiration of the applicable lockup periods, 25,104,031 shares of our common stock (24,541,531 shares if the underwriters exercise their over-allotment option in full) will be eligible for sale in the public market and freely tradeable without restriction under the Securities Act. The market price of our common stock could drop significantly if the holders of these formerly restricted shares sell them, or are perceived by the market as intending to sell them.

As soon as practicable after this offering, we intend to file one or more registration statements with the SEC on Form S-8 providing for the registration of up to 2,750,000 shares of our common stock issued or reserved for issuance under our stock incentive plan. Subject to the exercise of unexercised options or the expiration or waiver of vesting conditions for restricted stock and the expiration of lockups we and certain of our stockholders have entered into, shares registered under these registration statements on Form S-8 will be available for resale immediately in the public market without restriction.

There is no existing market for our common stock, and a trading market that will provide you with adequate liquidity may not develop.

Prior to this offering, there has been no public market for our common stock. Our common stock has been approved for listing on The NASDAQ Global Market, subject to official notice of issuance. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Negotiations between the underwriters and us will determine the initial public offering price. You may not be able to resell your shares of our common stock at or above

the initial public offering price or at all. Because of this potentially limited liquidity, it is unlikely that shares of our common stock will be accepted as collateral for loans. We cannot assure you as to:

•: the likelihood that an active market will develop for the shares of our common stock;
•: the liquidity of any such market;
•: the ability of our stockholders to sell their shares of our common stock; or
•: the price that our stockholders may obtain for their shares of our common stock.

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

Regardless of whether an active trading market for our common stock develops, the market price of our common stock may be volatile and you may not be able to resell your shares at or above the price you paid for such shares. The following factors could affect our stock price:

•: our operating and financial performance and prospects;
•: quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
•: changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry;
•: potentially limited liquidity;
•: actual or anticipated variations in our reserve estimates and quarterly operating results;
•: changes in natural gas and oil prices;
•: speculation in the press or investment community;
•: sales of our common stock by significant stockholders and future issuances of our common stock;
•: actions by institutional investors before disposition of our common stock;
•: increases in our cost of capital;
•: changes in applicable laws or regulations, court rulings and enforcement and legal actions;
•: commencement of or involvement in litigation;
•: announcements by us or our competitors of strategic alliances, significant contracts, new technologies, acquisitions, commercial relationships, joint ventures or capital commitments;
•: changes in market valuations of similar companies;
•: adverse market reaction to any increased indebtedness we incur in the future;
•: additions or departures of key management personnel;
•: actions by our stockholders;
•: general market conditions, including fluctuations in and the occurrence of events or tends affecting the price of natural gas and oil; and
•: domestic and international economic, legal and regulatory factors unrelated to our performance.

Purchasers of common stock will experience immediate and substantial dilution of $5.58 per share.

Based on an assumed initial public offering price of $11.00 per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $5.58 per share in the net

tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of December 31, 2006 after giving effect to this offering would be $5.42 per share. Please read "Dilution" for a complete description of the calculation of net tangible book value.

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

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

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

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

•: authorize the issuance of blank check preferred stock that could be issued by our board of directors to thwart a takeover attempt;
•: classify the board of directors into staggered, three-year terms, which may lengthen the time required to gain control of our board of directors;
•: prohibit cumulative voting in the election of directors, which would otherwise allow holders of less than a majority of stock to elect some directors;
•: require super-majority voting by our stockholders to effect amendments to provisions of our certificate of incorporation concerning the number of directors;
•: require super-majority voting by our stockholders to effect any stockholder-initiated amendment to any provision of our bylaws;
•: limit who may call special meetings of our stockholders;
•: prohibit stockholder action by written consent, thereby requiring all actions to be taken at a meeting of the stockholders;
•: establish advance notice requirements for stockholder nominations of candidates for election to the board of directors or for stockholder proposals that can be acted upon at annual meetings of stockholders; and
•: require that vacancies on the board of directors, including newly-created directorships, be filled only by a majority vote of directors then in office.

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

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

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the board of directors deems relevant. The terms of our credit facility restrict the payment of dividends without the prior written consent of the lenders. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.

USE OF PROCEEDS

We expect to receive net proceeds from this offering of approximately $37.7 million, assuming an initial public offering price of $11.00 per share and after deducting underwriting discounts and commissions and estimated offering expenses. We will not receive any of the net proceeds from the sale of shares of common stock by the selling stockholders if the over-allotment is exercised.

We plan to use all of the net proceeds we receive from this offering:

•: to pay down all of the outstanding indebtedness under our credit facility; and
•: for accelerated capital expenditures, infrastructure development and general corporate purposes.

An increase or decrease in the assumed initial public offering price of $1.00 per share would cause the net proceeds from this offering, after deducting underwriting discounts and commissions and estimated offering expenses, to increase or decrease by approximately $3.3 million.

The amount outstanding under our credit facility as of April 25, 2007 was $7.0 million. The outstanding borrowings under our credit facility were used to fund our drilling program. Borrowings under the credit facility may be either (i) a domestic bank rate plus an applicable margin between 0.25% and 1.25% per annum based on utilization, or (ii) the London interbank offered rate, or LIBOR, plus an applicable margin between 1.25% and 2.25% per annum based on utilization. As of March 31, 2007, the interest rate under our credit facility was 6.57%. The credit facility matures on February 12, 2011.

DIVIDEND POLICY

We do not expect to pay dividends on our common stock in the foreseeable future. In addition, our credit facility prohibits the payment of dividends to stockholders without the prior written consent of the lenders. Our board of directors has the authority to issue preferred stock and to fix dividend rights that may have preference to our common stock.

CAPITALIZATION

The following table presents our capitalization as of December 31, 2006:

•: on an actual basis; and
•: on an as adjusted basis to give effect to this offering and the application of our estimated net proceeds from this offering as set forth under "Use of Proceeds" as if each had occurred on December 31, 2006.

The information was derived from and is qualifed by reference to our financial statements included elsewhere in this prospectus. You should read this information in conjunction with these consolidated financial statements, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Use of Proceeds."

		As of December 31, 2006
		Actual			As Adjusted
		(unaudited) (in thousands)
Cash and cash equivalents		$	4,762		$	42,432

Long-term debt(1)			786			786
Preferred stock, $0.01 par value, 25,000,000 authorized shares; none issued and outstanding			0			0
Common stock, $0.01 par value, 100,000,000 authorized shares; 25,131,301 shares issued and outstanding; 28,881,301 shares issued and outstanding, as adjusted(2)			251			289
Additional paid-in capital			119,354			156,986
Retained earnings (accumulated deficit)			(776	)		(776	)

	Total capitalization	$	119,615		$	157,285

(1): As of December 31, 2006, we had no indebtedness outstanding under our old credit facility. Effective February 12, 2007, we entered into a new revolving credit facility for $100 million, but with an initial commitment of $27 million, of which $16.7 million was available as of March 31, 2007. Simultaneously with entering into the new credit facility, we terminated our previous credit facility. As of April 25, 2007, we had $7.0 million in indebtedness outstanding under our new credit facility. We plan to use a portion of the net proceeds to pay down all of the outstanding indebtedness under our new credit facility.
(2): The number of shares as adjusted as of December 31, 2006 does not include 47,000 shares of restricted stock that were granted to non-employee directors and certain employees during 2007.

DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Net tangible book value per share represents the amount of the total tangible assets less our total liabilities, divided by the number of shares of common stock that will be outstanding. At December 31, 2006, we had a net tangible book value of $118.8 million, or $4.73 per share of outstanding common stock. After giving effect to the sale of 3,750,000 shares of common stock by us in this offering at the assumed initial public offering price of $11.00 per share and after the deduction of underwriting discounts and commissions and estimated offering expenses, the as adjusted net tangible book value at December 31, 2006 would have been $156.5 million or $5.42 per share. This represents an immediate increase in such net tangible book value of $0.69 per share to existing stockholders and an immediate and substantial dilution of $5.58 per share to new investors purchasing common stock in this offering. The following table illustrates this per share dilution:

Assumed initial public offering price per share				$	11.00
	Net tangible book value per share as of December 31, 2006	$	4.73
	Increase attributable to new public investors	$	0.69
As adjusted net tangible book value per share after this offering				$	5.42

Dilution in as adjusted net tangible book value per share to new investors				$	5.58

The following table summarizes, on an as adjusted basis set forth above as of December 31, 2006, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $11.00, calculated before deduction of estimated underwriting discounts and commissions.

		Shares Purchased(1)			Total Consideration
		Shares Purchased(1)			Total Consideration				Average Price Per Share
		Number	Percent		Amount		Percent		Average Price Per Share
		(in thousands)
Existing Stockholders(2)		25,131,301	87	%	$	167,600	80.3	%	$	6.67
New Public Investors		3,750,000	13	%		41,300	19.7	%		11.00

	Total	28,881,301	100.0	%	$	208,900	100.0	%	$	7.23

(1): The number of shares disclosed for the existing stockholders includes 562,500 shares proposed to be sold by the selling stockholders in this offering if the over-allotment option is exercised in full. The number of shares disclosed for the new investors does not include the 562,500 shares that may be purchased by the new investors from the selling stockholders in this offering if the over-allotment option is exercised in full.
(2): The number of shares outstanding as of December 31, 2006 does not include 47,000 shares of restricted stock that were granted to non-employee directors and certain employees during 2007.

If the over-allotment option is exercised in full, the number of shares of common stock held by existing stockholders will be reduced to 24,568,801, or approximately 85.1% of the total number of shares of common stock outstanding after this offering. Sales of common stock by us and by the selling stockholders, if the over-allotment is exercised in full, will increase the number of shares of common stock held by new investors to 4,312,500, or approximately 14.9% of the total number of shares of common stock outstanding after this offering.

As of March 31, 2007, there were 25,178,301 shares of our common stock outstanding held by approximately 17 stockholders of record and approximately 140 beneficial owners.

SELECTED FINANCIAL DATA

The following tables set forth our selected historical financial data for, and as of the end of, each of the periods indicated. The statement of operations, statement of cash flows and other financial data for the period from inception (June 23, 2003) to December 31, 2003, and the balance sheet data as of December 31, 2004, are derived from our audited financial statements not included in this prospectus. The statement of operations, statement of cash flows and other financial data for the years ended December 31, 2004, 2005 and 2006, and the balance sheet data as of December 31, 2005 and 2006, are derived from our audited financial statements included elsewhere in this prospectus.

Our historical results are not necessarily indicative of the results that may be expected for any future period. The selected historical financial data should be read in conjunction with "Management's Discussion and Analysis of Results of Operations and Financial Condition" and our financial statements and related notes included elsewhere in this prospectus.

			Period from Inception (June 23) to December 31,			Year Ended December 31,
			2003			2004			2005			2006
			(in thousands, except share and per share data)
Statement of Operations Data:
Revenues
	Gas sales		$	1,679		$	7,393		$	14,136		$	12,196
	Income from earn-in joint venture agreement			41			368			1,629			379
	Gains (losses) on derivatives			—			(766	)		(4,815	)		7,362

		Total revenues		1,720			6,995			10,950			19,937
Operating expenses
	Lease operating expenses			772			1,445			1,781			2,993
	Production taxes			186			838			1,637			1,198
	Marketing and transportation			299			1,218			1,582			1,962
	General and administrative, net			729			1,552			2,267			4,343
	Organization costs			311			—			—			—
	Depreciation, depletion, amortization and accretion			850			3,328			5,622			6,673

		Total operating expenses		3,147			8,381			12,889			17,169

Operating income (loss)				(1,427	)		(1,386	)		(1,939	)		2,768
Other income (expense)
	Interest income			33			61			17			720
	Other income			3			4			129			484
	Unrealized derivative loss			—			—			—			(26	)
	Interest expense			—			(2	)		(47	)		(168	)

		Total other income (expense)		36			63			99			1,010

Net income (loss)				(1,391	)		(1,323	)		(1,840	)		3,778
Preferred dividends, related party				(719	)		(2,623	)		(5,409	)		(20,964	)

Net income (loss) attributable to common stockholders			$	(2,110	)	$	(3,946	)	$	(7,249	)	$	(17,186	)

Net income (loss) per common share
	Basic and diluted		$	(0.42	)	$	(0.79	)	$	(1.42	)	$	(0.87	)
Weighted average shares outstanding
	Basic and diluted(1)			5,000,000			5,000,000			5,094,800			19,783,118

(1): For all periods presented, all of our stock options and warrants were anti-dilutive as a result of the losses incurred. Common stock equivalents of 4,965,000, 9,187,500, 13,676,200 and 1,035,000 at December 31, 2003, 2004, 2005 and 2006, respectively, were excluded because they were anti-dilutive.

	Period from Inception (June 23) to December 31,			Year Ended December 31,
	2003			2004			2005			2006
	(in thousands)
Statement of Cash Flows Data:
Net cash provided (used) by operating activities	$	1,315		$	1,350		$	8,792		$	6,029
Net cash provided (used) by investing activities		(14,313	)		(14,017	)		(25,301	)		(63,880	)
Net cash provided (used) by financing activities		17,524			11,740			15,582			59,941
Other Financial Data:
Capital expenditures—exploration and production	$	13,977		$	13,149		$	20,866		$	62,340
Adjusted EBITDA(1)		(574	)		2,584			7,016			3,226

(1): Adjusted EBITDA is defined as earnings (loss) before deducting net interest expense (interest expense less interest income), income taxes, depreciation, depletion and amortization, cumulative effect of accounting change, change in unrealized derivative value, asset retirement obligation accretion and gains on sale of assets. Reconciliations of this non-GAAP financial measure to net income (loss) and net cash provided by operating activities are presented under "Summary—Summary of Financial Data—Reconciliation of Non-GAAP Financial Measures."

	As of December 31,
	2004		2005		2006
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	3,599	$	2,672	$	4,762
Property and equipment, net		43,054		63,529		127,189
Total assets		54,504		77,081		150,332
Long-term debt (including current portion)(1)		345		926		807
Total liabilities		13,817		23,897		31,503
Redeemable preferred stock(2)		18,338		31,400		—
Total stockholders' equity	$	22,349	$	21,784	$	118,829

(1): Long-term debt does not include fair value of derivatives, asset retirement obligation and the long-term portion of production taxes.
(2): On April 11, 2006, we used approximately $53.6 million of the net proceeds from our private placement to redeem all of the outstanding shares of our Series A Redeemable Preferred Stock, all of which were held by DLJ Merchant Banking.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION

The discussion and analysis that follows should be read together with the "Selected Financial Data" and the accompanying financial statements and notes related thereto that are included elsewhere in this prospectus. It includes forward-looking statements that may reflect our estimates, beliefs, plans and expected performance. The forward-looking statements are based upon events, risks and uncertainties that may be outside our control. Our actual results could differ significantly from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include but are not limited to, market prices for natural gas and oil, regulatory changes, estimates of proved reserves, economic conditions, competitive conditions, development success rates, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, including in "Risk Factors" and "Cautionary Statement Concerning Forward-Looking Statements," all of which are difficult to predict. As a result of these assumptions, risks and uncertainties, the forward-looking matters discussed may not occur.

Overview

We are an independent energy company engaged in the acquisition, exploration and development of domestic onshore natural gas reserves. We primarily focus our efforts on the development of CBM properties located in the Powder River Basin in northeastern Wyoming and southern Montana. In addition, in April 2006, we acquired properties located in the Green River Basin in southern Wyoming. As of December 31, 2006, we owned natural gas and oil leasehold interests in approximately 454,000 gross (308,000 net) acres, approximately 92% of which are undeveloped. As of December 31, 2006, our estimated net proved reserves were located on approximately 8% of our net acreage. We drilled 230 gross (139 net) wells during the year ended December 31, 2006, and we operated 514 gross (277 net) of those wells. We incurred capital expenditures of $68.5 million during the year ended December 31, 2006, of which $39.9 million was primarily related to drilling, completion and infrastructure costs on our undeveloped acreage in our Kirby, Deer Creek, Cabin Creek and Green River Basin areas and the remaining $28.6 million was related to acquisitions, including $27.0 million for our Green River Basin acquisition.

In June 2003, we were formed as a Delaware corporation through a contribution of interests in approximately 81,000 gross (40,000 net) acres, including proved producing properties and undeveloped leaseholds, from subsidiaries of Carrizo and U.S. Energy and a cash contribution from DLJ Merchant Banking. In exchange for the contributed assets, Carrizo and U.S. Energy each received 1,875,000 shares of our common stock and options to purchase an additional 1,250,000 shares of our common stock. In exchange for its initial cash contribution of approximately $17.6 million, DLJ Merchant Banking received 1,250,000 shares of our common stock as well as 130,000 shares of our Series A Redeemable Preferred Stock, with detachable warrants to purchase an additional 3,250,000 shares of common stock. Through three subsequent financings totaling approximately $26.5 million, DLJ Merchant Banking purchased an additional 270,000 shares of our Series A Redeemable Preferred Stock and additional detachable warrants to purchase 7,500,000 shares of our common stock.

In April 2006, we completed a private placement, exempt from registration under the Securities Act, of 12,835,230 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors at a price of $11.00 per share, or $10.23 net of the initial purchaser's discount and placement fee. Immediately prior to the initial closing of our private placement, DLJ Merchant Banking exchanged all of its warrants for 6,894,380 shares of our common stock in a tax-free reorganization and each of Carrizo and U.S. Energy entered into a cashless exercise of all of its options for 584,102 shares of common stock, in each case based on the private placement price of $11.00 per share. Out of the aggregate of approximately $129.9 million of net proceeds (after expenses) we received in the private placement, we used (i) approximately $53.6 million to redeem all of the outstanding shares of our Series A Redeemable Preferred Stock, including the payment of all accrued

and unpaid dividends and a redemption premium, (ii) approximately $27.0 million for our acquisition of the Green River Basin assets and (iii) approximately $16.3 million to repurchase an aggregate of 1,593,783 shares of common stock at a price of $10.23 per share from DLJ Merchant Banking and Gary W. Uhland, our former President. We used the remaining approximately $33.0 million of net proceeds to fund our development drilling program and pay additional offering expenses and for general corporate purposes. Please see "—Liquidity and Capital Resources—Cash Flow from Financing Activities—Sales and Issuances of Equity" and "Certain Relationships and Related Party Transactions—Transactions with Our Founders" for further information regarding issuances of our capital stock, options and warrants to our initial stockholders.

Recent Developments

Effective January 1, 2007, we sold a 50% working interest in approximately 3,972 undeveloped acres in Wyoming.

Effective February 12, 2007, we entered into a new $100 million credit facility with an initial commitment of $27 million which permits borrowings up to the borrowing base as designated by the administrative agent. As of March 31, 2007, the initial borrowing base was $22 million although our borrowing availability is less than our initial borrowing base due to covenant limitations. As of March 31, 2007, the actual borrowing availability was $16.7 million. At March 31, 2007, we had $4.5 million of outstanding borrowings under our new credit facility. Please see "—Liquidity and Capital Resources—Credit Facility" for further information.

Critical Accounting Policies

The most subjective and complex judgments used in the preparation of our financial statements are:

•: Reserve evaluation and determination.
•: Estimates of the timing and cost of our future drilling activity.
•: Estimates of the fair valuation of hedges in place.
•: Estimates of timing and cost of asset retirement obligations.
•: Estimates of the expense and timing of exercise of stock options.
•: Accruals of operating costs, capital expenditures and revenue.
•: Estimates for litigation.

Oil and Gas Properties

We use the full cost method of accounting for oil and gas producing activities. Under this method, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, are capitalized within a cost center. Our oil and gas properties are all located within the United States, which constitutes a single cost center. We have not capitalized any overhead costs. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of gas properties and the gain significantly alters the relationship between capitalized costs and proved gas reserves of the cost center. Expenditures for maintenance and repairs are charged to lease operating expense in the period incurred.

Depreciation, depletion and amortization of oil and gas properties is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of future

development costs of proved undeveloped reserves and asset retirement obligations. We invest in unevaluated oil and gas properties for the purpose of exploration for proved reserves. The costs of such assets, including exploration costs on properties where a determination of whether proved oil and gas reserves will be established is still under evaluation, and any capitalized interest, are included in unproved oil and gas properties at the lower of cost or estimated fair market value and are not subject to amortization. On an annual basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonment of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized. We recorded an impairment of unevaluated properties of $0, $0 and $695,000 during the years ended December 31, 2006, 2005 and 2004, respectively. Substantially all of such unproved property costs are expected to be developed and included in the amortization base ratably over the next three to five years. Salvage value is taken into account in determining depletion rates and is based on our estimate of the value of equipment and supplies at the time the well is abandoned. The estimated salvage value of equipment included in determining the depletion rate was $5,736,000, $3,306,000 and $741,000 as of December 31, 2006, 2005 and 2004, respectively.

Under the full cost method of accounting, capitalized oil and gas property costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, may not exceed a "ceiling" value comprised of the total of the present value of future net revenues from proved reserves, using current costs and prices, including the effects of derivative instruments accounted for at the fair value but excluding the future cash outflow associated with settling asset retirement obligations that have been accrued on the balance sheet, discounted at 10%, plus the lower of cost or market value of unproved properties and unevaluated properties excluded from costs being amortized, net of related income tax effects related to differences in the book and tax basis of oil and gas properties. At December 31, 2006, the capitalized cost of gas properties exceeded the ceiling value by approximately $13.0 million based upon a natural gas price of approximately $4.46 per Mcf in effect at that date. However, based on subsequent price increases to approximately $5.41 per Mcf of gas at April 18, 2007, the full cost ceiling limitation exceeded the carrying amount of our oil and gas properties by approximately $1.1 million. Therefore, we were not required to record a ceiling write-down as of December 31, 2006. A decline in gas prices or an increase in operating costs subsequent to the measurement date or reductions in the economically recoverable quantities could result in the recognition of a ceiling write-down of our gas properties in a future period.

Gas Sales

We use the sales method for recording natural gas sales. Sales of gas applicable to our interest in producing natural gas and oil leases are recorded as revenues when the gas is metered and title transferred pursuant to the gas sales contracts covering our interest in gas reserves. During such times as our sales of gas exceed our pro rata ownership in a well, such sales are recorded as revenues unless total sales from the well have exceeded our share of estimated total gas reserves underlying the property at which time such excess is recorded as a gas imbalance liability. At December 31, 2006, 2005 and 2004, there was no such liability recorded. Although there was no such liability recorded for prior periods, gas reserves are an estimate and are updated on an annual and interim basis. Gas pricing, expenses and production may impact future gas reserves remaining which in turn, could impact the recording of liabilities in the future. Gas sales accrual at December 31, 2006 and 2005 were based on the actual volume statements from our purchasers and distribution process. If accruals were to change by 10% at year end, the impact would have been a $319,000 change for 2006 and a $162,000 change for 2005.

Asset Retirement Obligations

We follow the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for the Asset Retirement Obligations." SFAS No. 143 generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires us to recognize an estimated liability for costs associated with the abandonment of our oil and gas properties.

A liability for the fair value of an asset retirement obligation with a corresponding increase to the carrying value of the related long-lived asset is recorded at the time a well is completed or acquired. The increased carrying value is depleted using the units-of-production method, and the discounted liability is increased through accretion over the remaining life of the respective oil and gas properties.

The estimated liability is based on historical gas industry experience in abandoning wells, including estimated economic lives, external estimates as to the cost to abandon the wells in the future and federal and state regulatory requirements. Our liability is discounted using our best estimate of our credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in estimated abandonment costs, changes in well economic lives or if federal or state regulators enact new requirements regarding the abandonment of wells. For example, a 10% change in our estimated retirement costs would have a $193,000 effect on our asset retirement obligation liability.

Changes in the carrying amount of the asset retirement obligations are as follows:

		Year Ended December 31,
		2006			2005			2004
		(in thousands)
Beginning balance of asset retirement obligations		$	1,277		$	554		$	404
	Additional obligation added during the period		953			186			128
	Obligations settled during the period		(2	)		(3	)		(31	)
	Revisions in estimates		(69	)		470			—
	Accretion expense		162			70			53

Ending balance of asset retirement obligations		$	2,321		$	1,277		$	554

Inventory

We acquired inventory of oil and gas equipment, primarily tubulars, in 2006 and 2005, to take advantage of quantity pricing and to secure a readily available supply. Inventory is valued at the lower of average cost or market. Inventory is used in the development of gas properties and to the extent it is estimated that it will be billed to other working interest owners during the next year, it is included in current assets. Otherwise, it is recorded in other assets. The price of steel is a primary factor in valuing our inventory. Under the valuation method of lower of average cost or market, a 10% reduction in the price of steel would cause a $92,000 reduction in our inventory valuation as of December 31, 2006. The market price of steel is evaluated each quarter using prices quoted by authorized vendors in the area.

Property and Equipment

Property and equipment is comprised primarily of a building, computer hardware and software, vehicles and equipment, and is recorded at cost. Renewals and betterments that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed when incurred. Depreciation and amortization are provided using the straight-line method over the estimated useful lives of the assets, ranging as follows: buildings—30 years, computer hardware and software—3 to 5 years, machinery, equipment and vehicles—5 years, and office furniture and equipment—3 to 5 years.

Long-Lived Assets

Long-lived assets to be held and used in our business are reviewed for impairment whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable. When the carrying amounts of long-lived assets exceed the fair value, which is generally based on discounted expected future cash flows, we record an impairment. No impairments were recorded during the years ended December 31, 2006, 2005 and 2004.

General and Administrative Expenses

General and administrative expenses are reported net of amounts allocated and billed to working interest owners of gas properties operated by us. The administrative expenses billed to working interest owners may change in accordance with the terms of the joint operating agreements. Administrative expenses are charged to working interest owners based on productive well counts. A 10% change in well counts for the year ended December 31, 2006 would have increased or decreased our expenses billed to working interest owners by approximately $121,000. As we operate and drill additional wells in the future, additional administrative expenses will be charged to the working interest owners when the wells become productive.

Income Taxes

We use the asset and liability method of accounting for income taxes, in accordance with SFAS No. 109, "Accounting for Income Taxes." Deferred tax assets and liabilities are recognized for the expected future tax consequences of temporary differences between the financial statement and tax bases of assets and liabilities. If appropriate, deferred tax assets are reduced by a valuation allowance which reflects expectations of the extent to which such assets will be realized. As of December 31, 2006, 2005 and 2004 we had recorded a full valuation allowance for our net deferred tax asset.

Derivatives

We use derivative instruments to manage our exposure to fluctuating natural gas prices through the use of natural gas swap and option contracts. We account for derivative instruments or hedging activities under the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires us to record derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings. Please see Note 8 of the notes to our audited financial statements for additional discussions of derivatives.

We periodically hedge a portion of our oil and gas production through swap and collar agreements. The purpose of the hedges is to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. Our management decided not to use hedge accounting for these agreements. Therefore, in accordance with the provisions of SFAS No. 133, the changes in fair market value are recognized in earnings.

Stock-Based Compensation

Effective January 1, 2006, we adopted SFAS No. 123(R), "Share-Based Payments," which requires companies to recognize compensation expense for share-based payments based on the estimated fair value of the awards.

SFAS No. 123(R) also requires that the benefits of tax deductions in excess of compensation cost recognized for stock awards and options ("excess tax benefits") be presented as financing cash inflows in the Statement of Cash Flows. Prior to January 1, 2006, we accounted for share-based payments

under the recognition and measurement provisions of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations, as permitted by SFAS No. 123, "Accounting for Stock-Based Compensation." In accordance with APB No. 25, no compensation cost was required to be recognized for options granted that had an exercise price equal to or greater than the market value of the underlying common stock on the date of the grant.

During 2005 and 2006, we granted options to certain of our officers and employees with exercise prices ranging from $4.80 to $11.00 per share. Although we did not obtain contemporaneous valuations performed by an unrelated valuation specialist, we believe that at the time of each grant, the exercise price of the options granted was greater than the fair value of the underlying shares of common stock. In each case, the primary factors in our determination of the fair value of the underlying shares of common stock were (1) the PV-10 value of our estimated net proved reserves, as determined by our independent petroleum engineers in the most recent reserve report available at the time of each grant, (2) the estimated fair market value of the undeveloped acreage in Montana that was contributed to us at inception, (3) the fair market value of the undeveloped acreage in Montana and Wyoming we acquired in March 2005 from Marathon Oil, which was determined through an arms'-length bidding and negotiation process, and (4) the liability relating to the redemption of our Series A Redeemable Preferred Stock. For each grant made prior to the date of our private offering, our valuation methodology indicated a fair value for the underlying shares of common stock of less than the price obtained in our private offering; each grant made subsequent to the private offering had an exercise price equal to the price obtained in our private offering. We believe that we were able to obtain a price of $11.00 in our private offering in part because the offering generated proceeds sufficient to (a) redeem all of our Series A Redeemable Preferred Stock and thereby eliminate the substantial redemption liability on a going-forward basis and (b) fund our 2006 drilling program without seeking additional dilutive capital contributions from our founding stockholders. A valuation of our shares of common stock by an unrelated valuation specialist was not required or requested by our board of directors, which approved each grant.

We are required to adopt the prospective method for grants prior to January 1, 2006 as we had elected to value employee grants using the minimum value method under SFAS No. 123. For option grants and restricted stock accounted for under the prospective method, we will continue to account for the grants under the intrinsic value-based method prescribed by APB No. 25 and the related interpretations in accounting for stock options. Therefore, we do not record any compensation expense for stock options granted to employees prior to January 1, 2006 if the exercise price equaled the fair market value of the stock option on the date of the grant, and the exercise price, the number of shares eligible for issuance under the options, and vesting period are fixed.

Under SFAS No. 123(R), compensation expense for all share-based payments granted subsequent to January 1, 2006, based on the estimated grant date fair value, has been recorded in the year ended December 31, 2006. Results for prior periods have not been retroactively adjusted. For prior periods, we applied APB No. 25 and related interpretations, and provided the required pro forma disclosures under SFAS No. 123, "Accounting for Stock-Based Compensation." We record compensation expense related to non-employees under the provisions of SFAS No. 123 and Emerging Issues Task Force EITF 96-18 "Accounting for Equity Instruments that are Issued to Other than Employees for Acquiring, or in conjunction with Selling Goods or Services" and recognize compensation expense over the vesting periods of such awards.

We have computed the fair value of options granted using the Black-Scholes option pricing model. In order to calculate the fair value of the options, certain assumptions are made regarding components of the model, including risk-free interest rate, volatility, expected dividend yield, and expected option life. Changes to the assumptions could cause significant adjustments to valuation. For options granted before January 1, 2006, expected volatility was not considered because we were a private company at the grant date of these options. For stock option grants after January 1, 2006, we used a volatility rate of 35% and began to include estimated forfeiture rates. We estimated the volatility rate of our common

stock at the date of the grant based on the historical volatility of comparable companies. We factored in expected retention rates combined with vesting periods to determine the average expected life. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of the grant. Accordingly, we have computed the fair value of all options granted during the years ended December 31, 2006, 2005 and 2004 (2005 and 2004 were calculated for disclosure purposes only) using the Black-Scholes option pricing model and the following weighted average assumptions.

	Year Ended December 31,
	2006	2005	2004
Expected Volatility	35%	0%	0%
Dividend Yield	—	—	—
Risk Free Interest Rate	4.30% to 5.03%	3.46% to 4.44%	2.71% to 3.90%
Weighted Average expected life (in years)	5	5	5

Accounts Receivable

Our revenue producing activities are conducted primarily in Wyoming. We grant credit to qualified customers, which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industry in which we operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and, if necessary, record an allowance for doubtful accounts based upon historical experience and any specific customer collection issues identified. We recorded $100,000, $0 and $0 at December 31, 2006, 2005 and 2004, respectively.

Transportation Costs

We account for transportation costs under Emerging Issues Task Force Issues 00-10, "Accounting for Shipping and Handling Fees and Costs," whereby amounts paid for transportation are classified as operating expenses.

Per Share Information

Basic earnings per share is computed by dividing net losses from continuing operations attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents such as stock options and warrants. Common stock equivalents of 1,035,000, 13,676,200 and 9,187,500 at December 31, 2006, 2005 and 2004, respectively, were excluded because they were anti-dilutive due to the losses incurred in all periods presented.

New Accounting Pronouncements

In February 2006, SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments—an Amendment of FASB Statements No. 133 and 140" was issued. This statement resolves issues addressed in Statement 133 Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interests in Securitized Financial Assets." SFAS No. 155 became effective January 1, 2007. The impact of SFAS No. 155 will depend on the nature and extent of any new derivative instruments entered into after the effective date.

In July 2006, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 48 ("FIN No. 48"), "Accounting for Uncertainty in Income Taxes, an Interpretation of SFAS No. 109," which clarifies the accounting for uncertainty in income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." FIN No. 48 prescribes a recognition threshold and measurement attribute for the measurement and financial statements recognition of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. Upon adoption, FIN No. 48 will be applied to all tax positions in those tax years for which the tax return statute of

limitations is open. The cumulative effect of the initial application will be reported as an increase or decrease to retained earnings as of the beginning of the period in which it is adopted. The provisions of FIN No. 48 were effective January 1, 2007. We have not yet completed our evaluation of the impact FIN No. 48 will have when adopted. However, we currently believe that its implementation will not have a material impact on our results of operations, financial position or liquidity.

In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements," which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. Accordingly, SFAS No. 157 does not require any new fair value measurements. However, for some entities, the application of SFAS No. 157 will change current practice. The provisions of SFAS No. 157 are effective as of January 1, 2008. We are currently evaluating the impact of adopting SFAS No. 157 on our financial statements.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin (SAB) No. 108 which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. SAB No. 108 is effective for us as of January 1, 2007. We are currently evaluating the impact of SAB No. 108 on our financial statements. However, we currently believe that its implementation will not have a material impact on our results of operations, financial position or liquidity.

In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities." SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The Statement will be effective as of January 1, 2008 for us. The Statement offers various options in electing to apply the provisions of this Statement, and at this time we have not made any decisions in its application to our financial position or results of operations.

Trends Affecting Our Business

We have experienced increasing costs since our inception in 2003 due to increased demand for oilfield products and services. The cyclical nature of the natural gas industry causes fluctuations in demand for goods and services from oilfield companies, suppliers and others associated with the industry, which in turn affects the prices for those goods and services. Typically, as prices for natural gas increase, so do all the costs associated with natural gas production. Recently, we have seen increases in the cost of tubulars, drilling rigs and cement in particular. We expect that increased demand for the goods and services we use in our business will continue to put pressure on prices in the near to medium term.

Historically, natural gas prices have been extremely volatile, and we expect that volatility to continue. For example, during the year ended December 31, 2006, the NYMEX natural gas index price ranged from a high of $11.23 per MMBtu to a low of $4.20 per MMBtu, while the CIG natural gas index price ranged from a high of $7.90 per MMBtu to a low of $1.30 per MMBtu. Changes in natural gas pricing have impacted our revenue streams, production taxes, prices used in reserve calculations, borrowing base calculations and the valuation of potential property acquisitions. During the years ended December 31, 2006, 2005 and 2004, estimated future gas prices had an impact on both our revenues and the costs attributable to our future operations. We expect that changing natural gas prices will continue to impact our operations and financial results in the future.

Transportation of natural gas and access to throughput capacity have a direct impact on natural gas prices in the Rocky Mountain region, where our operations are concentrated. As drilling activity increases throughout the Rocky Mountain region, additional production may come on line, which could cause bottlenecks or capacity constraints. Generally speaking, a surplus of natural gas production relative to available transportation capacity has a negative impact on prices. Conversely, as capacity increases, and bottlenecks are eliminated, prices generally increase. Although there is currently adequate transportation capacity out of the Powder River Basin, a surplus of natural gas arriving at key marketing hubs from the Powder River Basin and elsewhere relative to available takeaway capacity from these hubs has caused Rocky Mountain gas to trade at a discount to the Henry Hub Index. Two major projects that are expected to be completed in 2008 will increase takeaway capacity from these hubs, and we expect that they will therefore help reduce the differential between gas produced in the Rocky Mountain region and the Henry Hub Index.

Results of Operations

Net loss attributable to stockholders for the year ended December 31, 2006 was $17.2 million, or $0.87 per diluted share, on total revenue of $19.9 million. The loss includes preferred stock dividends of $21.0 million, comprised of $1.4 million in cash dividends and $19.6 million related to a redemption premium upon the redemption of preferred stock in the second quarter of 2006. Total revenue for the year ended December 31, 2006 included a $6.7 million unrealized gain associated with the change in the fair valuation of our natural gas hedges in place in accordance with the provisions of SFAS No. 133. Absent such change in the valuation, we would have shown a loss of $23.9 million on revenue of $13.2 million. This compares to a reported net loss attributable to stockholders of $7.2 million for the year ended December 31, 2005 on total revenue of approximately $11.0 million. Adjusted for an unrealized loss in the fair valuation of our natural gas hedges in place of $3.2 million, our results for the year ended December 31, 2005 would have been a net loss attributable to common stockholders of $4.0 million on total revenue of $14.2 million.

Year Ended December 31, 2006 Compared To Year Ended December 31, 2005

Gas sales volume.

Gas sales volume increased 9% in 2006 from 2,207 MMcf in 2005 to 2,413 MMcf in 2006. Daily sales volume was 6.6 MMcf for 2006 as compared to 6.0 MMcf for 2005, a 0.6 MMcf per day increase. The increase was primarily due to initial production coming online in our Cabin Creek project area.

Gas sales revenue.

Revenue from gas sales decreased $1.9 million in 2006 to $12.2 million, a 14% decrease compared to 2005. This decrease was primarily due to a decrease in the average realized price per Mcf, partially offset by increased gas sales volume. The average realized price per Mcf decreased 21% from $6.41 per Mcf in 2005 to $5.05 per Mcf in 2006.

Derivatives.

For the year ended December 31, 2006, we had an unrealized gain of $6.7 million compared to an unrealized loss of $3.2 million for the year ended December 31, 2005. The unrealized gain is a noncash expense based primarily on the Black-Scholes model for valuing future cash flows utilizing price volatility with a normal discount rate. Hedges settled in 2006 resulted in a realized gain of $0.7 million compared to hedge losses of $1.6 million in 2005. The hedge gains were primarily due to the fact that gas prices were lower than our weighted average floor price.

Lease operating expenses.

Lease operating expenses increased $1.2 million in 2006 to $3.0 million, a 68% increase compared to 2005. This increase resulted from an increase in the number of wells in the productive cycle during 2006. On an Mcf basis, lease operating expenses increased 53% from $0.81 per Mcf in 2005 to $1.24 per Mcf in 2006. The increase per Mcf was primarily due to a number of wells being in the early stages of their productive life cycle as production did not increase proportionately to the number of wells coming online.

Production taxes.

Production taxes decreased $0.4 million in 2006 to $1.2 million, a 27% decrease from 2005. The decrease in production tax was directly correlated to gross sales revenue because production taxes in Wyoming are based on a percentage of sales value. The percentage averages 11% to 13%, depending on rates in effect for the respective year. On an Mcf basis, production taxes were $0.50 per Mcf for 2006 and $0.74 per Mcf for 2005, a 33% decrease, which correlates to the decrease in the price per Mcf received in 2006 from 2005.

Marketing and transportation.

Marketing and transportation expenses increased $0.4 million in 2006 to $2.0 million, a 24% increase from 2005. The increase related primarily to the increased sales volume in 2006 together with a slight increase in transportation fees and compression due to inflationary adjustments in the applicable contracts along with additional compression, which enabled us to move gas on additional high-pressure transportation systems. On an Mcf basis, marketing and transportation expenses increased 13% to $0.81 per Mcf in 2006 from $0.72 per Mcf in 2005.

General and administrative expenses, net.

General and administrative expenses are offset by operating income from drilling and production activities for which we can charge an overhead fee to nonoperating working interest owners. These well operating overhead fees increased 43% in 2006, from $0.8 million to $1.2 million, due to increased productive wells which we operate and for which we charge an overhead fee. General and administrative expenses, net increased $2.1 million in 2006 to $4.3 million from $2.3 million in 2005. This increase during 2006 was due primarily to increased staffing and administrative costs pertaining to the support of our drilling and production activities, along with our private placement offering. On an Mcf basis, general and administrative expenses, net increased 75% from $1.03 per Mcf in 2005 to $1.80 per Mcf in 2006.

Depreciation, depletion, amortization and accretion.

Depreciation, depletion, amortization and accretion expense increased $1.1 million for 2006 to $6.7 million, a 19% increase compared to 2005. This increase was due to an increase in capital expenditures that were added into the full cost pool used for the computation of depletion, as well as increased production coupled with lower year-end reserves due to lower year-end pricing. On an Mcf basis, the depreciation, depletion, amortization and accretion rate increased 9% to $2.77 per Mcf in 2006 from $2.55 per Mcf in 2005.

Year Ended December 31, 2005 Compared To Year Ended December 31, 2004

Gas sales volume.

Gas sales volume increased 46% in 2005 from 1,508 MMcf in 2004 to 2,207 MMcf in 2005. Daily sales volume was 6.0 MMcf for 2005 as compared to 4.1 MMcf for 2004, a 1.9 MMcf per day increase.

Gas sales revenue.

Revenue from gas sales increased $6.7 million in 2005 to $14.1 million, a 91% increase compared to 2004. This increase was due to increased volume resulting from wells dewatering to the point of commercial gas production, the connection of producing wells to gathering and processing infrastructure and increased drilling and completions. In addition, the average realized price per Mcf increased 31% from $4.90 per Mcf in 2004 to $6.41 per Mcf in 2005.

Derivatives.

For the year ended December 31, 2005, we had an unrealized loss of $1.6 million compared to an unrealized loss of $0.5 million for the year ended December 31, 2004. The unrealized loss is a noncash expense based primarily on the Black-Scholes model for valuing future cash flows utilizing price volatility with a normal discount rate. Hedges settled in 2005 resulted in a realized loss of $1.6 million compared to hedge losses of $0.1 million in 2004. The increased hedge losses were primarily due to a $1.4 million loss in the fourth quarter due to higher prices.

Lease operating expenses.

Lease operating expenses increased $0.3 million in 2005 to $1.8 million, a 23% increase compared to 2004. This increase resulted from an increase in the number of wells in the productive cycle during 2005. On an Mcf basis, lease operating expenses decreased 16% from $0.96 per Mcf in 2004 to $0.81 per Mcf in 2005.

Production taxes.

Production taxes increased $0.8 million in 2005 to $1.6 million, a 95% increase from 2004. The increase in production tax was directly correlated to gross sales revenue because production taxes in Wyoming are based on a percentage of sales value. The percentage averages 11% to 13%, depending on rates in effect for the respective year. On an Mcf basis, production taxes were $0.56 per Mcf for 2004 and $0.74 per Mcf for 2005, a 32% increase, which correlates to the increase in the price per Mcf received in 2005 from 2004.

Marketing and transportation.

Marketing and transportation expenses increased $0.4 million in 2005 to $1.6 million, a 30% increase from 2004. The increase related primarily to the increased sales volume in 2005 together with a slight increase in transportation fees and compression due to inflationary adjustments in the applicable contracts along with additional compression, which enabled us to move gas on additional high-pressure transportation systems. On an Mcf basis, marketing and transportation expenses decreased 11% to $0.72 per Mcf in 2005 from $0.81 per Mcf in 2004.

General and administrative expenses, net.

General and administrative expenses are offset by operating income from drilling and production activities for which we can charge an overhead fee to nonoperating working interest owners. These well operating overhead fees increased 33% in 2005, from $0.6 million to $0.8 million, due to increased productive wells which we operate and for which we charge an overhead fee. General and administrative expenses, net increased $0.7 million in 2005 to $2.3 million from $1.6 million in 2004. This increase during 2005 was due primarily to a full year of expenses combined with increased staffing and administrative costs pertaining to the support of our drilling and production activities. On an Mcf basis, general and administrative expenses, net did not change and were $1.03 per Mcf in 2004 and 2005.

Depreciation, depletion, amortization and accretion.

Depreciation, depletion, amortization and accretion expense increased $2.3 million for 2005 to $5.6 million, a 69% increase compared to 2004. This increase was due to an increase in capital expenditures that were added into the full cost pool used for the computation of depletion, as well as increased production. On an Mcf basis, the depreciation, depletion, amortization and accretion rate increased 15% to $2.55 per Mcf in 2005 from $2.21 per Mcf in 2004.

Liquidity and Capital Resources

Our primary source of liquidity since our formation has been the private sale of our equity. On June 23, 2003, DLJ Merchant Banking contributed $4.9 million cash in exchange for shares of our common stock and approximately $12.7 million cash in exchange for shares of our Series A Redeemable Preferred Stock and detachable warrants to purchase additional shares of common stock. The proceeds were used to purchase producing properties and undeveloped acreage and to fund our capital program for 2003. In 2004, DLJ Merchant Banking contributed approximately $11.8 million cash, which was used to fund our 2004 capital expenditures. In 2005, DLJ Merchant Banking contributed $14.7 million cash in order to fund our acquisition of undeveloped acreage and capital expenditures related to the development of that acreage. We issued additional shares of our Series A Redeemable Preferred Stock and detachable warrants to purchase shares of our common stock in connection with each capital contribution. Through December 31, 2006, DLJ Merchant Banking had contributed $44.1 million in cash in order to fund our acquisitions and capital expenditures. In April 2006, we completed a private placement of an aggregate of 12,835,230 shares of our common stock at a price per share of $11.00, or $10.23 net of the initial purchaser's discount and placement fee. Please see "—Cash Flow from Financing Activities—Sales and Issuances of Equity."

Credit Facility. As of December 31, 2006, we had no indebtedness outstanding under our old credit facility. Effective February 12, 2007, we entered into a new $100 million credit facility with an initial commitment of $27 million which permits borrowings up to the borrowing base as designated by the administrative agent. As of March 30, 2007, the initial borrowing base was $22 million although our borrowing availability is less than our initial borrowing base due to covenant limitations. As of March 30, 2007, the actual borrowing availability was $16.7 million. The borrowing base is determined on a semi-annual basis and at such other additional times, up to twice yearly, as may be requested by either the borrower or the administrative agent and is determined by the administrative agent in accordance with customary practices and standards for loans of a similar nature; provided that such determination is at the administrative agent's discretion as the credit agreement does not provide a specific borrowing base formula. Based on our reserve report as of December 31, 2006, we expect that our borrowing base will be further reduced below its initial level. Borrowings under this credit facility may be used solely to acquire, explore or develop oil and gas properties and for general corporate purposes. The credit facility matures February 12, 2011. At March 31, 2007 we had $4.5 million of indebtedness outstanding under our new credit facility.

Our obligations under the credit facility are secured by liens on (i) no less than 90% of the net present value of the oil and gas to be produced from our oil and gas properties that are included in the borrowing base determination, calculated using a discount rate of 10% per annum and reserve estimates, prices and production rates and costs, (ii) options to lease, seismic options, permits, and records related to such properties, and (iii) seismic data.

Borrowings under our credit facility may be either (i) a domestic bank rate plus an applicable margin between 0.25% and 1.25% per annum based on utilization, or (ii) the London interbank offered rate, or LIBOR, plus an applicable margin between 1.25% and 2.25% per annum based on utilization. The credit agreement provides for various fees, including a quarterly commitment fee of ¹/2 of 1.00% per annum and engineering fees to the administrative agent in connection with a borrowing base

determination. In addition, the new credit agreement provides for an up front fee of $27,000, which was paid on the closing date of the credit agreement, and an additional arrangement fee of up to 1% based on utilization. Borrowings under this credit facility may be prepaid without premium or penalty, except on Eurodollar advances. If an event of default exists, the default rate shall be equal to 2% plus the floating rate.

The credit agreement contains covenants that, among other things, restrict our ability, subject to certain exceptions, to do the following:

•: incur liens;
•: incur debt;
•: make investments in other persons;
•: declare dividends or redeem or repurchase stock;
•: engage in mergers, acquisitions, consolidations and asset sales or amend our organizational documents;
•: enter into certain hedging arrangements;
•: amend material contracts; and
•: enter into related party transactions.

With regard to hedging arrangements, the credit facility provides that acceptable commodity hedging arrangements cannot be greater than 80 to 85% depending on the measurement date of our monthly production from our hydrocarbon properties that are used in the borrowing base determination and that the fixed or floor price of our hedging arrangements must be equal to or greater than the gas price used by the lenders in determining the borrowing base.

The credit agreement also requires that we satisfy certain affirmative covenants, meet certain financial tests, maintain certain financial ratios and make certain customary indemnifications to lenders and the administrative agent. The financial covenants include requirements to maintain: (i) EBITDA to cash interest expense of not less than 3.00 to 1.00, (ii) current ratio of not less than 1.00 to 1.00, (iii) total debt to annualized EBITDA of not more than 3.0 to 1.0, (iv) quarterly total senior debt to annualized EBITDA equal to or less than 3.0 to 1.0 until June 30, 2007 and 2.00 to 1.0 thereafter, and (v) total proved PV-10 value to total debt of at least 1.50 to 1.00.

The credit agreement contains customary events of default, including, without limitation, payment defaults, covenant defaults, certain events of bankruptcy and insolvency, defaults in the payment of other material debt, judgment defaults, breaches of representations and warranties, loss of material permits and licenses and a change in control. In addition, we are required to eliminate scheduled title defects within periods specified on or prior to August 12, 2007, and the failure to eliminate all of these title defects would result in an event of default under the credit facility. We cannot guarantee that we will be able to eliminate all of these title defects within the specified periods. On March 9, 2007, we notified the lenders that we would be unable to comply with the initial deadline for the first phase of the curative title work and received a waiver from the lenders until April 30, 2007. Certain phase one curative title work has not been completed but we expect to receive an extension of the waiver. Failure to obtain an extension would result in an event of default under the credit facility.

The credit agreement requires all of our wholly owned subsidiaries to guarantee the obligations under the credit agreement.

Office Building Loan. On November 15, 2005, we entered into a mortgage loan secured by our office building in Sheridan, Wyoming in the aggregate principal amount of $829,000. The promissory note provides for monthly payments of principal and interest in the initial amount of $6,400, and

unpaid principal bears interest at 6.875% during the first three years, at a variable base rate thereafter and at 18% upon a default. The variable base rate is based on the lender's base rate. The maturity date of this mortgage is November 15, 2015, at which time a principal and interest payment of $615,400 will become due. As of December 31, 2006, we had $807,000 outstanding in principal and interest on this mortgage.

Capital Expenditure Budget. For 2006, we had a total capital expenditure budget for drilling and completion (excluding acquisitions) of approximately $36.3 million. While we believe we have adequate resources from our new credit facility and cash flows from operations to implement our 2007 drilling plan, our ability to develop future projects will depend on access to additional capital. For 2007, we have a total capital expenditure budget of approximately $52.6 million to drill and complete approximately 260 gross (207 net) wells, to construct related gas and water infrastructure, to fund plans of development costs for future wells, to fund undeveloped leasehold acquisition costs carried over from 2006, to recomplete certain wells, and to fund infrastructure and completion costs related to wells drilled in 2006. Please see "Business—2007 Capital Expenditure Plan."

We participated in the drilling of 230 gross (139 net) wells during the year ended December 31, 2006 and we are actively developing the Kirby, Deer Creek and Cabin Creek areas of our undeveloped acreage. We also commenced drilling in our Green River Basin acreage at the end of the second quarter of 2006 and are actively developing this new area.

Cash Flow from Operating Activities

Net cash provided by operating activities was $6.0 million for year ended December 31, 2006, compared to net cash provided by operating activities of $8.8 million and $1.4 million in the years ended 2005 and 2004, respectively.

We believe that cash flows from operations and borrowings under our credit facility will be sufficient to meet our planned capital expenditures and our other cash needs during the year ending December 31, 2007.

Cash Flow from Investing Activities

Net cash used in investing activities was $63.9 million, $25.3 million, and $14.0 million for the years ended December 31, 2006, 2005, and 2004, respectively. Net cash used in investing activities increased by approximately $38.5 million in 2006 compared to 2005, of which approximately $27 million was related to the Green River Basin acquisition and the remaining $11.5 million was related to increased investments attributable to the acquisition and development of undeveloped leaseholds in Montana and Wyoming. The increase of $11.3 million in 2005 compared to 2004 was primarily due to increased investments attributable to the acquisition of undeveloped leaseholds in Montana and Wyoming, a larger realized loss on a hedge settlement and an increase in assets held for sale.

Cash Flow from Financing Activities

Sales and Issuances of Equity

Common Stock. At formation, we issued an aggregate of 3,750,000 shares of common stock, par value $0.01 per share, in equal portions to a subsidiary of Carrizo and to Rocky Mountain Gas Inc., a former subsidiary of U.S. Energy, in exchange for the contribution of interests in approximately 81,000 gross (40,000 net) acres, including proved producing properties and undeveloped leaseholds, valued at $15.0 million. The 1,875,000 shares held by Rocky Mountain Gas were transferred to its affiliates, U.S. Energy and Crested Corp., in May 2005. We issued an additional 1,250,000 shares of common stock at formation to DLJ Merchant Banking in exchange for a cash contribution of $4.9 million. On November 18, 2005, we issued an additional 750,000 shares of common stock to DLJ Merchant

Banking in connection with the exercise of Series B warrants. On November 30, 2005, Gary W. Uhland, our former President, exercised options to acquire 50,000 shares of our common stock. As of December 31, 2006 and March 31, 2007, we had 25,131,301 and 25,178,301 shares of common stock issued and outstanding, respectively, of which 27,270 and 74,270 shares, respectively, are shares of restricted stock issued to employees and directors.

In April 2006, we completed a private placement, exempt from registration under the Securities Act, of 12,835,230 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors at a price of $11.00 per share, or $10.23 per share net of the initial purchaser's discount and placement fee. Out of the aggregate of approximately $129.9 million of net proceeds (after expenses) we received in the private placement, we used (i) approximately $53.6 million to redeem all of the outstanding shares of our Series A Redeemable Preferred Stock, including the payment of all accrued and unpaid dividends and a redemption premium, (ii) approximately $27.0 million for our acquisition of the Green River Basin assets, (iii) approximately $16.3 million to repurchase an aggregate of 1,593,783 shares of common stock at a price of $10.23 per share from DLJ Merchant Banking and Gary W. Uhland, our former President, and (iv) approximately $33.0 million to fund our development drilling program and pay additional offering expenses and for general corporate purposes.

Series A Redeemable Preferred Stock. At formation, we issued 130,000 shares of Series A Redeemable Preferred Stock, par value $0.01 per share, to DLJ Merchant Banking in exchange for an approximately $12.7 million cash investment. On February 19, 2004, we issued an additional 120,000 shares of Series A Redeemable Preferred Stock to DLJ Merchant Banking in exchange for an approximately $11.8 million cash investment. On March 28, 2005, we issued an additional 100,000 shares of Series A Redeemable Preferred Stock to DLJ Merchant Banking in exchange for a $9.8 million cash investment. On September 1, 2005, we issued an additional 50,000 shares of Series A Redeemable Preferred Stock to DLJ Merchant Banking in exchange for a $4.9 million cash investment.

In 2005, 2004 and 2003, we elected to pay all dividends on our Series A Redeemable Preferred Stock in the form of paid-in-kind dividends. Dividends paid in 2005, 2004 and 2003 totaled approximately $3.6 million, $2.2 million and $0.4 million, respectively, resulting in the issuance of 36,007, 22,495 and 3,687 additional shares of Series A Redeemable Preferred Stock, respectively. In January 2006, a paid-in-kind dividend in the amount of approximately $1.2 million was paid with respect to the fourth quarter of 2005, resulting in the issuance of 12,132 additional shares of Series A Redeemable Preferred Stock.

In April 2006, following the initial closing of our private placement, we redeemed all of the outstanding shares of Series A Redeemable Preferred Stock with a portion of the proceeds from our private placement including the payment of accrued and unpaid dividends of $1.4 million. The difference between the redemption price and the carrying value of the Series A Redeemable Preferred Stock resulted in a $19.6 million redemption premium that was recorded as a dividend expense in our statement of operations for the three months ended June 30, 2006. As of December 31, 2006, we had no shares of Series A Redeemable Preferred Stock issued and outstanding.

Warrants. At formation, in connection with the issuance of Series A Redeemable Preferred Stock, we issued Series A detachable warrants to DLJ Merchant Banking to purchase 3,250,000 shares of common stock at an exercise price of $4.00 per share. The warrants were recorded at their estimated fair value on the date of issuance, which was approximately $4.4 million. On February 19, 2004, in connection with the issuance of additional Series A Redeemable Preferred Stock, we issued additional Series A detachable warrants to DLJ Merchant Banking to purchase 3,000,000 shares of common stock at an exercise price of $4.00 per share. The warrants were recorded at their estimated fair value on the date of issuance of approximately $4.1 million. On March 28, 2005, in connection with the issuance of additional Series A Redeemable Preferred Stock, we issued additional Series A detachable warrants to

DLJ Merchant Banking to purchase 2,500,000 shares of common stock at an exercise price of $4.00 per share and Series B warrants to purchase 500,000 shares of common stock at an exercise price of $0.01 per share. These warrants were recorded at their estimated fair value on the date of issuance of approximately $2.4 million and $1.1 million, respectively. On September 1, 2005, in connection with the issuance of additional Series A Redeemable Preferred Stock, we issued additional Series A detachable warrants to DLJ Merchant Banking to purchase 1,250,000 shares of common stock at an exercise price of $4.00 per share and additional Series B warrants to purchase 250,000 shares of common stock at an exercise price of $0.01 per share. These warrants were recorded at their estimated fair value on the date of issuance of approximately $1.1 million and approximately $0.6 million, respectively. In addition, in connection with the payment of paid-in-kind dividends on our Series A Redeemable Preferred Stock, we issued additional Series A detachable warrants to DLJ Merchant Banking to purchase an aggregate 834,025 shares of common stock at an exercise price of $4.00 per share. On November 18, 2005, DLJ Merchant Banking exercised all of its Series B warrants to purchase 30,000 shares (pre-split; 750,000 shares post-split) of common stock at an exercise price of $0.01 per share. As of December 31, 2005 there were Series A warrants outstanding to purchase an aggregate of 10,530,725 shares of common stock with an exercise price of $4.00 per share. However, immediately prior to the initial closing of our private placement, DLJ Merchant Banking exchanged all of its outstanding warrants for 6,894,380 shares of our common stock in a tax-free reorganization based on the private placement price of $11.00 per share. As of December 31, 2006, we had no warrants or escalating options issued and outstanding.

Options. Please see "Certain Relationships and Related Party Transactions—Transactions with Our Founders—Transactions with Other Initial Stockholders" for information regarding the issuance of options to non-management stockholders.

Contractual Obligations

The following table summarizes by period our contractual obligations as of December 31, 2006:

		Total		2007		2008-2009		2010-2011		Thereafter
		(in thousands)
Notes payable in connection with the mortgage		$	807	$	22	$	42	$	42	$	701
Asset retirement obligations			2,321				313		791		1,217
Non-current production and property taxes			843		—		843		—		—

	Total	$	3,971	$	22	$	1,198	$	833	$	1,918

At December 31, 2006, the commodity derivatives asset was valued at $2,856,000, which represents a current receivable attributable to 2007.

Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk" refers to the risk of loss arising from adverse changes in natural gas prices. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposure. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our natural gas production. The prices we receive for our production depend on many factors beyond our control. We seek to reduce our exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow us to predict with greater certainty the effective natural

gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided by the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling prices and floors provided in those contracts.

The following table summarizes the estimated volumes, fixed prices, fixed price sales and fair value attributable to the fixed price contracts as of December 31, 2006. At December 31, 2006, we had no hedged volumes beyond December 2007. However, in April 2007, we hedged an additional 3,000 MMBtu per day from January 2008 through December 2008 at a floor price of $6.50 per MMBtu and a ceiling price of $8.20 per MMBtu based on the CIG Inside FERC published price. Please see Note 8 of the notes to the audited financial statements appearing elsewhere in this prospectus for additional information regarding our hedging for 2005 and 2006.

		Year Ending December 31, 2007
		(Unaudited)
Natural Gas Collars:
Contract volumes (MMBtu):
	Floor		1,733,000
	Ceiling		1,733,000
Weighted-average fixed price per MMBtu(1):
	Floor	$	6.58
	Ceiling	$	8.75
Fixed-price sales(2)		$	8.75
Fair value, net (thousands)(3)		$	2,856
Total Natural Gas Contracts:
Contract volumes (MMBtu)			1,733,000
Weighted-average fixed price per MMBtu(1)		$	6.58
Fixed-price sales(2)		$	8.75
Fair value, net (thousands)(3)		$	2,856

(1): Volumes hedged using the CIG index price published in the first issue of Inside FERC's Gas Market Report for each calendar month of the derivative transaction.
(2): Assumes ceiling prices for natural gas collar volumes.
(3): Fair value based on CIG index price in effect for each month as of December 31, 2006.

BUSINESS

Overview

We are an independent energy company engaged in the acquisition, exploration and development of domestic onshore natural gas reserves. We currently focus our efforts on the development of coalbed methane properties located in the Rocky Mountain region, and we are a substantial holder of CBM acreage in the Powder River Basin. We have assembled a large, predominantly undeveloped CBM leasehold position, which we believe positions us for significant long-term growth in production and proved reserves. In addition, we own over 94% of the rights to develop conventional and unconventional oil and gas in zones below our existing CBM reserves. Substantially all our undeveloped acreage as of December 31, 2006 was located on the northern end of the Powder River Basin in northeastern Wyoming and southern Montana.

As of December 31, 2006, we owned natural gas and oil leasehold interests in approximately 454,000 gross (308,000 net) acres, approximately 92% of which are undeveloped. As of December 31, 2006, we had identified approximately 5,000 CBM drilling locations on our existing acreage, primarily on 80-acre well spacing, targeting an average of three coal seams per location. At December 31, 2006, we had estimated net proved reserves of 20.3 Bcf based on a year-end CIG index price of $4.46 per Mcf, with a pre-tax PV-10 value of $25.3 million. These net proved reserves were located on approximately 8% of our net acreage. Based on our drilling results to date, analysis of core samples and third-party results in adjacent areas, we believe that our remaining undeveloped CBM acreage has substantial commercial potential. None of our acreage or producing wells is associated with coal mining operations.

Our Powder River Basin and Green River Basin CBM Projects

During the period from formation in June 2003 to December 31, 2006, we completed 560 gross (278 net) of the 613 gross (327 net) CBM wells we drilled in the Powder River and Green River Basins. We expect to complete an additional 53 gross (49 net) of these wells as soon as necessary infrastructure becomes available. If, as expected, we complete these additional wells, we will have completed over 99% of the wells drilled through December 31, 2006.

Powder River Basin

•: Wyoming. Our principal Wyoming properties in the Powder River Basin are located in two distinct project areas: Recluse and Cabin Creek. Substantially all of our natural gas production has come from the Recluse area. As of December 31, 2006, we held approximately 97,000 gross (55,000 net) acres in the Powder River Basin in Wyoming for prospective CBM development

and we operated over 97% of this acreage. As of December 31, 2006, we had 393 approved drilling permits for our Powder River Basin properties in Wyoming and are in the process of applying for an additional 364 drilling permits which we expect to be approved before the end of 2007. We anticipate drilling 186 gross (143 net) wells on our Powder River Basin properties in Wyoming during the year ending December 31, 2007.

•: Montana. Our Montana properties are located in four project areas: Kirby, Deer Creek, Bear Creek and Bradshaw. As of December 31, 2006, we held approximately 325,000 gross (222,000 net) acres in Montana for prospective CBM development and we operated 100% of this acreage. We have begun active development in both the Deer Creek and Kirby areas, and in 2006, we drilled 130 gross (82 net) wells. As of December 31, 2006, we had 67 approved drilling permits for our Montana properties and are in the process of applying for an additional 1,344 drilling permits which we expect to be approved during 2007. Of these additional permits, 590 are on fee and state land and 754 are on federal land. We anticipate drilling 73 gross (63 net) wells on our Montana properties during the year ending December 31, 2007.

Green River Basin

On April 20, 2006, we acquired undeveloped natural gas properties, including related interests and assets, located in the Green River Basin of Wyoming from Kennedy Oil for an aggregate purchase price of approximately $27.0 million in cash. Our Green River Basin properties are located in the northeast area of Sweetwater County, Wyoming. As of December 31, 2006, our properties in the Green River Basin consisted of approximately 32,000 gross (31,000 net) undeveloped acres for prospective CBM development in the Fort Union Big Red Coal formation. As of December 31, 2006, we operated 100% of this acreage. As part of our initial acquisition, we also acquired 20 shut-in wells and 23 approved drilling permits and a 65% working interest in existing deep rights below the base of the Fort Union formation. Based in part on preliminary positive coring results, mud logs, coal thickness and permeability, we accelerated our development in the Green River Basin in 2006. In addition, we have been successful in downspacing a section of our Green River Basin property from 160-acre spacing to 80-acre spacing, thus allowing us to more quickly dewater wells in this area and reach gas production. We originally planned to drill 5 gross (5 net) wells in the Green River Basin in 2006, but had drilled a total of 14 gross (14 net) wells as of December 31, 2006. To facilitate our increased development activities, we are also constructing gas gathering infrastructure and a water management system for the Green River Basin areas which we are initially developing. It is more expensive to drill in the Green River Basin because of the increased depth of the wells, the increased cost of water management in the area and the need for additional infrastructure. As a result, in 2006 we reallocated $5.5 million of capital expenditures to the Green River Basin and reduced drilling in the Powder River Basin in order to accelerate the development of our initial Green River Basin properties.

As of December 31, 2006, we had 14 approved permits for our Green River Basin properties. We are in the process of applying for an additional 51 drilling permits which we expect to be approved before the end of 2007. We anticipate drilling 1 gross (1 net) well on our Green River Basin properties during the year ending December 31, 2007. As of December 31, 2006, we had identified 160 drilling locations based on 160-acre spacing (or 320 drilling locations based on 80-acre spacing). As of December 31, 2006, we had no proved reserves established in our Green River Basin properties.

In November 2006, we entered into a 2-year gas gathering agreement with Mountain Gas Resources, Inc. which will allow us to transport up to 5 MMcf/day from our initially developed Green River Basin properties. In addition, we expect that takeaway capacity from the Green River Basin properties we are currently developing will increase due to the Rockies Express Pipeline which became operational in February 2007. The expansion of this pipeline to service the Midwest markets is expected to be completed in January 2008 and will add 2 Bcf per day to the total takeaway capacity from the Rocky Mountain region, including the Green River Basin. According to NSAI, our Green River Basin

properties have higher reserve values and longer life reserves than our Powder River Basin properties. Based on early drilling results, we expect to continue to accelerate our development plans in the Green River Basin in 2007 and 2008.

Summary of Our Powder River and Green River Basin Properties and 2007 Capital Budget

		Producing Wells as of December 31, 2006		Producing Wells as of December 31, 2005
						2007 Capital Budget(1)(2)
						2007 Capital Budget(1)(2)				Estimated Potential Drilling Locations (Approximate)
		Gross	Net	Gross	Net	Gross Wells	Net Wells	Capital Expenditures		Estimated Potential Drilling Locations (Approximate)	Estimated Total Net Acres (Approximate)
Recluse(3)		407	208	395	198	54	27	$	3.9	350	17,000
Cabin Creek		29	15	0	0	132	116		24.7	450	31,000
Kirby		93	58	9	5	2	1		0.2	1,650	51,000
Deer Creek		0	0	0	0	71	62		8.4	620	47,000
Bear Creek		0	0	0	0	0	0		0	710	53,000
Bradshaw		0	0	0	0	0	0		0	1,000	71,000
Green River Basin(4)		0	0	0	0	1	1		7.5	160	31,000
Other		0	0	0	0	0	0		0	60	7,000

	Total	529	281	404	203	260	207	$	44.7	5,000	308,000

(1): For the year ended December 31, 2006, capital expenditures for drilling 230 gross (139 net) wells totaled $34.7 million.
(2): Excludes approximately $5.9 in capital expenditures relating to plans of development costs for wells to be drilled in the future and $2.0 million of undeveloped leasehold acquisition costs in 2006.
(3): Includes approximately $0.5 million for recompletions.
(4): Includes approximately $7.3 million of infrastructure and completion costs related to wells drilled in 2006.

Strategy

•: Accelerating the development of our acreage position by increasing the level of our drilling activity;
•: Maintaining operational control over our assets in order to control the costs and timing of our exploration, development and production activities;
•: Constructing and maintaining control over our low-pressure gas gathering systems that collect and transport our production;
•: Maintaining a low-cost and efficient operating environment by exploiting the economies of scale that arise from developing our large contiguous acreage position;
•: Proactively managing legal, regulatory and environmental issues to ensure the efficient and timely development of our asset base;
•: Pursuing selective acquisitions that add attractive exploitation and development opportunities and also enhance the critical mass of our asset base;

•: Pursuing selective acquisition opportunities that would allow us to apply our CBM development expertise in other areas in the Rocky Mountain region; and
•: Exploring the potential of the deeper lease rights below the coal seams on our existing acreage position.

Competitive Strengths

We have a number of strengths that we believe will help us successfully implement our strategy.

•: Experienced Management Team. Our key personnel have significant experience managing CBM operations, particularly in the Powder River Basin. Our management team has an average of 20 years of experience in acquiring, developing and operating oil and gas properties, primarily in the Rocky Mountain region.
•: Significant Reserve Potential. According to the U.S. Department of Energy 2002 Powder River Basin Coalbed Methane Development and Produced Water Management Study, the Montana portion of the Powder River Basin is estimated to have substantial recoverable reserves. We hold a significant portion of the acreage that is prospective for CBM development in the Montana portion of the Powder River Basin.
•: Low Geological Risk. The coal seams in the Powder River Basin that we target have been extensively mapped as a result of a variety of natural resource development that has occurred in the region. Industry data from over 23,500 wellbores drilled through the Fort Union formation allows us to determine the aerial extent, thickness, gas saturation, formation pressure and relative permeability of the coal seams we target for development, which reduces our dry hole risk.
•: Low Development Risk and Predictable Results. As of December 31, 2006, we had completed 560 gross (278 net) of the 613 gross (327 net) CBM wells that we had drilled on our acreage. We expect to complete an additional 53 gross (49 net) of these wells as soon as necessary infrastructure becomes available. If, as expected, we complete these additional wells, we will have completed over 99% of the wells drilled through December 31, 2006. Our overall drilling program is relatively predictable on an average well basis in terms of recoverable reserves, production rates and decline curves, which results in lower development risk.
•: Large, Contiguous Acreage Position. Our acreage position of approximately 454,000 gross (308,000 net) acres includes one of the largest contiguous acreage positions in the Powder River Basin. Many of our leases are in large blocks, generally along the Wyoming and Montana border, adjacent to newly established areas of development activities. We believe the contiguous nature of the majority of our Powder River Basin properties gives us the necessary critical mass to better manage operating and development costs and surface issues, obtain pipeline access and execute our plan of development.
•: Extensive Inventory of Drilling Locations. As of December 31, 2005, our net acreage position was only 8% developed. As of December 31, 2006, we had identified approximately 5,000 CBM drilling locations on our existing acreage, primarily on 80-acre spacing, targeting an average of three coal seams per location.
•: Large Inventory of Drilling Permits. As of December 31, 2006, we had 407 approved drilling permits for our Wyoming acreage and we are in the process of applying for an additional 415 permits in Wyoming, which we expect to be approved before the end of 2007. As of December 31, 2006, we had four plans of development approved for our Montana acreage, allowing us to drill 67 additional wells, and we are in the process of applying for an additional 1,344 permits which we expect to be approved before the end of 2007. We believe that in the

near future, we will have sufficient permits to support at least two years of our planned drilling activity.

•: Attractive Cost Structure. We believe our average cost structure is attractive due to the low geological risk, high completion rates, generally shallow drilling depths and low-cost completions, including multiple zone completions, associated with developing our CBM acreage position. Although our lease operating costs are higher than average on a per Mcf basis while we are in our initial stages of development, we expect that our lease operating expenses will benefit from economies of scale as we grow, our maintaining high operatorship of our reserves and production, and our continuing cost management initiatives.
•: Control of Low-Pressure Gas Gathering Infrastructure. As of December 31, 2006, we owned and operated approximately 208 miles of low-pressure gas gathering pipelines that collect and transport our production in the Recluse area of Wyoming. We intend to construct, own and operate the additional low-pressure gas gathering system assets required to develop our acreage position.
•: Marketing Flexibility. Production from our acreage has access to several regional and interstate pipelines, providing sufficient takeaway capacity from our operating region and access to major gas demand centers in the United States.
•: Local Presence. We are headquartered in Sheridan, Wyoming, which is the center of our project areas in the Powder River Basin. Our local presence gives us insight into the issues associated with Powder River Basin CBM development and the ability to quickly and effectively communicate with landowners, mineral owners and regulatory agencies.

Our History

We were formed as a Delaware corporation in June 2003 by funds affiliated with DLJ Merchant Banking and subsidiaries of Carrizo and U.S. Energy. Carrizo and U.S. Energy contributed oil and gas reserves and leasehold interests in approximately 81,000 gross (40,000 net) acres in exchange for shares of our common stock and options to purchase shares of our common stock. DLJ Merchant Banking completed several cash investments in us in exchange for shares of our common stock, Series A Redeemable Preferred Stock, and warrants to purchase additional shares of our common stock, and has been instrumental in providing capital to drive our growth. In April 2006, we completed a private offering of 12,835,230 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors. Immediately prior to the initial closing of our private placement, DLJ Merchant Banking exchanged all of its warrants for 6,894,380 shares of common stock in a tax-free reorganization and each of Carrizo and U.S. Energy entered into a cashless exercise of all of its options for 584,102 shares of common stock, in each case based on the private placement price of $11.00 per share. Following the initial closing of our private placement, we redeemed all of the outstanding shares of Series A Redeemable Preferred Stock held by DLJ Merchant Banking with a portion of the proceeds we received in the private placement. In addition, following the final closing of our private placement, we used a portion of the proceeds we received in the private placement to repurchase an aggregate of 1,587,598 shares of common stock from DLJ Merchant Banking at a price per share equal to the private placement price of $11.00 per share less the initial purchaser's discount and placement fee. On September 22, 2006, DLJ Merchant Banking purchased all of the 2,459,102 shares of our common stock held by U.S. Energy and its affiliates in a private transaction. As of December 31, 2006, DLJ Merchant Banking and Carrizo beneficially owned approximately 38.9% and 9.8%, respectively, of our outstanding common stock. After this offering, DLJ Merchant Banking and Carrizo will beneficially own approximately 32.5% and 8.2%, respectively, of our outstanding common stock if the over-allotment option is exercised in full.

In addition to the initial contribution of leasehold interests to us by U.S. Energy and Carrizo, during the period from our formation in June 2003 to December 31, 2006, we have acquired leasehold interests covering approximately 341,000 gross (237,000 net) acres in the Powder River Basin, primarily from two significant acquisitions.

•: In June 2003, we acquired approximately 57,000 gross (22,000 net) acres along with 210 gross (96 net) producing wells and shut-in wells in Wyoming from Gastar Exploration, Ltd. and certain of its affiliates.
•: In March 2005, we acquired approximately 223,000 gross (196,000 net) undeveloped acres for prospective CBM development in Montana and Wyoming from a subsidiary of Marathon Oil Corporation.

In April 2006, we also acquired approximately 30,000 gross (29,000 net) undeveloped acres in the Green River Basin in Wyoming. Please see "—Our Powder River Basin and Green River Basin CBM Projects—Green River Basin."

2007 Capital Expenditure Plan

For 2007, we have a total capital expenditure budget of approximately $52.6 million to drill and complete approximately 260 gross (207 net) wells, to construct related gas and water infrastructure, to fund plans of development costs for future wells, to fund undeveloped leasehold acquisition costs carried over from 2006, to recomplete certain wells, and to fund infrastructure and completion costs related to wells drilled in 2006.

Overview of the CBM Industry and the Powder River Basin

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

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

CBM production is expected to increase substantially due to the economic viability of the resources and the tremendous reserve potential of the numerous, virtually undeveloped U.S. coal basins. Within the Rocky Mountain region, the Powder River Basin has become a major CBM producing basin. According to the U.S. Department of Energy 2002 Powder Basin Coalbed Methane Development and Produced Water Management Study, the Powder River Basin is estimated to have substantial recoverable natural gas reserves. Approximately 1.01 Bcf of CBM is produced from the Powder River Basin per day.

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

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

Drilling and Production

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

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

Conventional gas wells are typically 8,000 to 20,000 feet deep and initially produce large volumes of gas relative to water. Natural gas normally does not require assistance to move to the surface, and over time, gas production declines and water production may increase. In contrast, CBM wells generally range from 300 to 4,000 feet. In the early stages of CBM production, large quantities of water and low

quantities of gas are produced. Water production is initiated to lower the downhole pressure which allows the methane to release from the coal. The water volumes eventually decline and gas quantities begin to rise. In most cases, assistance to bring the gas to surface is not needed for the final period of production.

Water Production and Management

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

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

•: surface discharge;
•: containment in reservoirs;
•: irrigation of surface lands;
•: injection to shallow sand formations;
•: enhanced evaporation systems;
•: treatment through ion exchange or reverse osmosis; and/or
•: sub-surface irrigation.

We include water gathering and water disposal costs in our hook-up, infrastructure and water management cost estimate of $44,000 per well.

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

Recovery Characteristics

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

Powder River Basin CBM Production Overview

The Powder River Basin is located in northeastern Wyoming and southeastern Montana. The Powder River Basin is rich in natural resources with significant reserves of oil and gas as well as some of the world's thickest coal seams. The Powder River Basin holds the distinction of being the leading coal-producing area in the United States, and in recent years, has become one of the most active areas for oil and gas drilling. Our CBM development in the Powder River Basin is a relatively predictable natural gas exploitation and development process compared to the exploitation of many types of natural gas.

On 80-acre spacing, we have approximately 5,000 drilling locations in the Powder River Basin. We target an average of three coal seams per location and have up to five coal seams that we believe are capable of commercial production. We expect that many of our wells will be completed to more than one coal seam, and thus we may drill less than three wells per location. The coal seams that we target are part of the Fort Union formation and include the Canyon, Cook, Wall, Pawnee and Flowers-Goodale (the Roberts equivalent) coals, which are found at depths ranging from 200 to 1,500 feet and are each approximately 15 to 60 feet thick. We plan to drill 200 to 400 wells annually.

As of December 31, 2006 and based on a year-end index price, NSAI has identified over 6,800 economic completions, consisting of 783 proved, 793 probable and 5,252 possible, across our approximately 5,000 drilling locations in the Powder River Basin assuming one coal seam per well. Our wells generally reach total depth in one day and cost an average of approximately $76,000 per well to drill and complete. Hook-up, infrastructure and water management costs average approximately $44,000 per well. Powder River CBM wells are drilled with small truck mounted water well rigs and are completed as either single or multiple zone producers. In a single coal completion, we top set the casing in the first foot of coal and complete the well by under-reaming the coal with a 12-inch diameter tool. In a multiple zone completion, we typically top set and under-ream the deepest coal seam and perforate the upper coal seams sequentially. Our general production profile for a CBM well shows production of water for 30 to 90 days prior to initial gas production. The lowering of the static water level reduces the coal formation pressure and allows the gas to desorb from the coal and migrate to the well bore. Gas production typically inclines steeply for an average of nine months, peaking at an average of over 100 Mcf per day. A period of relatively flat production at peak continues for three to four months and then declines at an annual rate of approximately 35% over a five to seven year period. Produced water is handled by discharging it through one or more of several regulatory-approved methods.

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

Green River Basin CBM Production Overview

The Green River Basin is primarily located in southwestern Wyoming, and our assets are located in the eastern half of the Wyoming portion of the Green River Basin. According to the U.S. Department of Energy 2004 Coal Bed Methane Primer, the Green River Basin has significant potential CBM reserves in place. The Green River Basin is an increasingly active basin for natural gas and CBM exploration and drilling. An Environmental Impact Statement is currently being prepared by the Wyoming Bureau of Land Management for the drilling and development of up to approximately 9,000 natural gas wells, including up to 500 CBM wells, on a 1.1 million acre project area. Our Green River Basin acreage position is offset by multiple fields producing from conventional reservoirs in the Lance, Lewis and Almond sandstones. In 2005, there were approximately 31 CBM projects in the eastern half of the Green River Basin with a total of 176 CBM wells drilled. These projects are being developed by approximately 13 operators targeting coals in the Mesaverde, Fort Union and Wasatch formations.

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

We anticipate developing the Green River Basin CBM reserves primarily on 160-acre spacing. The 14 gross (14 net) wells drilled as of December 31, 2006 on the acreage have generally reached total depth in five days. We estimate that future wells will cost an average of $780,000 to drill, complete and hook up. We intend to complete the wells by under-reaming the coal or drilling through the coal and perforating the coal formation. Based on a reserve report prepared by NSAI, we estimate that a typical Big Red Coal well has gross ultimate recovery of 1.2 Bcf. Our estimated production profile assumes little gas production for three to five months as the well is dewatered and the formation pressure lowered, a steep incline in production for the following 12 months, peak production of an average of over 450 Mcf per day for 18 to 24 months and then a slow decline in production of approximately 10% per year over a 20 to 25 year period. We estimate the standard reserve life of a well in the Green River Basin will be approximately 25 years.

Operations

CBM Development, Projects and Operations

Our properties in the Powder River Basin are primarily located in northeastern Wyoming and southern Montana and are generally contiguous, providing us with critical mass and the ability to execute large scale development projects in our operating areas. As of December 31, 2006, we owned leasehold interests in approximately 422,000 gross (277,000 net) acres in the Powder River Basin, approximately 99% of which we operated. In addition, in April 2006 we acquired 30,000 gross (29,000 net) acres in the Green River Basin in Wyoming, 100% of which we operated.

During the period from our formation in June 2003 to December 31, 2006, we completed 560 gross (278 net) of the 613 gross (327 net) CMB wells we drilled in the Powder River and Green River Basins. We expect to complete an additional 53 gross (49 net) of these wells as soon as necessary infrastructure becomes available. If, as expected, we complete these additional wells, we will have completed over 99% of the wells drilled through December 31, 2006. During the year ended December 31, 2005, we drilled 137 gross (66 net) wells and connected 93 gross (38 net) wells to our low-pressure gathering system. During the year ended December 31, 2006, we drilled 230 gross (139 net) wells and connected 218 gross (119 net) wells to our low-pressure gathering system. At December 31, 2006, we were producing natural gas from approximately 487 gross (257 net) CBM wells

at a net rate of 7.5 MMcf per day measured at the wellhead. Capital expenditures for the year ended December 31, 2005 were approximately $10.1 million for development of wells and pipeline infrastructure. Capital expenditures during the year ended December 31, 2006 were approximately $39.9 million for development of wells and pipeline infrastructure. For 2007, we have a total capital expenditure budget of approximately $52.6 million to drill and complete approximately 260 gross (207 net) wells, to construct related gas and water infrastructure, to fund plans of development costs for future wells, to fund undeveloped leasehold acquisition costs carried over from 2006, to recomplete certain wells, and to fund infrastructure and completion costs related to wells drilled in 2006.

We plan to drill and complete approximately 500 wells through 2008 and have also identified approximately 5,000 drilling locations on our existing acreage, primarily on 80-acre well spacing, targeting an average of three coal seams per location. The coal seams that we target include the Canyon, Cook, Wall, Pawnee and Flowers-Goodale (the Roberts equivalent) in the Powder River Basin, which are found at depths ranging from 200 to 1,500 feet, and the Fort Union Big Red Coal in the Green River Basin, which is found at depths ranging from 4,000 to 6,000 feet. Each coal seam is approximately 15 to 60 feet thick. As of December 31, 2006 and based on a year-end index price, NSAI has identified over 6,800 economic completions, consisting of 783 proved, 793 probable and 5,252 possible, assuming one coal seam per well. We expect that many of our wells will be completed to more than one coal seam.

We believe that we have the necessary expertise, manpower, capital resources and drilling rigs and other equipment capabilities required to carry out our development plans. Our management believes that value will be created if the drilling program continues to be successful in converting undeveloped acreage into proven natural gas reserves. Most of this development drilling is in areas of known natural gas reserves and involves much lower risk than the exploratory type of drilling that is required when searching for new natural gas reserves. Our typical new well has added value amounting to several times our approximately $76,000 historical cost for drilling and completing a well in the Powder River Basin and our approximately $678,000 historical cost for drilling and completing a well in the Green River Basin.

Wyoming—Powder River Basin

Our principal properties in the Powder River Basin in Wyoming are located in two distinct project areas: Recluse and Cabin Creek. Substantially all of our natural gas production has come from the Recluse area. As of December 31, 2006, we held approximately 97,000 gross (55,000 net) acres in the Powder River Basin in Wyoming for prospective CBM development and we operated over 97% of this acreage.

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

As of December 31, 2006, we had 393 approved drilling permits for our Wyoming properties in the Powder River Basin and are in the process of applying for an additional 364 drilling permits which we expect to be approved during 2007. We anticipate drilling 186 gross (143 net) wells on our Wyoming

properties in the Powder River Basin during the year ending December 31, 2007. Set forth below is a summary of each of our Wyoming project areas.

•: Recluse—Recluse is located on the northern end of the Gillette Fairway, where a majority of Powder River Basin CBM has been produced to date. As of December 31, 2006, we held approximately 46,000 gross (17,000 net) acres in the Recluse area, of which approximately 70% is developed. As of December 31, 2006, we operated approximately 100% of these properties. As of December 31, 2006, we were producing approximately 18.0 gross (7.2 net) MMcf per day from approximately 400 wells in this area. During the year ended December 31, 2006, we drilled 45 gross (20 net) wells. Our gas is gathered in over 200 miles of low-pressure gathering systems which we installed and own. As of December 31, 2006, we had approximately 10 Bcf of net proved reserves in the Recluse area based on a CIG index price of $4.46 per Mcf. We have identified over 350 potential drilling locations and plan to drill 54 gross (27 net) wells in Recluse during the year ending December 31, 2007.
•: Cabin Creek—Our Cabin Creek project is located on the northern border of Wyoming adjacent to St. Mary's Hanging Woman project to the west. As of December 31, 2006, we held approximately 42,000 gross (31,000 net) acres in Cabin Creek, of which approximately 5% is developed. As of December 31, 2006, we operated approximately 95% of these properties. As of December 31, 2006, we participated in wells that were producing approximately 1.4 gross (0.3 net) MMcf per day from approximately 29 gross (15 net) wells in this area. During the year ended December 31, 2006, we drilled 21 gross (17 net) wells and participated in 21 gross (7 net) wells being drilled by Nance Petroleum, a wholly-owned subsidiary of St. Mary Land and Exploration. We entered into an agreement with Nance Petroleum to trade operations, whereby we operate wells in certain areas where they have small, stranded acreage positions and they operate in areas where we have similar positions. As of December 31, 2006, we had approximately 9 Bcf of net proved reserves in the Cabin Creek area based on a CIG index price of $4.46 per Mcf. We have identified 450 potential drilling locations and plan to drill 132 gross (116 net) wells and participate in the drilling of 11 gross (9 net) wells in the Cabin Creek area during the year ending December 31, 2007.
•: Other—As of December 31, 2006, we held approximately 9,000 gross (7,000 net) acres in three non-core project areas in Wyoming, all of which is undeveloped. As of December 31, 2006, we operated approximately 77 gross (55 net) wells in these areas. The wells were shut-in and we are currently evaluating future development opportunities in these project areas.

Montana—Powder River Basin

Our properties in Montana are located in four project areas: Kirby, Deer Creek, Bear Creek and Bradshaw. As of December 31, 2006, we held approximately 325,000 gross (222,000 net) acres in Montana for prospective CBM development and we operated 100% of this acreage. We have begun active development in both the Deer Creek and Kirby projects. During the year ended December 31, 2006, we drilled 130 gross (82 net) wells in two of our four project areas.

Because CBM development in Montana is still in its early stages, the permitting process is not as streamlined in Montana as it is in Wyoming. Permitting new wells in Montana on federal land involves submitting a POD, which typically covers 200 to 300 wells, to the Montana division of the United States Bureau of Land Management, or Montana BLM, and is subject to an environmental assessment and a review period. Permitting new wells on state and fee land involves submitting a POD, which typically covers 200 to 300 wells, to the Montana Oil and Gas Conservation Commission, and is also subject to an environmental assessment and a review period. Although the Montana BLM is still processing federal permit applications, it is currently subject to an injunction which prohibits it from approving any CBM drilling permits on federal lands in the Montana portion of the Powder River Basin. However, fee and state permits are unaffected by the injunction and any federal permits issued prior to the

injunction may continue to be developed. Approximately 59% of our gross acreage in Montana is on U.S. federal land. Prior to the issuance of the injunction, the permit approval process for federal lands typically took about a year. The permit approval process for fee and state lands typically takes three to six months. Please see "—Regulations—Permitting Issues for Federal Lands" for further discussion of the Montana federal permitting process and injunction.

As of December 31, 2006, we had a total of 67 approved drilling permits for our Montana properties. We are in the process of applying for an additional 1,344 drilling permits, 754 of which are on federal lands and 590 of which are on state or fee lands. We expect these permits to be approved during 2007. We anticipate drilling 73 gross (63 net) wells on our Montana properties during the year ending December 31, 2007. Set forth below is a summary of each of our Powder River Basin project areas in Montana.

•: Kirby—Kirby was acquired at the time of our initial formation in 2003. As of December 31, 2006, we held approximately 131,000 gross (51,000 net) acres in our Kirby project area, of which approximately 3% is developed. Kirby is located adjacent to and just north of Fidelity Exploration and Development Company's project area, which is north of J. M. Huber's project area in Wyoming. For the year ended December 31, 2006, Fidelity produced an average of 32 MMcf per day from this project area. As of December 31, 2006, we were producing approximately 0.7 gross (0.4 net) MMcf per day from approximately 93 gross (58 net) wells in this area. During the year ended December 31, 2006, we drilled 39 gross (24 net) wells in our Coal Creek pilot program in the Kirby area at depths between 500 and 1,200 feet in the Wall and Flowers-Goodale coals. We have begun commercial gas production from Kirby and transport our Kirby gas production through the Bitter Creek Pipeline, which became operational in late August 2006. We plan to target up to six distinct coal seams in the Kirby area.

As of December 31, 2006, we had approximately 1.2 Bcf of proved reserves in Kirby based on a CIG index price of $4.46 per Mcf. We have identified 1,650 potential drilling locations and plan to drill 2 gross (1 net) wells during the year ending December 31, 2007. All of our leases in Kirby are on fee and state lands.

•: Deer Creek—As of December 31, 2006, we held approximately 57,000 gross (47,000 net) acres in our Deer Creek project area, all of which is undeveloped. Our Deer Creek project area is located adjacent to St. Mary's Hanging Woman project to the south and Fidelity's CX Ranch Field to the west. Extensive drilling activity has occurred in both areas to date. We acquired this acreage as part of the acquisition of properties from Marathon Oil Corp. in March 2005 and we operate 100% of the acreage. We began development in 2005 in the Dietz POD which is located just to the southeast of Kirby. During the year ended December 31, 2006, we drilled 91 gross (58 net) wells in the Dietz POD, targeting eight distinct coal seams.

As of December 31, 2006, we had no proved reserves in Deer Creek. We have identified 620 potential drilling locations and plan to drill 71 gross (62 net) wells during the year ending December 31, 2007. Approximately 71% of our gross acreage in Deer Creek is on U.S. federal land.

•: Bear Creek—As of December 31, 2006, we held approximately 59,000 gross (53,000 net) acres in our Bear Creek project area, all of which is undeveloped. Our Bear Creek project area is located adjacent to and just north of our Cabin Creek project area in Wyoming and northeast of St. Mary's Hanging Woman project. We operate all of our acreage in Bear Creek, which was acquired from Marathon Oil Corp. in March 2005.

As of December 31, 2006, we had no proved reserves established in Bear Creek. We have identified over 700 potential drilling locations targeting eight distinct coal seams that appear to have significant gas potential based on recent core samples. Approximately 87% of our gross acreage in Bear Creek is on U.S. federal land, and as of December 31, 2006 we had no drilling permits for Bear Creek.

•: Bradshaw—Our Bradshaw project area is located to the northeast of our Cabin Creek project area in Wyoming. As of December 31, 2006, we held approximately 78,000 gross (71,000 net) acres in Bradshaw, all of which is undeveloped. As of December 31, 2006, we operated all of the acreage. As of December 31, 2006 we had interests in 17 wells in this area with significant gas shows.

As of December 31, 2006, we had no proved reserves established in Bradshaw. We have identified 1,000 potential drilling locations targeting eight distinct coal seams. Approximately 83% of our gross acreage in Bradshaw is on U.S. federal land, and as of December 31, 2006, we had no drilling permits for Bradshaw.

Wyoming—Green River Basin

On April 20, 2006, we acquired undeveloped natural gas properties, including related interests and assets, located in the Green River Basin of Wyoming from Kennedy Oil. The initial acquisition included approximately 30,000 gross (29,000 net) undeveloped acres for prospective CBM development in the Fort Union Big Red Coal formation. As of December 31, 2006, we owned 32,000 gross (31,000 net) undeveloped acres and we operated 100% of this acreage. As part of the acquisition, we also acquired 20 shut-in wells and 23 approved drilling permits and a 65% working interest in existing deep rights below the base of the Fort Union formation. As of December 31, 2006, we had drilled 14 gross (14 net) wells. As of December 31, 2006, we had 14 approved permits for our Green River Basin properties. We are in the process of applying for an additional 51 drilling permits which we expect to be approved before the end of 2007. During the year ending December 31, 2007, we anticipate drilling and completing 1 gross (1 net) well. As of December 31, 2006, we had identified 160 drilling locations based on 160-acre spacing (or 320 drilling locations based on 80-acre spacing). As of December 31, 2006, we had no proved reserves established in our Green River Basin properties.

Exploration & Production Activities

Producing Wells and Acreage

The following table sets forth certain information regarding our ownership of productive wells and total acreage as of June 23, 2003 and as of December 31, 2003, 2004, 2005 and 2006. For purposes of this table, productive wells are wells producing gas or dewatering.

			Approximate Leasehold Acreage
	Productive Wells		Approximate Leasehold Acreage
	Productive Wells		Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
June 23, 2003	81	48	3,240	2,320	135,760	60,680	139,000	63,000
December 31, 2003	149	87	5,960	3,480	133,040	59,520	139,000	63,000
December 31, 2004	312	165	12,480	6,600	181,520	69,400	194,000	76,000
December 31, 2005	404	203	16,160	8,120	401,840	263,880	418,000	272,000
December 31, 2006	529	281	26,160	17,400	427,840	290,600	454,000	308,000

Lease Expirations

		Expiring Acreage
		Expiring Acreage				Held by Production
		2007		2008		Held by Production		Suspended
		Gross	Net	Gross	Net	Gross	Net	Gross	Net
Wyoming
	Recluse	4,578	1,421	5,753	2,649	32,069	12,597	0	0
	Cabin Creek	40	35	1,393	567	7,232	3,456	578	538
	Green River Basin	1,760	1,760	0	0	7,920	7,728	2,560	2,560
Montana
	Bear Creek	0	0	2,045	1,849	0	0	49,536	46,903
	Deer Creek	0	0	4,001	2,881	6,554	3,570	40,499	35,393
	Bradshaw	0	0	0	0	0	0	61,648	61,648
	Kirby	5,018	2,509	45,140	22,570	4,722	2,361	34,533	17,266

Natural Gas Reserves

The following table summarizes the reserve estimate and analysis of net proved reserves of natural gas as of December 31, 2006, 2005, 2004 and 2003, in accordance with SEC guidelines. The data for the periods listed was prepared by NSAI in Dallas, Texas. The present value of estimated future net revenues from these reserves was calculated on a non-escalated price basis discounted at 10% per year. As of December 31, 2006, there were no proved reserves related to our Green River Basin assets.

			As of December 31,
			2003			2004			2005			2006(3)
Estimated net proved reserves:
	Proved developed producing (MMcf)			1,653			5,154			5,522			3,588
	Proved developed non-producing (MMcf)			3,279			2,277			2,690			4,292

		Total proved developed (MMcf)		4,932			7,431			8,212			7,880
	Proved undeveloped (MMcf)			13,212			17,346			18,827			12,409

		Total proved reserves (MMcf)		18,144			24,777			27,039			20,289

	Future cash flows before income taxes (in millions)		$	35.1		$	49.4		$	84.4		$	34.8
	PV-10 (in millions)(1)		$	24.6		$	34.8		$	58.5		$	25.3
	Income tax effect discounted at 10%		$	(5.9	)	$	(6.4	)	$	(14.8	)	$	(2.9	)

	Standardized measure (in millions)(2)		$	18.7		$	28.4		$	43.7		$	22.4
	Price used for proved reserve PV-10 (CIG index price per Mcf as of December 31)		$	5.575		$	5.515		$	7.715		$	4.460

(1): PV-10 represents the present value of estimated future net revenues attributable to our reserves using constant prices, as of the calculation date, discounted at 10% per year on a pre-tax basis. PV-10 was determined based on the market prices for natural gas on December 31 of each year. PV-10 differs from standardized measure of discounted future net cash flows because it does not include the effects of income taxes on future net cash flows. Neither PV-10 nor standardized measure represent an estimate of fair market value of our reserves. Although PV-10 is not a financial measure calculated in accordance with GAAP, management believes that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to any given company affect the amount of estimated future income taxes, the use of a pre-tax measure is helpful when comparing companies in our industry.

(2): The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved reserves discounted at 10% after giving effect to income taxes, and as calculated in accordance with SFAS No. 69.
(3): Total proved reserves for 2006 declined primarily due to declines in the price of natural gas. Please see "Risk Factors—The volatility of natural gas and oil prices could have a material adverse effect on our business."

Summary of Well Activity

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

				Year Ended December 31,
		June 23, 2003- December 31, 2003		Year Ended December 31,
		June 23, 2003- December 31, 2003		2004		2005		2006
		Gross	Net	Gross	Net	Gross	Net	Gross	Net
Wells Drilled:
	Capable of Production	123	62	121	59	136	65	230	139
	Dry	1	0	1	1	1	1	0	0
Wells Acquired		240	148	1	1	0	4	29	29
Wells Abandoned		5	3	2	1	0	0	1	1

Net Increase in Capable Wells		357	207	119	58	135	68	258	167

We expect to drill and complete 260 gross (207 net) wells during the year ending December 31, 2007.

Gas Gathering, Transportation and Compression

We have constructed and plan to continue to construct additional low-pressure gas gathering systems to transport natural gas from the wellhead to compression stations as part of the completion of a well. We use third-party services to compress and transport our natural gas to market in return for compression and transportation fees.

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

We have entered into a low-pressure gas gathering agreement and a high-pressure gathering and compression agreement with Bitter Creek Pipelines, LLC for the Kirby and Deer Creek prospects. Under the low-pressure gas gathering agreement, Bitter Creek Pipelines constructed a central compression site to compress a maximum daily quantity of gas for delivery into Bitter Creek Pipelines' high-pressure gathering line in exchange for a gathering payment comprised of a commodity rate based on average daily volumes and monthly demand charges based on the number of compression sites and compressors. Pursuant to the high-pressure gas gathering agreement, Bitter Creek Pipelines will transport a maximum daily quantity of our gas on its high-pressure line in exchange for a demand fee,

gathering rate and processing service fee, as applicable. The rates under these agreements will be adjusted annually for inflation. The Bitter Creek Pipelines high-pressure line will deliver our gas to the Bitter Creek Landeck Compressor Station for redelivery north into Williston Basin Interstate Pipeline Company and/or south into Thunder Creek Gas Services, LLC and any other future delivery points on the Bitter Creek Pipelines system. The low-pressure gas gathering agreement has an initial term of ten years, and the high-pressure gas gathering agreement has an initial term of five years, in each case, from August 28, 2006, the effective date of the agreements. The Bitter Creek Pipelines pipeline and compression facilities became operational in late August 2006. Each gas gathering agreement will be automatically renewable after the initial term on a month-to-month basis, unless terminated by either party upon 60 days' notice. In addition, after five years, if Bitter Creek Pipelines determines that it is no longer economically feasible to provide services under the low-pressure gas gathering agreement, it may terminate the low-pressure gas gathering agreement in its sole discretion with 60 days' written notice.

By virtue of an acreage dedication by Pennaco to Cantera Gas Holdings, LLC for the gathering and compression of gas on lands acquired by us from Pennaco, we will utilize Cantera Gas to gather and compress our gas in the Cabin Creek Prospect. Right-of-way and construction have begun to connect this area to the Big Horn Gas Gathering Pipeline which will take us to multiple outlets. Pursuant to an agreement between us and Bighorn Gas Gathering, L.L.C., a subsidiary of Cantera, Bighorn Gas Gathering is constructing and will operate, and we have agreed to pay the costs of the construction and operation of, the gas gathering extension that will connect our properties acquired from Pennaco to the Big Horn Gas Gathering Pipeline. The agreement has an initial term of one year and will continue on a month-to-month basis thereafter unless terminated by either party upon 90 days' written notice. For five years after the effective date of the agreement, Big Horn Gas Gathering has an option to purchase the gas gathering extension from us. Under certain circumstance, Big Horn Gas Gathering also has a right of first refusal with respect to the extension.

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

Natural gas in the Powder River Basin is transported by three intrastate gathering pipelines, Thunder Creek Gas Gathering, Fort Union Gas Gathering and the Kinder Morgan Lateral, and one interstate pipeline, the Grasslands Pipeline. Gas transported from the Powder River Basin as of December 31, 2006 was approximately 1.1 Bcf per day, with remaining available capacity of approximately 0.2 Bcf per day, or 17% of the total capacity. The gas is moved to marketing hubs in southern Wyoming or western North Dakota, where pipeline interconnections enable gas to move to distribution centers, primarily in the midwestern and southern United States. However, a surplus of natural gas arriving at these marketing hubs from the Powder River Basin and elsewhere relative to the available takeaway capacity from these hubs has caused Rocky Mountain gas to trade at a discount to the Henry Hub Index. From January 1, 2006 through December 31, 2006, Rocky Mountain gas traded at a negative differential to the Henry Hub Index of between $0.22 and $6.58 and averaged $1.65. Additional takeaway capacity should help alleviate the constraints on the transportation of Rocky

Mountain gas and reduce the differential between gas produced in the Rocky Mountain region and the Henry Hub Index. Two major projects are expected to increase takeaway capacity: Kinder Morgan's Rocky Mountain Express, which is expected to transport up to 2 Bcf per day from Wamsutter, Wyoming to Mullet, Ohio, and El Paso's Cheyenne Hub Extension, which is expected to add capacity of 1 Bcf per day from the Cheyenne Hub to Perryville, Kentucky. Both projects are expected to be completed in 2008. The State of Wyoming has also authorized up to $1 billion in bonds to finance and develop infrastructure to help achieve efficient movement of gas out of Wyoming.

Marketing and Customers

We currently have a contract with Enserco Energy Inc. to purchase the gas at the tailgate of the Clear Creek compression. Western Gas Resources, Inc. currently purchases our gas at Glenrock after the compression and transportation from our Squaw Creek area. Both Enserco Energy and Western Gas Resources have extensive experience in gas marketing services in the Rocky Mountain region and specifically in the Powder River and surrounding gas producing basins. Our contractual arrangements with Enserco Energy and Western Gas Resources are based on the CIG index price and are cancelable upon thirty and sixty days' written notice, respectively, if we determine there are more attractive purchasing arrangements in the marketplace. During the year ended December 31, 2005, Enserco Energy and Western Gas Resources purchased 76% and 24% of our gas sold, respectively. The contractual arrangements for 2006 have paid premiums above the CIG index price of $0.06/Mcf to $0.71/Mcf, dependent upon the market outlook and conditions. During the year ended December 31, 2006, Enserco Energy, Western Gas Resources and United Energy Trading purchased 66%, 21% and 11% of our gas sold, respectively. In the event that Enserco Energy, Western Gas Resources or United Energy Trading were to experience financial difficulties or were to no longer purchase our natural gas, we could, in the short-term, experience difficulty in our marketing of natural gas, which could adversely affect our results of operations.

Hedging Activities

We seek to reduce our exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow us to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided by the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling prices and floors provided in those contracts.

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of December, 2006. At December 31, 2006, we had no hedged volumes beyond December 2007. However, in April 2007, we hedged an additional 3,000 MMBtu per day from January 2008 through December 2008 at a floor price of $6.50 per MMBtu and a ceiling price of $8.20 per MMBtu based on the CIG Inside FERC published price. Please see Note 8 of the notes to the audited financial statements appearing elsewhere in this prospectus for additional information regarding our hedging for 2005 and 2006.

		Year Ending December 31, 2007
		(Unaudited)
Natural Gas Collars:
Contract volumes (MMBtu):
	Floor		1,733,000
	Ceiling		1,733,000
Weighted-average fixed price per MMBtu(1):
	Floor	$	6.58
	Ceiling	$	8.75
Fixed-price sales(2)		$	8.75
Fair value, net (thousands)(3)		$	2,856
Total Natural Gas Contracts:
Contract volumes (MMBtu)			1,733,000
Weighted-average fixed price per MMBtu(1)		$	6.58
Fixed-price sales(2)		$	8.75
Fair value, net (thousands)(3)		$	2,856

(1): Volumes hedged using the CIG index price published in the first issue of Inside FERC's Gas Market Report for each calendar month of the derivative transaction.
(2): Assumes ceiling prices for natural gas collar volumes.
(3): Fair value based on CIG index price in effect for each month as of December 31, 2006.

Competition

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

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

Seasonal Nature of Business

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

Employee and Labor Relations

As of March 31, 2007, we had 39 full-time employees. We believe that our relationships with our employees are good. None of our employees are covered by a collective bargaining agreement. From time to time, we use the services of independent consultants to perform various professional services, particularly in the areas of legal and regulatory services. Independent contractors often perform well drilling and production operations, including pumping, maintenance, dispatching, inspection and testing.

Regulations

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

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

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of

these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

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

Environmental Regulation of Gas Operations

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

While it is not possible to quantify the costs of compliance with all applicable federal, state and local environmental laws, those costs have been and are expected to continue to be significant. We did not make any capital expenditures for environmental control facilities for the year ended December 31, 2006. Any environmental costs are in addition to well closing costs, property restoration costs and other, significant, non-capital environmental costs, including costs incurred to obtain and maintain permits, gather and submit required data to regulatory authorities, characterize and dispose of wastes and effluents, and maintain management operational practices with regard to potential environmental liabilities. Compliance with these federal and state environmental laws has substantially increased the cost of gas production, but is, in general, a cost common to all domestic gas producers.

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

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

•: the Clean Air Act;
•: the Federal Water Pollution Control Act/Clean Water Act;
•: the National Environmental Policy Act;
•: the Federal Land Policy and Management Act;
•: the Toxic Substances Control Act;
•: the Comprehensive Environmental Response, Compensation and Liability Act (Superfund);
•: the Solid Waste Disposal Act/Resource Conservation and Recovery Act;
•: the Emergency Planning and Community Right to Know Act; and
•: the Endangered Species Act;

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

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

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

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

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

states from time to time and may include initiatives at county, municipal and local government levels. These various initiatives could have a similar adverse impact on us.

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

Federal Regulation of the Sale and Transportation of Gas

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

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

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

The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and FERC continues to review and modify its open access regulations. In particular, FERC has reviewed its transportation regulations, including how they operate in conjunction with state proposals for retail gas marketing restructuring, whether to eliminate cost of service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. In February 2000, FERC issued Order No. 637 amending certain regulations governing interstate natural gas pipeline companies in response to the development of more competitive markets for natural gas and natural gas transportation. The goal of Order No. 637 is to "fine tune" the open access regulations implemented by Order No. 636 to accommodate subsequent changes in the market. Key provisions of Order No. 637 include:

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

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

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

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

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

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

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

State Regulation of Gas Operations

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

Ground Water Well Applications and Reservoir Permits

In March 2006, we received a notice of violation and order from the Wyoming State Engineer's Office. Based on a Wyoming statute that became effective in July 2005, the notice of violation and order alleged that we had produced water from 14 wells without the appropriate permits and that we were storing water in reservoirs for which completed and approved permits were not in place. Pursuant to a settlement agreement with the Wyoming State Engineer's Office, we have completed the

permitting process for the 14 wells and are upgrading the affected reservoirs. We have already resumed operations at all 14 of the wells. The affected wells and permits represent a small percentage of the total number of CBM wells that we have in production and are not a material portion of our operations.

Permitting Issues for Federal Lands

Approximately 59% and 61% of our gross acreage in Montana and Wyoming, respectively, is on U.S. federal land. Federal leases in Montana and Wyoming must be developed pursuant to the U.S. BLM's Resource Management Plans. Federal leases are also subject to the National Environmental Policy Act and Federal Land Policy Management Act. The National Environmental Policy Act process imposes obligations on the federal government that may result in legal challenges and potentially lengthy delays in obtaining project permits or approvals. The Montana and Wyoming BLMs have been subject to several lawsuits from various environmental groups challenging Resource Management Plan amendments and supporting Environmental Impact Statements addressing CBM development in Montana and Wyoming. In 2003, the Montana BLM and Wyoming BLM each amended their Resource Management Plans based in part on Environmental Impact Statements prepared pursuant to the National Environmental Policy Act. Shortly after the issuance of the Environmental Impact Statements and amended Resource Management Plans, various plaintiffs brought legal actions challenging the Montana and Wyoming Environmental Impact Statements and Resource Management Plans. There have been five federal district court challenges to the Montana Environmental Impact Statements. Three of these are currently before the United States Court of Appeals for the Ninth Circuit on appeal. There are also three federal district court challenges to the Wyoming Environmental Impact Statements currently pending before the United States District Court for the District of Wyoming. We have intervened in several of these cases to protect our interests in these proceedings. The outcome and timing of these cases could affect the Montana and Wyoming BLM's ability to approve PODs and issue drilling permits and thus could affect our ability to further develop our federal leases in Montana and Wyoming. In particular, the Ninth Circuit has granted a motion for a blanket injunction pending appeal which prohibits the Montana BLM from approving any CBM drilling permits on federal lands in the Powder River Basin of Montana. This injunction will remain in place at least until the Ninth Circuit rules on pending appeals in two consolidated cases that have been briefed and argued before the court. As of March 31, 2007, this injunction remains in effect. While these cases have been progressing toward resolution, we cannot predict how or when the courts will resolve these matters, nor can we foresee future challenges which may arise. We believe we will ultimately be successful in developing our leases as planned, but cannot assure you as to when or how these suits will be resolved.

In October 2005, we received a notice of violation from the Wyoming BLM stating that we had drilled a single well without the proper permits. We began an informal review process with the Wyoming BLM and in May 2006 met with the state director in an attempt to resolve the violation. In September 2006, we paid a fine of $160,000 and resolved the violation.

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

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

Employee Health and Safety

We are subject to the requirements of the Occupational Safety and Health Act, referred to as OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In

addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements and general industry standards regarding recordkeeping requirements and the monitoring of occupational exposure to regulated substances.

Legal Proceedings

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of our business. Like other natural gas and oil producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore it is extremely difficult to reasonably quantify future environmental-related expenditures.

The following represent legal actions that are currently pending. No assurance can be given that these legal actions will be resolved in our favor. However, management believes, based on its experiences to date, that these matters will not have a material adverse impact on our business, financial position or results of operations.

We, together with the State of Montana, the Montana Department of Environmental Quality, the Montana Board of Oil and Gas Conservation and the Department of Natural Resources, have been named as defendants in a lawsuit (Civil Cause No. DV-05-27) filed on May 19, 2005 in the Montana 22nd Judicial District Court, Bighorn County by Diamond Cross Properties, LLC relating to the Coal Creek POD. The plaintiff is a surface owner with properties located in Big Horn County and Rosebud County, Montana where we serve as operator and own a working interest in the minerals under lease. The plaintiff seeks to permanently enjoin the State of Montana and its administrative bodies from issuing licenses or permits, or authorizing the removal of ground water from under the plaintiff's ranch. In addition, the plaintiff further seeks to preliminarily and permanently enjoin us on the basis that our operations lack adequate safeguards required under the Montana state constitution. On August 25, 2005, the district judge issued an order denying without prejudice the application for temporary restraining order and preliminary injunction requested by the plaintiff. The case was appealed by the plaintiff to the Montana Supreme Court. On November 16, 2005, the Montana Supreme Court issued an order that denied enjoining the Coal Creek POD, and recently, the Montana Supreme Court remanded the case back to the district court for a decision on the merits.

We, together with the defendants above, have also been named as defendants in a lawsuit (Civil Cause No. DV-05-70) filed on September 21, 2005 in the Montana 22nd Judicial District Court, Bighorn County by Diamond Cross Properties, LLC relating to the Dietz POD. The plaintiff seeks similar relief as in the Coal Creek POD suit. Additional parties have intervened as plaintiffs and a defendant in the action.

The two cases have been combined. The judge in the combined case is reviewing the briefs, and will then decide whether the plaintiffs are entitled to a preliminary injunction with respect to the Coal Creek POD, and whether either the plaintiffs or defendants are entitled to summary judgment with respect to the Dietz POD. Based on the information available to date, we believe that the plaintiffs' claims are without merit, and we intend to defend this case vigorously.

We were named as defendants in two related lawsuits (Civil Action No. 06CV0047J) filed on March 30, 2006 in the United States District Court, Wyoming by Burning Rock Energy, LLC and (Case No. 06-CV-01627-MDM-MEH) filed on April 25, 2006 in the United States District Court for the District of Colorado by John R. Behrmann, et al. claiming various contract and tort claims against us relating to a like-kind exchange between us and the plaintiffs of approximately 1,000 acres of leased acreage in January 2004. The plaintiffs claimed, in part, that the leases transferred by us to Burning

Rock did not terminate upon nonpayment of shut-in rentals and further, that we trespassed by releasing from the original lessors the properties originally transferred to Burning Rock under the exchange agreement. In April 2007, we settled these claims with the plaintiffs and both lawsuits have been dismissed. The settlement arrangement included a $500,000 payment by us to Burning Rock together with an assignment by us to Burning Rock of a 69.5% carried working interest in the disputed leased acreage.

Please see "—Permitting Issues for Federal Lands" regarding litigation in which we have intervened with respect to CBM production in Wyoming and Montana.

MANAGEMENT

Directors, Executive Officers and Key Employees

The following sets forth the names of our executive officers and directors, their ages as of December 31, 2006, and their current positions and offices.

Name	Age	Position
Steven A. Webster	55	Chairman of the Board
Peter G. Schoonmaker	48	Chief Executive Officer, President and Director
Ronald T. Barnes	47	Chief Financial Officer, Senior Vice President and Secretary
Robert L. Cabes, Jr.	37	Director
Jeffrey P. Gunst	29	Director
Sylvester P. Johnson, IV	50	Director
F. Gardner Parker	64	Director
Susan C. Schnabel	45	Director
Gordon L. Olson	55	Vice President—Engineering
Terry L. Savage	54	Vice President—Land

Set forth below is a brief description of the business experience of each of our executive officers and directors listed above and an additional key employee.

Executive Officers and Directors

Mr. Steven A. Webster. Mr. Webster has been the Chairman of our board of directors and a director since our inception in June 2003. Mr. Webster has served as Co-Managing Partner of Avista Capital Holdings, L.P., a private equity firm focused on investments in the energy, media and healthcare sectors, since July 2005. From January 2000 until June 2005, Mr. Webster served as Chairman of Global Energy Partners, or GEP, a specialty group within Credit Suisse's asset management business that made investments in energy companies. Mr. Webster has continued to serve as a consultant to Credit Suisse's asset management business through arrangements with MB Advisory Partners, LLC, an affiliate of Avista, and sits on the boards of, and monitors the operations of, various existing DLJ Merchant Banking portfolio companies. From 1998 to 1999, Mr. Webster served as Chief Executive Officer and President of R&B Falcon Corporation, and from 1988 to 1998, Mr. Webster served as Chairman and Chief Executive Officer of Falcon Drilling Corporation, both offshore drilling contractors. Mr. Webster serves as a director of Grey Wolf, Inc., SEACOR Holdings Inc., Hercules Offshore, Inc., Camden Property Trust and Geokinetics, Inc. Mr. Webster also serves as a director of various privately-held companies, including Enduring Resources, LLC, Laramie Energy, LLC and Frontier Drilling, ASA. In addition, Mr. Webster serves as Chairman of Basic Energy Services, Inc. and Carrizo Oil & Gas, Inc. Mr. Webster was the founder and an original shareholder of Falcon Drilling Company, a predecessor to Transocean Inc., and was a co-founder and original shareholder of Carrizo. Mr. Webster holds a B.S.I.M. from Purdue University and an M.B.A. from Harvard Business School.

Mr. Peter G. Schoonmaker. Mr. Schoonmaker has served as our Chief Executive Officer since our inception in June 2003, and as President and a director since February 2006. Mr. Schoonmaker has over 16 years of experience in the acquisition, exploration and development of coalbed methane properties as well as conventional oil and gas properties. From 1980 to 1985 Mr. Schoonmaker was an independent landman for various oil and gas companies and operated a land management company in Denver, Colorado. From 1985 to 1995 he served as President, owner and operator of a land and agricultural company based in Colorado and Wyoming. In 1995, Mr. Schoonmaker joined U.S. Energy, a publicly held mining and energy company, as a land manager and also became Executive Vice President and a director of Yellowstone Fuels Corporation, a subsidiary of U.S. Energy. In November 1999, U.S. Energy formed Rocky Mountain Gas, a coal bed natural gas company. He served

as President, Chief Operating Officer and was a director of Rocky Mountain Gas from its inception until June 23, 2003.

Mr. Ronald T. Barnes. Mr. Barnes has served as our Chief Financial Officer and Senior Vice President since December 2005 and our Secretary since February 2006 and since joining Pinnacle in January 2004, has also served as our Vice President-Finance and our Controller. Mr. Barnes has 25 years of experience in public accounting and industry related to all aspects of the upstream sector of oil and gas acquisition, exploration, development and production. Prior to joining Pinnacle, Mr. Barnes worked for EnCana Oil and Gas (USA), Inc. from 2002 through January, 2004 as lead controller and was responsible for all accounting aspects of U.S. operations. From 1988 through 2002, Mr. Barnes held various positions with JN Exploration and Production LP, including most recently serving as Controller and Vice President of Marketing of JN Exploration and Production where he managed the accounting and marketing for the acquisition, drilling and production of properties in 17 states and the Outer Continental Shelf of the Gulf of Mexico. From 1983 through 1988, Mr. Barnes held various positions with Raymond T. Duncan Oil Properties and from 1981 through 1983, he worked for a major public accounting firm. Mr. Barnes is a member of the Council of Petroleum Accountants Societies, the Independent Petroleum Association of Mountain States, the Petroleum Association of Wyoming and the Montana Petroleum Association. Mr. Barnes earned a B.S. in accounting from the University of Wyoming and an M.B.A. from the University of Colorado.

Mr. Robert L. Cabes, Jr. Mr. Cabes has served as a director since our inception in June 2003. Mr. Cabes is a Partner of Avista Capital Holdings, L.P., a private equity firm focused on investments in the energy, media and healthcare sectors, and previously served as a Principal since July 2005. From April 2001 to June 2005, Mr. Cabes served as a Principal of Global Energy Partners, or GEP, a specialty group within Credit Suisse's asset management business that made investments in energy companies. Mr. Cabes currently serves as a director of Celtique Energie Limited, MedServe, Inc. and Geokinetics, Inc. Prior to joining GEP, Mr. Cabes was with Credit Suisse's and Donaldson, Lufkin and Jenrette's Investment Banking Division (prior to its acquisition by Credit Suisse in 2000) where he worked on debt and equity securities underwriting and mergers and acquisitions for energy companies. Before joining Donaldson, Lufkin and Jenrette, Mr. Cabes spent six years with Prudential Securities in its energy corporate finance group in Houston and New York. Mr. Cabes holds a B.B.A. from Southern Methodist University and is a CFA charterholder.

Mr. Jeffrey P. Gunst. Mr. Gunst has served as a director since our inception in June 2003. Mr. Gunst has served as a Vice President at Avista Capital Holdings, L.P., a private equity firm focused on investments in the energy, media and healthcare sectors, since July 2005. Mr. Gunst previously worked with Global Energy Partners, or GEP, a specialty group within Credit Suisse's asset management business that made investments in energy companies, beginning in 2001. Mr. Gunst currently serves as a director of Celtique Energie Limited. Prior to joining GEP, Mr. Gunst was an investment banker for Credit Suisse and Donaldson, Lufkin and Jenrette where he worked primarily on energy transactions. Mr. Gunst received a B.B.A. and B.S. from Southern Methodist University.

Mr. Sylvester P. Johnson, IV. Mr. Johnson has served as a director since our inception in June 2003. Mr. Johnson has served as President, Chief Executive Officer and a director of Carrizo since December 1993. Prior to December 1993, he worked for Shell Oil Company for 15 years. His managerial positions included Operations Superintendent, Manager of Planning and Finance and Manager of Development Engineering. Mr. Johnson serves as a director of Basic Energy Services, Inc. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in Mechanical Engineering from the University of Colorado.

Mr. F. Gardner Parker. Mr. Parker has served as a director since our inception in June 2003. Mr. Parker has been Lead Outside Trust Manager with Camden Property Trust, a real estate investment trust, since 1998 and a director since 1993. Mr. Parker also serves on the board of directors

of Carrizo, Crown Resources Corporation, Sharps Compliance Corp., Blue Dolphin Energy Company and Hercules Offshore, Inc. In addition, Mr. Parker serves on the board of directors of the following private companies: Gillman Automobile Dealerships, Net Near U Communications, Camp Longhorn, Inc., nii communications, inc. and Sherwood Healthcare Inc. Mr. Parker also worked with Ernst & Ernst (now Ernst &Young LLP) for 14 years, for seven of which he served as a partner. Mr. Parker received a B.B.A. from The University of Texas.

Ms. Susan C. Schnabel. Ms. Schnabel has served as a director since July 2005. Ms. Schnabel has served as Managing Director with DLJ Merchant Banking Partners, the leveraged corporate private equity platform of Credit Suisse's asset management business, since 1998. She joined Donaldson, Lufkin and Jenrette's Investment Banking Division in 1990 and DLJ Merchant Banking Partners in 1998. In 1997, she left Donaldson, Lufkin and Jenrette's Investment Banking Division to serve as Chief Financial Officer of PETsMART, a high growth specialty retailer of pet products and supplies, and joined DLJ Merchant Banking in her present capacity in 1998. Ms. Schnabel is also a director of Rockwood Holdings (NYSE: ROC), DeCrane Aircraft Holdings, Inc., Environmental Systems Products, Inc., Target Media Partners, Frontier Drilling and Laramie Energy, LLC. Ms. Schnabel received a B.S. from Cornell University and an M.B.A. from Harvard Business School.

Additional Key Employees

Mr. Gordon L. Olson. Mr. Olson became our Vice President-Engineering in March 2006. He previously served as our Reserve Engineer from January 2005 until March 2006. Prior to joining Pinnacle, Mr. Olson was an engineering manager with CDX Gas, Inc. from May 2004 to January 2005, working on exploitation and exploration projects in the San Juan Basin. From April 2003 to May 2004, Mr. Olson worked for EnCana Oil and Gas (USA), Inc. as a CBM reservoir engineer within the New Ventures group. From September 1999 until he joined EnCana, Mr. Olson was a consultant with Wind River Consultants, LLC. Prior to September 1999, Mr. Olson was employed by the Colorado School of Mines unconventional resource consortium and held positions at KCS Mountain Resources Inc., as Manager Reservoir Engineering, and Resource Services International, Inc., as an Associate Reservoir Engineer. Mr. Olson has over 12 years of experience in the exploration and development of coalbed methane properties as well as conventional and oil and gas properties. Mr. Olson has a B.S. in Petroleum Engineering from North Dakota State University and an M.S. in Petroleum Engineering from the Colorado School of Mines. Mr. Olson is a member the Society of Petroleum Engineers, American Petroleum Institute and Rocky Mountain Association of Geologists.

Mr. Terry L. Savage. Mr. Savage was appointed our Vice President—Land in February 2007. Mr. Savage has over 30 years of oil and gas land experience. Prior to joining Pinnacle, Mr. Savage was Vice-President—Land for American Oil & Gas, Inc. from January 2006 to February 2007, managing all land and land administration matters. From January 1999 to January 2006, Mr. Savage was an oil and gas land consultant providing acquisition, divestiture, lease acquisition and property management services. From 1987 to 1998, Mr. Savage was employed by Snyder Oil Corporation serving in various management positions, including as a land manager and Vice President—Land. Prior to 1987, Mr. Savage served as Vice-President—Land for Mizel Petro-Resouces, Inc. for 3 years, as a land manager for Sundance Oil Company for 3 years and 6 years in various land positions with Grace Petroleum Corporation and Mobil Oil Corporation. Mr. Savage has a B.B.A. from the University of Oklahoma in Petroleum Land Management. Mr. Savage is a member of the American Association of Professional Landmen and is a Certified Professional Landman.

Composition of the Board of Directors

Our board of directors currently consists of seven members. Pursuant to our amended and restated securityholders' agreement, DLJ Merchant Banking and affiliates of Carrizo and U.S. Energy had the right, prior the consummation of our private placement, to designate members of the board of

directors. Prior to our private placement, DLJ Merchant Banking's designees, Messrs. Webster, Cabes and Gunst and Ms. Schnabel, were elected to our board of directors. Carrizo's designees, Messrs. Johnson and Parker, and U.S. Energy's designees were also elected to our board prior to our private placement. Effective September 25, 2006, both of U.S. Energy's designees resigned from the board of directors in connection with the sale by U.S. Energy of all of its shares of our common stock to DLJ Merchant Banking. The right to designate board members terminated upon consummation of our private placement, although each of the board members elected prior to our private placement may continue to serve on the board of directors until the expiration of his or her respective term or resignation as set forth below. Please see "Certain Relationships and Related Party Transactions—Amended and Restated Securityholders Agreement with DLJ Merchant Banking and Other Significant Stockholders" for further information.

As a private company, we have not been required to comply with the corporate governance rules of the NASDAQ, nor have we been subject to the Sarbanes-Oxley Act of 2002 and related SEC rules. The listing requirements of the NASDAQ require that our board of directors be composed of a majority of independent directors within one year of listing. Accordingly, the board of directors is engaged in an active search to identify and recruit new directors meeting the independence criteria under these rules. In addition, upon the effectiveness of this registration statement, we will be subject to the Sarbanes-Oxley Act and related SEC rules.

Our second amended and restated certificate of incorporation and amended and restated bylaws provide for a classified board of directors consisting of three classes of directors, each serving staggered three-year terms. The initial terms of the directors of each class will expire at the annual meeting of stockholders to be held in 2007 (Class I), 2008 (Class II) and 2009 (Class III). At each annual meeting of stockholders, one class of directors will be elected for a full term of three years to succeed that class of directors whose terms are expiring. The classification of directors is as follows:

•: Class I—Messrs. Gunst and Schoonmaker;
•: Class II—Messrs. Cabes and Johnson;
•: Class III—Mr. Parker, Ms. Schnabel and Mr. Webster.

The division of our board of directors into three classes with staggered terms may delay or prevent a change in our management or a change in control. Please see "Description of Capital Stock—Anti-Takeover Provisions."

Committees of the Board of Directors

Our board of directors has established four committees: an audit committee, a nominating and corporate governance committee, a compensation committee and a hedging committee. In compliance with NASDAQ listing standards and SEC rules and regulations, upon the listing of our common stock on the NASDAQ, one member of each of the audit, nominating and corporate governance, and compensation committees will be an independent director (as defined by NASDAQ listing standards and, in the case of the audit committee, SEC rules), within 90 days of listing, a majority of the members of each such committee will be independent directors, and within one year of listing, each such committee will be composed entirely of independent directors.

Audit Committee

Messrs. Parker (Chairman), Johnson and Cabes serve as the members of our audit committee. The board has determined that Messrs. Parker and Johnson are independent directors (as defined by NASDAQ listing standards and SEC rules). In addition, the board has determined that Mr. Parker is

an audit committee financial expert (as defined by SEC rules). The principal duties of the audit committee include the following:

•: to oversee and review our accounting and financial reporting processes and the audits and integrity of our financial statements;
•: to engage and evaluate our independent auditors; and
•: to review our procedures for internal auditing and the adequacy of our internal accounting controls.

Our board of directors has adopted a written charter for the audit committee that will be available on our website subsequent to this offering.

Nominating and Corporate Governance Committee

Messrs. Webster (Chairman) and Johnson and Ms. Schnabel serve as the members of our nominating and corporate governance committee. The board has determined that Mr. Johnson and Ms. Schnabel are independent directors (as defined by NASDAQ listing standards). The principal duties of the nominating and corporate governance committee include the following:

•: to recommend to the board of directors proposed nominees for election to the board of directors by the stockholders at annual meetings, including an annual review as to the renominations of incumbents and proposed nominees for election by the board of directors to fill vacancies that occur between stockholder meetings; and
•: to make recommendations to the board of directors regarding corporate governance matters and practices.

Our board of directors has adopted a written charter for the nominating and corporate governance committee that will be available on our website subsequent to this offering.

Compensation Committee

Messrs. Cabes (Chairman), Johnson and Parker and Ms. Schnabel serve as the members of our compensation committee. The board has determined that Messrs. Cabes, Johnson and Parker and Ms. Schnabel are independent directors (as defined by NASDAQ listing standards). The principal duties of the compensation committee include the following:

•: to administer our stock plans and incentive compensation plans, including our Stock Incentive Plan, and in this capacity, make all option grants or awards to our directors and employees under such plans;
•: to make recommendations to the board of directors with respect to the compensation of our Chief Executive Officer and our other executive officers; and
•: to establish compensation and employee benefit policies.

Our board of directors has adopted a written charter for the compensation committee that will be available on our website subsequent to this offering.

Hedging Committee

Messrs. Johnson and Cabes serve as the members of our hedging committee. The principal duty of the hedging committee is to review and approve hedging transactions to be entered into by us.

Web Access

Subsequent to this offering, we will provide access through our website at www.pinnaclegas.com to information relating to our corporate governance, including a copy of each board committee charter, our Code of Ethics, our Corporate Governance Guidelines and other matters impacting our governance principles. You may also contact our Chief Financial Officer for paper copies of these documents free of charge.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of directors or compensation committee.

During fiscal year 2005, the board of directors determined executive compensation.

Compensation Discussion and Analysis

Introduction

From our formation in June 2003 through April 2006, we were privately owned and controlled by our three founding investors, DLJ Merchant Banking, Carrizo and U.S. Energy, which collectively owned approximately 99.6% of our outstanding common stock on a fully diluted basis and held eight of the nine seats on our board of directors.

At our formation, our founding investors' strategy was to make a significant investment in us and then oversee and nurture that investment. The overriding objective of our founding investors was to increase our size and enterprise value. The compensation of our named executive officers since our formation has been designed to support and complement the successful execution of this strategy. As a result, our overall approach to executive compensation since our formation has been more similar to that of a privately held, growth stage company than to that of a large, publicly traded company.

Our named executive officers for the fiscal year ended December 31, 2006 were Peter G. Schoonmaker, our Chief Executive Officer and President, and Ronald T. Barnes, our Chief Financial Officer, Senior Vice President and Secretary.

Overview of Our Compensation Policies and Objectives

Our overall policy with respect to executive compensation has been to provide levels and types of compensation that attract and retain highly qualified executive officers and align their interests with those of our stockholders by linking portions of their compensation with specific business and strategic objectives and our overall business and financial performance. Accordingly, our policy is to pay our executive officers a competitive compensation package that includes a significant incentive compensation component in addition to salary. In addition, it is our policy to pay incentive compensation that is tied to both our short- and long-term performance. During 2006, incentive compensation accounted for approximately 45% and 51% of Messrs. Schoonmaker's and Barnes' total compensation, respectively (excluding a one-time transaction-related bonus). In making compensation recommendations and decisions, the Compensation Committee considers the compensation of executives at similar companies in the oil and gas industry.

Elements of Compensation

During 2006, the compensation packages for our named executive officers included five principal elements:

•: a base salary;

•: a performance-based cash bonus;
•: long-term equity incentive awards, which in 2006 consisted of grants of stock options;
•: limited perquisites and other benefits; and
•: a one-time bonus relating to our April 2006 private placement.

These elements, taken together, constituted a flexible and balanced approach to determining the total compensation of our named executive officers. For example, the performance-based cash bonus for 2006 was tied to our achievement of certain operational and financial goals over a period of one year, while the ultimate value of the equity incentive awards will largely depend upon our overall performance over a multi-year period.

We consider long-term equity incentive compensation to be an important element of our compensation program for executive officers. Since our formation, our founding investors have expected our management team not only to increase the enterprise value of our company but also to expand our business and operations. We believe that meaningful equity participation by each executive officer motivates and rewards the creation and preservation of long-term stockholder value. This belief is reflected in the aggregate awards of stock options that have been made to our executive officers since our formation.

Our Compensation Committee did not retain a compensation consultant during 2006, but established compensation packages that it concluded were appropriate based on the general business and particular compensation experience and knowledge of its members, which experience and knowledge was gained through working with other privately held, growth stage companies, as well as public companies.

As of March 31, 2007, the Compensation Committee had not yet made a determination with respect to 2007 compensation for our executive officers.

Base Salary. The Compensation Committee periodically reviews and establishes the base salaries of our executive officers. Generally, base salaries are determined according to the following factors: the individual's experience level, the scope and complexity of the position held, and the annual performance of the individual. Both Messrs. Schoonmaker and Barnes received significant salary increases for 2006, based on (1) our and their performance during 2005 and (2) the expanded responsibilities they would take on as we prepared to become a public company. The Compensation Committee has not yet determined or made a recommendation with respect to the 2007 base salaries for Messrs. Schoonmaker and Barnes.

Performance-Based Bonuses. During 2006, we established an incentive compensation plan pursuant to which cash bonuses, as a percentage of base salary, would, in the sole discretion of the Compensation Committee, be paid to all of our employees, including our executive officers, upon the achievement of certain financial and operational objectives. The incentive compensation plan was designed to motivate all of our employees, including our named executive officers, to conduct our day-to-day operations in a way that helped us to achieve financial and operational goals that were intended to correlate closely with long-term stockholder value. For 2006, the performance metrics of the incentive compensation plan were the following: (1) annual gas production (net); (2) additions to proved reserves; (3) daily gas production at year end (net); (4) adjusted EBITDA; (5) depletion rate; (6) lease operating expenses; (7) general and administrative expenses; and (8) lost time due to injuries. In addition, in 2006, up to 50% of the overall bonus payable to any individual was based on individual performance measures and tied to an individual performance review. These measures allowed the Compensation Committee to be proactive in rewarding the initiative and contributions of each individual employee.

The operational and financial objectives established by the Compensation Committee represented the factors that it deemed most important and the most likely to result in the creation of long-term stockholder value. For each metric, the Compensation Committee established a threshold, target and maximum level of performance for which 50%, 100% and 150%, respectively, of the bonus attributable to each such metric would be paid. The threshold, target and maximum performance levels were determined in connection with a detailed review of our 2006 budget and represented aggressive targets for operational and financial performance by us during 2006. As a result, only certain of the objectives were achieved during 2006, and no bonus was paid with respect to four of the eight metrics, the minimum bonus was paid with respect to three of the metrics, and the maximum bonus was paid with respect to only one of the metrics.

When reviewing the individual performance of Messrs. Schoonmaker and Barnes, the Compensation Committee considered, among other things, their success in implementing an efficient and effective management reporting regime, their ability to interact with regulatory agencies in a positive and productive manner, including through making accurate and timely regulatory filings, and their contributions to our culture of teamwork, open communication, integrity and safety. Messrs. Schoonmaker and Barnes were awarded cash bonuses of $30,000 and $25,000, respectively, under the 2006 incentive compensation plan.

The Compensation Committee has determined to adopt a similar incentive compensation plan for non-executive employees for 2007. Bonuses for executive officers during 2007 will not be tied to the achievement of specific performance targets and will be at the sole discretion of the Compensation Committee.

Equity Incentive Awards. We have established a Stock Incentive Plan pursuant to which equity awards, including stock options and restricted stock, may be granted to employees, directors and consultants of us and our affiliates. The Stock Incentive Plan is designed to motivate all of our employees, including our named executive officers, to assist us in achieving a high level of long-term performance and to tie the compensation of grant recipients to long-term stockholder value. The Compensation Committee administers the Stock Incentive Plan.

Historically, we have generally used stock options to attract new employees and to increase the stake of our existing employees, including our executive officers, in our long-term success. As such, the Compensation Committee periodically evaluates the equity position of our executive officers and determines if increasing that position, in light of events such as our April 2006 private placement, would be appropriate. During 2006, Mr. Schoonmaker and Mr. Barnes were granted options to purchase 70,000 and 77,500 shares of our common stock, respectively. These awards were intended to reward Messrs. Schoonmaker and Barnes for the services they would provide in preparation for our private placement and to counter the dilutive effect our private placement had on their existing equity positions in us. All options granted since our formation vest 20%, 30% and 50% on the first, second and third anniversary of the date of grant, respectively. This vesting schedule is designed to maintain the focus of the option holder on our long-term performance.

The Compensation Committee has not yet made any determinations regarding equity grants to our named executive officers for 2007.

Perquisites and Other Benefits. Messrs. Schoonmaker and Barnes receive no perquisites or benefits that are not generally available on a non-discriminatory basis to all employees. During 2006, for all employees, including Messrs. Schoonmaker and Barnes, we paid health, life and accidental death & disability insurance premiums, made health savings account contributions and matched their contributions to our 401(k) plan (up to 4% of their base salary).

One-time Transaction Bonus. During 2006, Messrs. Schoonmaker and Barnes received one-time cash bonuses of $271,000 and $221,000, respectively, due to the filing, prior to the deadline established

pursuant to a registration rights agreement between us and the purchasers in our April 2006 private placement, of a registration statement on Form S-1 covering the resale of the shares of common stock purchased in our private placement.

Stock Option Practices

Due to the favorable tax consequences to the grant recipient, our stock option grants have historically been intended to qualify as "incentive stock options" under Section 422 of the Internal Revenue Code. We have awarded all stock options to purchase our common stock at or above the fair market value of our common stock on the grant date. Prior to our April 2006 private placement, we determined the fair market value of our common stock by reference to the following factors, among others: (1) the PV-10 value of our estimated net proved reserves, as determined by our independent petroleum engineers in their most recent reserve report, (2) the estimated fair market value of the undeveloped acreage that was contributed to us at inception, (3) the fair market value of the undeveloped acreage in Montana and Wyoming we acquired in March 2005, which was determined through an arms-length bidding and negotiation process, and (4) the liability relating to the redemption of our Series A Redeemable Preferred Stock. Each grant made subsequent to our April 2006 private placement had an exercise price of $11.00, the price paid by purchasers in our private placement. A valuation of our shares of common stock by an independent valuation specialist was not required or requested by our board of directors, which approved each grant.

Following our initial public offering, options will be granted only at regularly scheduled meetings of the Compensation Committee and/or the board of directors, and will have exercise prices equal to the closing market price of shares of our common stock on the date of the meeting. As a privately owned company, there has been no market for our common stock. Accordingly we have had no program, plan or practice pertaining to the timing of stock option grants to executive officers in coordination with the release of material non-public information.

Payments in Connection with a Change of Control or Termination

We have no agreements, plans or arrangements that provide for any payments or accelerated vesting of stock options upon a change of control. Pursuant to Mr. Schoonmaker's current employment agreement, upon termination of his employment by us without cause or by reason of his disability, or by him with good reason, he would be entitled to receive a lump-sum payment equal to the sum of (i) any unpaid salary through the date of termination, any deferred compensation and compensation for unused vacation time, (ii) one year's base salary and (iii) a prorated bonus with respect to the year in which the termination occurred. In addition, any and all stock options, restricted stock awards, restricted stock unit awards and other equity-based or performance awards held by Mr. Schoonmaker immediately prior to his termination would immediately vest and/or become exercisable. Mr. Schoonmaker and his family would also be entitled to a continuation of benefits for one year.

We have agreed to the terms of new employment agreements with Messrs. Schoonmaker and Barnes. Although we have not entered into a definitive agreement with either of Messrs. Schoonmaker or Barnes, we expect the terms of their employment agreements to provide for (i) an initial term of one year, subject to automatic yearly renewals thereafter, (ii) annual base salaries of $225,000 and $185,000, respectively, subject to yearly increases, and (iii) discretionary annual bonuses of up to 1.0 and 0.75 times their base salaries, respectively. In addition, upon termination of their employment by us without cause or by reason of their disability, or by them with good reason, they would be entitled to receive a lump-sum payment equal to the sum of (i) any accrued but unpaid compensation, (ii) 1.0 times their base salaries and (iii) a prorated bonus with respect to the year in which the termination occurred. In addition, any and all stock options, restricted stock awards, restricted stock unit awards and other equity-based or performance awards held by them immediately prior to their termination would immediately vest and/or become exercisable. Upon termination of their employment

by us without cause, or by them with good reason or due to retirement, in each case within 12 months following a change of control, they would be entitled to similar benefits, except that their lump-sum payments would include an amount equal to 1.5 times their base salaries.

As inducement to enter into definitive employment agreements, the board of directors expects to award each of Messrs. Schoonmaker and Barnes 30,000 and 20,000 shares of restricted stock, respectively. Such restricted stock would vest one-third on the third anniversary of the grant, one-third on the fourth anniversary of the grant, and the remaining one-third on the fifth anniversary of the date of grant.

Stock Ownership Requirements

We do not currently have any requirements or guidelines relating to the level of ownership of our common stock by our directors or executive officers or to the hedging of the economic risk of such ownership. As of December 31, 2006, Messrs. Schoonmaker and Barnes each owned 10,000 shares of our common stock and held options to purchase another 232,500 and 202,500 shares of our common stock, respectively. On a fully diluted basis, Messrs. Schoonmaker and Barnes held approximately 1.7% of our issued and outstanding common stock as of December 31, 2006.

Role of the Executive Officers in Determining Executive Compensation

Our executive compensation is determined by our Compensation Committee. Mr. Schoonmaker has no role in determining his own compensation. However, as our Chief Executive Officer and President, he has a role in determining the compensation of Mr. Barnes and our other employees. Mr. Barnes has no role in determining his own compensation or that of Mr. Schoonmaker.

Transitional Compensation Framework

We viewed 2006 as the year in which we would transition from being a private to a public company with a larger and more diverse stockholder base. Accordingly, during 2006 we took steps to begin establishing a more formalized compensation framework appropriate for a public company and responsive to the expectations of an expanding stockholder base. For example, we:

•: adopted a Compensation Committee charter that is compliant with the current rules and guidelines of the NASDAQ and the SEC;
•: adopted an amended and restated Stock Incentive Plan that complies with Internal Revenue Code Section 162(m) and FAS 123R; and
•: began formalizing our stock option grant practices.

In addition, we have retained an outside compensation consultant to assist the board and the Compensation Committee in making their compensation decisions.

Executive Compensation

2006 Summary Compensation Table

The following tables sets forth the aggregate compensation earned by or awarded or paid to our named executive officers during 2006.

Name and Principal Position		Year		Salary			Option Awards(1)			Non-Equity Incentive Plan Compensation			All Other Compensation			Total
Peter G. Schoonmaker Chief Executive Officer, President and Director		2006		$	220,000		$	146,622		$	30,000		$	271,000	(2)	$	667,622
Ronald T. Barnes Chief Financial Officer, Senior Vice President and Secretary		2006		$	180,000		$	161,143		$	25,000		$	221,000	(2)	$	587,143

(1): For a discussion of the assumptions made in the valuation, please see "Stock-Based Compensation" under Note 1 to our audited financial statements.
(2): Messrs. Schoonmaker and Barnes received no perquisites or benefits not made generally available on a non-discriminatory basis to all employees. The amount reported was a one-time bonus paid in connection with the timely filing of a registration statement relating to our April 2006 private placement.

Grants of Plan-Based Awards During 2006

The following table sets forth the plan-based grants made to our named executive officers during 2006.

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1)
								All Other Option Awards: Number of Securities Underlying Options (#)(2)			Grant Date Fair Value of Option Awards
Name									Exercise Price of Option Awards ($/Sh)
Name	Grant Date	Threshold ($)		Target ($)		Maximum ($)			Exercise Price of Option Awards ($/Sh)
Peter G. Schoonmaker	January 1, 2006 June 1, 2006 August 8, 2006	$	27,500	$	55,000	$	82,500	50,000 20,000	$ $	5.20 11.00	$ $	353,168 86,614
Ronald T. Barnes	January 1, 2006 February 16, 2006 June 1, 2006 August 8, 2006	$	22,500	$	45,000	$	67,500	50,000 12,500 15,000	$ $ $	5.20 5.20 11.00	$ $ $	353,168 88,885 64,961

(1): Pursuant to the 2006 incentive compensation plan.
(2): Pursuant to the Stock Incentive Plan.

Employment Agreements

We entered into an employment agreement with Mr. Schoonmaker effective as of June 23, 2003. The initial term of this agreement was two years, subject to automatic renewal so that a term of one year is continuously remaining until the agreement is otherwise terminated. Under this employment agreement, Mr. Schoonmaker was entitled to an initial base salary of $150,000, subject to annual performance-based adjustment, and an annual bonus of up to $100,000 payable in cash or in stock. In addition, pursuant to this employment agreement, in June 2003 and March 2004, Mr. Schoonmaker was

awarded options to purchase 82,500 and 30,000 shares of our common stock, respectively, at an exercise price of $4.00 per share. This employment agreement will terminate automatically upon Mr. Schoonmaker's death and may be terminated by us for cause or by Mr. Schoonmaker for good reason upon written notice. For additional information regarding Mr. Schoonmaker's existing employment agreement, please see "—Potential Payments Upon Termination or Change-in-Control," below.

We have agreed to the terms of new employment agreements with Messrs. Schoonmaker and Barnes. For a discussion of the expected terms of their employment agreements, please see "Management—Compensation Discussion and Analysis—Payments in Connection with a Change of Control or Termination."

Incentive Plan Awards

For a discussion of the performance metrics under our 2006 incentive compensation plan, please see "—Compensation Discussion and Analysis—Elements of Compensation—Performance-Based Bonuses," above. Based on a review of our and their performance during 2006, the Compensation Committee awarded bonuses to Messrs. Schoonmaker and Barnes under the 2006 incentive compensation plan of $30,000 and $25,000, respectively. The Compensation Committee has not yet determined whether to adopt a similar incentive compensation plan for 2007.

The stock options granted to Messrs. Schoonmaker and Barnes were granted pursuant to our Stock Incentive Plan. For a discussion of our Stock Incentive Plan, please see "—Compensation Discussion and Analysis—Elements of Compensation—Equity Incentive Awards," above, and "—Stock Incentive Plan," below. Options vest 20%, 30% and 50% on the first, second and third anniversary of the date of grant, respectively.

During 2006, incentive compensation accounted for approximately 45% and 51% of Messrs. Schoonmaker's and Barnes' total compensation, respectively (excluding the one-time transaction-related bonus).

Outstanding Equity Awards at 2006 Fiscal Year-End

The following table sets forth all outstanding equity awards held by our named executive officers as of December 31, 2006.

Name		Number of Securities Underlying Unexercised Options Exercisable (#)		Number of Securities Underlying Unexercised Options Unexercisable (#)		Option Exercise Price ($)			Option Expiration Date
Peter G. Schoonmaker		82,500 15,000 10,000 — —		— 15,000 40,000 50,000 20,000	(1) (2) (3) (4)	$ $ $ $ $	4.00 4.00 4.80 5.20 11.00		June 30, 2010 March 5, 2011 December 9, 2012 January 1, 2013 June 1, 2013
Ronald T. Barnes		25,000 25,000 7,500 2,500 — — —		— 25,000 30,000 10,000 50,000 12,500 15,000	(5) (6) (7) (3) (8) (4)	$ $ $ $ $ $ $	4.00 4.80 4.80 4.80 5.20 5.20 11.00		January 3, 2011 June 23, 2011 January 3, 2012 December 9, 2012 January 1, 2013 February 16, 2013 June 1, 2013

(1): Options were granted March 5, 2004. Remaining options vest on March 5, 2007.

(2): Options were granted December 9, 2005. 15,000 and 25,000 of the remaining options vest on December 9, 2007 and 2008, respectively.
(3): Options were granted January 1, 2006. 10,000 options vested on January 1, 2007. 15,000 and 25,000 of the remaining options vest on January 1, 2008 and 2009, respectively.
(4): Options were granted June 1, 2006 and vest 20%, 30% and 50% on the first, second and third anniversary of the date of grant, respectively.
(5): Options were granted June 23, 2004. The remaining options vest on June 23, 2007.
(6): Options were granted January 3, 2005. 11,250 options vested on January 3, 2007. The remaining options vest on January 3, 2008.
(7): Options were granted on December 9, 2005. 3,750 and 6,250 of the remaining options vest on December 9, 2007 and 2008, respectively.
(8): Options were granted on February 16, 2006 and vest 20%, 30% and 50% on the first, second and third anniversary of the date of grant, respectively.

Potential Payments Upon Termination or Change-in-Control

The following table sets forth the potential termination payments due to our named executive officers, assuming the triggering event occurred on December 31, 2006.

Name	Benefit	Termination without Cause, by Reason of Disability or for Good Reason(1)			Termination for Cause or without Good Reason		Termination Due to Death
Peter G. Schoonmaker	Severance	$	213,291	(2)		—	$	170,000	(3)
	Prorated bonus(4)	$	30,000				$	30,000
	Insurance premiums(5)	$	12,250			—	$	12,250
	Unused vacation(6)	$	4,231		$	4,231	$	4,231
	Health savings account contribution(5)	$	3,000			—	$	3,000
	Acceleration of stock options(7)	$	643,000			—		—

(1): Prior to or after a change in control.
(2): Equal to Mr. Schoonmaker's 2006 base salary, discounted at 6%.
(3): Equal to Mr. Schoonmaker's 2006 base salary, less $50,000 payable under an insurance policy, the premiums of which are paid by us.
(4): Estimated based on Mr. Schoonmaker's 2006 bonus under our 2006 incentive compensation plan.
(5): Estimated based on the amount paid during 2006.
(6): Estimated based on the number of unused vacation days during 2006.
(7): Represents the "in-the-money" value of all options that would accelerate, assuming a price per share of $11.00.

Pursuant to Mr. Schoonmaker's existing employment agreement, upon termination of his employment by us without cause or by reason of his disability, or by him with good reason, he would be entitled to receive a lump-sum payment equal to the sum of (i) any unpaid salary through the date of termination, any deferred compensation and compensation for unused vacation time, (ii) one year's base salary (discounted at 6%) and (iii) a prorated bonus with respect to the year in which the

termination occurred. In addition, any and all stock options, restricted stock awards, restricted stock unit awards and other equity-based or performance awards held by Mr. Schoonmaker immediately prior to his termination would immediately vest and/or become exercisable. Mr. Schoonmaker and his family would also be entitled to a continuation of benefits for one year. Upon termination of Mr. Schoonmaker's employment by us for cause, or by him without good reason, Mr. Schoonmaker would be entitled to only his unpaid salary through the date of termination, any deferred compensation and compensation for unused vacation time.

For purposes of Mr. Schoonmaker's existing employment agreement, "cause" includes, among other things, (i) his being convicted of a felony, (ii) a breach of his fiduciary duties owed to us, (iii) his willful and gross neglect of, or continued failure to perform, his duties and (iv) his commission of any act of moral turpitude. "Good reason" includes, among other things, (i) the assignment to Mr. Schoonmaker of duties inconsistent with, or a material diminution of, his position with us and (ii) our failure to comply with the terms of his employment agreement.

In addition, pursuant to Mr. Schoonmaker's existing employment agreement, upon his death, his estate would be entitled to receive a lump-sum payment equal to the sum of (i) any unpaid salary through the date of termination, any deferred compensation and compensation for unused vacation time, (ii) one year's base salary (less the amount payable under any insurance policy, the premiums of which are paid by us) and (iii) a prorated bonus with respect to the year in which the termination occurred. Mr. Schoonmaker's family would also be entitled to a continuation of benefits for one year.

Under his existing employment agreement, Mr. Schoonmaker is subject to covenants prohibiting him from (i) disclosing confidential information for a period of five years following the termination of his employment, (ii) competing with us for a period of one year following the termination of his employment or (iii) soliciting our employees for a period of two years following the termination of his employment.

2006 Director Compensation

Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)(1)		All Other Compensation ($)	Total ($)
Steven A. Webster(2)	$	25,250	$	12,054	—	$	37,304
Robert L. Cabes, Jr.(2)	$	32,750	$	12,054	—	$	44,804
Jeffrey P. Gunst(2)	$	20,500	$	12,054	—	$	32,554
Sylvester P. Johnson, IV(3)	$	24,000	$	12,054	—	$	36,054
F. Gardner Parker	$	40,250	$	12,054	—	$	52,304
Susan C. Schnabel(4)	$	22,500	$	12,054	—	$	34,554
Keith G. Larsen(5)	$	14,500	$	12,054	—	$	26,554
Mark J. Larsen(5)	$	15,000	$	12,054	—	$	27,054
Peter G. Schoonmaker(6)		—		—	—		—

(1): In connection with the closing of our April 2006 private placement, each non-employee director was granted 4,545 shares of restricted stock effective as of April 11, 2006. The shares of restricted stock vest 33%, 33% and 34% on the first, second and third anniversary of the date of grant, respectively. None of such shares of restricted stock have vested and all such shares of restricted stock were outstanding as of December 31, 2006. The grant date fair value of each such grant was $50,000. Messrs. Larsen and Larsen forfeited all their shares of restricted stock upon their

resignation, described in note 5 below. For a discussion of the assumptions made in the valuation, please see "Stock-Based Compensation" under Note 1 to our audited financial statements.

(2): At the request of the director, payment of cash compensation was deferred until 2007.
(3): All cash compensation earned by Mr. Johnson for his service as a director goes directly to Carrizo.
(4): Pursuant to an agreement with Credit Suisse First Boston Private Equity, Inc., all cash compensation earned by Ms. Schnabel for her service as a director is paid over to the limited partners of DLJ Merchant Banking Partners III, L.P. and its affiliated funds.
(5): Messrs. Larsen and Larsen were designees of one of our founding investors, U.S. Energy, and resigned effective September 22, 2006 in connection with the purchase by DLJ Merchant Banking of all of the shares of common stock held by U.S. Energy.
(6): Mr. Schoonmaker is our President and Chief Executive Officer and receives no compensation for serving as a director.

Historically, our directors did not receive any compensation for serving as a director, although we did reimburse directors for expenses incurred in connection with attendance at meetings of the board of directors. Following our April 2006 private placement, each non-employee member of our board of directors began receiving compensation for service on our board of directors and committees, other than the hedging committee, thereof. Non-employee directors receive an annual fee of $20,000. In addition, the chairman of each of the following committees receives the following annual fees: audit committee—$15,000, compensation committee—$5,000 and nominating and corporate governance committee—$5,000. Non-employee directors receive a fee of $1,500 for each board or committee meeting attended in person and a fee of $1,000 for attendance at a board or committee meeting held telephonically. Effective as of the initial closing of the private placement, each non-employee director was granted shares of restricted stock in the aggregate amount of $50,000 (based on the price of $11.00 per share, as established in our private placement, and rounded to the nearest whole share), vesting 33%, 33% and 34% over three years beginning on the first anniversary of the date of grant. Directors will receive the same cash compensation and received a grant of 2,000 shares of restricted stock effective February 12, 2007 as compensation for their service in 2007. The shares of restricted stock will vest on the first anniversary of the date of grant.

Employee directors do not receive compensation for service on our board or committees. Pursuant to the amended and restated securityholders agreement, all directors are reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of the board or committees and for other reasonable expenses incurred in connection with service on the board and any committees. Each director will be fully indemnified by us for actions associated with being a member of our board to the extent permitted under Delaware law as provided in our second amended and restated certificate of incorporation, our amended and restated bylaws and the indemnification agreements by and between us and each of our directors.

Equity Compensation Plan Information

The following table sets forth information regarding shares of our common stock authorized for issuance under our equity compensation plans as of December 31, 2006:

Plan Category		Number of Securities to be Issued Upon Exercise of Outstanding Options		Weighted-Average Exercise Price of Outstanding Options			Number of Shares of Restricted Stock Issued		Number of Securities Remaining Available for Future Issuance
Equity compensation plans approved by stockholders		1,035,000		$	6.68		27,270		1,687,730

From January 1, 2007 through March 31, 2007, we cancelled options to purchase 146,000 shares of common stock in connection with the termination of employees. From January 1, 2007 through March 31, 2007, the board of directors has granted options to purchase an additional 75,000 shares of common stock and 47,000 shares of restricted common stock under our Stock Incentive Plan, leaving 1,711,730 shares of common stock available for future issuance under our Stock Incentive Plan as of March 31, 2007.

2003 Stock Option Plan

Effective February 16, 2006, we merged our 2003 Stock Option Plan with and into our Stock Incentive Plan so that our Stock Incentive Plan shall be our only incentive compensation plan going forward. The initial grant to Mr. Schoonmaker of an option to purchase up to 82,500 shares of common stock was made under our 2003 Stock Option Plan. This option was assumed and continued under our Stock Incentive Plan, but will remain subject to the terms of the applicable option agreement and the 2003 Stock Option Plan as in effect immediately prior to the merger of the plans.

Stock Incentive Plan

Effective February 16, 2006, we amended and restated our Stock Incentive Plan to increase the number of shares with respect to which awards may be granted from 675,000 to 2,750,000 shares. Our Stock Incentive Plan permits the granting of stock options, restricted common stock, restricted common stock units, performance shares, performance share units, share purchases, share awards or other awards based on the value of common stock to any employees, directors and consultants of us or of our affiliates. No employee shall be granted, during any calendar year, stock options to purchase more than 625,000 shares of common stock. In addition, the number of shares of common stock subject to any awards other than stock options granted to any employee during any calendar year shall not exceed 625,000 shares. The plan is administered by a committee comprised of our board of directors, unless the board has delegated administration of the plan to a committee of one or more members of the board. Following an initial public offering, with respect to any grant to any individual covered by Section 162(m) of the Code which is intended to be performance-based compensation, the committee shall consist solely of two or more non-employee directors. The committee will select the participants who will receive awards, determine the type, size and terms of the awards to be granted and interpret and administer the plan.

The stock options granted pursuant to the plan may be either incentive options qualifying for beneficial tax treatment for the recipient as "incentive stock options" under Section 422 of the Code or nonqualified options. Incentive stock options may only be granted to employees and the exercise price for incentive stock options will not be less than 100% of the fair market value of the common stock on the date of grant. No person may be issued incentive stock options that first become exercisable in any calendar year with respect to shares having an aggregate fair market value, at the date of grant, in excess of $100,000. No incentive stock option may be granted to a person if at the time such option is granted the person owns stock possessing more than 10% of the total combined voting power of all classes of our stock or any of our subsidiaries as defined in Section 424 of the Code, unless at the time incentive stock options are granted the purchase price for the option shares is at least 110% of the fair market value of the option shares on the date of grant and the incentive stock options are not exercisable five years after the date of grant.

The board may amend, suspend or terminate the plan, provided, however, that no amendment of the plan may, without the consent of the participant, adversely affect the rights of a participant under an award theretofore granted and no amendment shall be made without stockholder approval to the extent stockholder approval is necessary to satisfy any applicable law or securities exchange listing requirements. Unless sooner terminated, the plan shall terminate on the seventh anniversary of the effective date of the plan.

As of March 31, 2007, there were issued and outstanding options to purchase 964,000 shares of common stock and 74,270 shares of restricted stock under our stock incentive plan.

Tax Treatment of Stock Incentive Plan

Nonqualified Stock Options. An optionee will not recognize any taxable income upon the grant of a nonqualified stock option. We will not be entitled to a federal income tax deduction with respect to the grant of a nonqualified stock option. Upon exercise of a nonqualified stock option, the excess of the fair market value of the common stock transferred to the optionee over the option exercise price will be taxable as compensation income to the optionee and will be subject to applicable withholding taxes. Such fair market value generally will be determined on the date the shares of common stock are transferred pursuant to the exercise. We generally will be entitled to a federal income tax deduction at such time in the amount of such compensation income. The optionee's federal income tax basis for the common stock received pursuant to the exercise of a non-qualified stock option will equal the sum of the compensation income recognized and the exercise price. In the event of a sale of common stock received upon the exercise of a nonqualified stock option, any appreciation or depreciation after the exercise date generally will be taxed as capital gain or loss.

Incentive Stock Options. An optionee will not recognize any taxable income at the time of grant or timely exercise of an incentive stock option (but in some circumstances may be subject to an alternative minimum tax as a result of exercise), and we will not be entitled to a federal income tax deduction with respect to such grant or exercise. A sale or exchange by an optionee of shares acquired upon the exercise of an incentive stock option more than one year after the transfer of the shares to such optionee and more than two years after the date of grant of the incentive stock option will result in the difference between the amount realized and the exercise price, if any, being treated as long-term capital gain (or loss) to the optionee. If such sale or exchange takes place within two years after the date of grant of the incentive stock option or within one year from the date of transfer of the shares to the optionee, such sale or exchange generally will constitute a "disqualifying disposition" of such shares that will have the following result: any excess of (a) the lesser of (1) the fair market value of the shares at the time of exercise of the incentive stock option and (2) the amount realized on such disqualifying disposition of the shares over (b) the option exercise price of such shares, will be ordinary income to the optionee, and we generally will be entitled to a federal income tax deduction in the amount of such income. The balance, if any, of the optionee's gain upon a disqualifying disposition will qualify as capital gain and will not result in any deduction by us.

Restricted Common Stock. A grantee generally will not recognize taxable income upon the grant of restricted stock, and the recognition of any income will be postponed until such shares are no longer subject to restrictions on transfer or the risk of forfeiture. When either the transfer restrictions or the risk of forfeiture lapses, the grantee will recognize ordinary income equal to the fair market value of the restricted stock at the time of such lapse and, subject to satisfying applicable income reporting requirements and any deduction limitation under Section 162(m) of the Code, we will be entitled to a federal income tax deduction in the same amount and at the same time as the grantee recognized ordinary income. A grantee may elect to be taxed at the time of the grant of restricted stock and, if this election is made, the grantee will recognize ordinary income equal to the excess of the fair market value of the restricted stock at the time of grant (determined without regard to any of the restrictions thereon) over the amount paid, if any, by the grantee for such shares. We generally will be entitled to a federal income tax deduction in the same amount and at the same time as the grantee recognizes ordinary income.

Performance Shares, Performance Share Units, Restricted Stock Units, Share Awards and Other Share-Based Awards. Generally, a grantee will not recognize any taxable income and we will not be entitled to a deduction upon the award of performance shares, performance share units, restricted stock units, share awards and other share-based awards. Upon vesting, the participant would include in ordinary

income the value of any shares received and an amount equal to any cash received. Subject to satisfying applicable income reporting requirements and any deduction limitation under Section 162(m) of the Code, we will be entitled to a federal income tax deduction equal to the amount of ordinary income recognized by the grantee.

Share Purchases. In general, a grantee who is given the right to purchase stock at a discount to fair market value does not recognize taxable income and the corporation is not entitled to a deduction until such right is exercised. If and when a participant purchases stock at less than its fair market value on the date of purchase, the participant recognizes income and the corporation receives a deduction for the amount of the difference.

Deferred Compensation and Parachute Taxes. Section 409A of the Code provides for an additional 20% tax, among other things, on awards that, if subject to Section 409A, do not comply with the requirements of this section. The plan shall be effected in order to comply with Section 409A. In addition, if, upon a change of control of us, the vesting or payment of awards to certain "disqualified individuals" exceeds certain amounts, that individual will be subject to a 20% excise tax on such payments and those amounts will not be deductible by us.

401(k) Plan

We maintain a 401(k) plan, also known as our Profit Sharing Plan. The plan permits substantially all employees over age 18 to make voluntary, pre-tax contributions to the plan, subject to applicable tax limitations. We will make matching contributions equal to 100% of an employee's contributions that do not exceed 3% of annual compensation, plus 50% of an employee's contributions that are in excess of 3% of annual compensation but do not exceed 5% of annual compensation, subject to applicable tax limitations. Eligible employees who elect to participate in the plan are 100% vested in the matching contributions. The plan is intended to be a "safe harbor" tax-qualified under Section 401(a) of the Internal Revenue Code so that contributions to the plan, and income earned on any plan contributions, are not taxable to employees until withdrawn from the plan, and so that contributions to the plan will be deductible when made.

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Transactions with Officers and Directors

On June 23, 2003, pursuant to his employment agreement, Mr. Gary W. Uhland, our former President, was awarded an option to purchase up to 82,500 shares of common stock at an exercise price of $4.00 per share. In March 2004, Mr. Uhland was awarded an additional option to purchase up to 30,000 shares of common stock at an exercise price of $4.00 per share. Effective July 31, 2005, Mr. Uhland resigned as our President. In connection with his resignation and pursuant to his employment agreement and release, Mr. Uhland exercised options to purchase 50,000 shares of our common stock at an exercise price of $3.32 per share on November 30, 2005. Mr. Uhland's remaining options to purchase 62,500 shares were terminated. Following the final closing of our private placement, we used a portion of the proceeds we received in the private placement to repurchase 6,185 shares of common stock from Mr. Uhland at $10.23 per share, the price per share we received in the private placement net of the initial purchaser's discount and placement fee.

Messrs. Schoonmaker, Barnes and Webster purchased 10,000, 10,000 and 9,091 shares, respectively, in the private placement, at the same price per share and on the same terms as other purchasers in the private placement (including registration rights with respect to such shares).

Transactions With Our Founders

Transactions with DLJ Merchant Banking. At our formation in June 2003, DLJ Merchant Banking contributed approximately $17.6 million cash in exchange for 1,250,000 shares of our common stock, representing 25% of the common stock initially issued, Series A warrants for the purchase of 3,250,000 additional shares of common stock at an exercise price of $4.00 per share, and 130,000 shares of our Series A Redeemable Preferred Stock. Through three subsequent financings, totaling approximately $26.5 million, DLJ Merchant Banking purchased 270,000 shares of our Series A Redeemable Preferred Stock, Series A warrants to purchase an aggregate of 6,750,000 shares of common stock at an exercise price of $4.00 per share and Series B warrants to purchase an aggregate of 30,000 shares (pre-split; 750,000 shares post-split) of common stock at an exercise price of $0.01 per share. In November 2005, DLJ Merchant Banking exercised its Series B warrants to purchase 30,000 shares (pre-split; 750,000 shares post-split) of common stock at an exercise price of $0.01 per share. DLJ Merchant Banking is part of DLJ Merchant Banking Partners, which is a private equity investor with a 20-year history of investing in leveraged buyouts and related transactions across a broad range of industries. DLJ Merchant Banking Partners is part of the alternative investments platform within Credit Suisse's asset management business.

In April 2006, we completed a private offering of 12,835,230 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors. Prior to our private placement, DLJ Merchant Banking beneficially owned 100% of our Series A Redeemable Preferred Stock and approximately 64.2% of our outstanding common stock on a diluted basis giving effect to the exchange of all outstanding warrants and the cashless exercise of all outstanding options held by non-management stockholders. Immediately prior to the initial closing of our private placement, DLJ Merchant Banking exchanged all of its warrants for 6,894,380 shares of our common stock in a tax-free reorganization based on the private placement price of $11.00 per share. Following the initial closing of our private placement, we redeemed all of the outstanding shares of Series A Redeemable Preferred Stock with a portion of the proceeds we received in the private placement. Following the final closing of our private placement, we used a portion of the proceeds we received in the private placement to repurchase an aggregate of 1,587,598 shares of common stock from DLJ Merchant Banking at $10.23 per share, the net price per share we received in the private placement. On September 22, 2006, DLJ Merchant Banking purchased all of the shares of our common stock held by U.S. Energy and its affiliates in a private transaction. As of December 31, 2006, DLJ Merchant Banking beneficially owned

approximately 38.9% of our outstanding common stock. After this offering, DLJ Merchant Banking will beneficially own approximately 32.5% of our outstanding common stock if the over-allotment is exercised in full. Please see "Security Ownership of Certain Beneficial Owners and Management" for more information regarding DLJ Merchant Banking's ownership of us.

Transactions with Other Initial Stockholders. At our formation in June 2003, CCBM, Inc., a subsidiary of Carrizo, and Rocky Mountain Gas, Inc., a former subsidiary of U.S. Energy, contributed interests in approximately 81,000 gross (40,000 net) acres, including proved producing properties and undeveloped leaseholds, valued at $15.0 million. In exchange for such contribution, we issued 1,875,000 shares of our common stock and options to purchase an additional 1,250,000 shares of our common stock to each of CCBM and Rocky Mountain Gas. The shares of our common stock and options held by Rocky Mountain Gas were transferred to its affiliates, U.S. Energy and Crested Corp., in May 2005. The options, half of which were designated as Tranche A options and half of which were designated as Tranche B options, were exercisable for as long as CCBM or U.S. Energy, as the case may be, or their respective permitted transferees were owners of record of shares of our common stock. The Tranche A options had an exercise price of $4.00 per share increased by 10% per annum, compounded quarterly, beginning on the date of issuance, or a $5.14 per share weighted average price as of April 11, 2006 (the initial closing date of our private placement), and the Tranche B options had an exercise price of $4.00 per share increased by 20% per annum, compounded quarterly, beginning on the date of issuance, or a $6.58 per share weighted average price as of April 11, 2006 (the initial closing date of our private placement).

Prior to our private placement, each of Carrizo and U.S. Energy beneficially owned approximately 17.7% of our outstanding common stock on a diluted basis giving effect to the exchange of all outstanding warrants and cashless exercise of all outstanding options held by non-management stockholders. Immediately prior to the initial closing of our private placement, each of Carrizo and U.S. Energy entered into a cashless exercise of all of its Tranche A and Tranche B options to purchase 584,102 shares of common stock based on the private placement price of $11.00 per share. On September 22, 2006, DLJ Merchant Banking purchased all of the shares of our common stock held by U.S. Energy and its affiliates in a private transaction. As of December 31, 2006, each of Carrizo and U.S. Energy beneficially owned approximately 9.8% and 0%, respectively, of our outstanding common stock. After this offering, Carrizo will beneficially own approximately 8.2% of our outstanding common stock if the over-allotment is exercised in full. Please see "Security Ownership of Certain Beneficial Owners and Management" for more information regarding Carrizo's ownership of us.

Amended and Restated Securityholders Agreement with DLJ Merchant Banking and Other Significant Stockholders. Pursuant to the securityholders agreement among us, DLJ Merchant Banking, CCBM, U.S. Energy, Crested, Carrizo and Mr. Schoonmaker, DLJ Merchant Banking and affiliates of Carrizo and U.S. Energy had the right, prior to our private placement, to designate members of the board of directors. Prior to the private placement, DLJ Merchant Banking elected four directors, U.S. Energy elected two directors and Carrizo elected two directors to the board. In connection with the sale of all of U.S. Energy's common stock to DLJ Merchant Banking, the U.S. Energy designees resigned from our board of directors effective as of September 25, 2006. The board members designated by DLJ Merchant Banking and Carrizo will continue to serve on our board of directors until the expiration of their respective terms. However, the right of our significant stockholders to designate new directors pursuant to the securityholders agreement terminated upon consummation of the private placement.

Subject to certain restrictions, the securityholders agreement also provides DLJ Merchant Banking and CCBM certain rights to require us to register shares of our common stock. DLJ Merchant Banking may require us to register shares of common stock on up to three occasions. At any time after this registration statement becomes effective CCBM has the right on one occasion to require us to register shares of common stock, provided that CCBM holds of record not less than 10% of our common stock on a fully diluted basis. We are not obligated to effect a demand registration in any case unless the

proposed offering proceeds for an offering equal or exceed $25 million. In addition, these stockholders also have piggyback registration rights, which they have elected to exercise in connection with this registration statement. Please see "Registration Rights."

We have agreed to pay most offering fees and expenses associated with the registration and offering of these shares, other than underwriting fees, discounts or commissions. We have also agreed to indemnify these stockholders and their officers, directors, partners, legal counsel and other listed representatives against certain losses, claims, damages or liabilities in connection with the registered offering of their shares.

Relationships with Certain Directors

Steven A. Webster, the Chairman of our board of directors, is the Co-Managing Partner of Avista Capital Holdings, L.P., a private equity firm that makes investments in the energy sector, and is also Chairman of Carrizo. Robert L. Cabes, Jr. and Jeffrey P. Gunst, two of our directors, also serve as Principal and Vice President of Avista, respectively. In addition, Sylvester P. Johnson, IV serves as President, Chief Executive Officer and a director of Carrizo. F. Gardner Parker is a director of Carrizo and Susan Schnabel is a Managing Director of DLJ Merchant Banking. These relationships may create a conflict of interest regarding corporate opportunities and other matters. The resolution of any conflicts of interest may not always be in our stockholders' best interest. We expect to address transactions involving potential conflicts of interest by having such transactions approved by the disinterested members of our board of directors.

Transactions between Our Initial Stockholders

On September 22, 2006, DLJ Merchant Banking purchased all of the shares of our common stock held by U.S. Energy and its affiliates in a private transaction for an aggregate cash purchase price of $13.8 million.

Approval of Related Party Transactions

As a privately held company, we have not adopted policies or procedures for the review, approval or ratification of related party transactions. Pursuant to its charter, our audit committee will establish procedures for the approval of all related party transactions. Our certificate of incorporation permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested. Please see "Description of Capital Stock — Related Party Transactions and Corporate Opportunities."

SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information as of March 31, 2007 concerning the shares of our capital stock beneficially owned by:

•: each person known by us to be the beneficial owner of 5% or more of our outstanding common stock;
•: each of the directors;
•: each person named in the Summary Compensation Table; and
•: all directors, nominees and executive officers as a group.

Except as indicated by footnote, and subject to applicable community property laws, the persons named in the table below have sole voting and investment power with respect to all shares of capital stock shown as beneficially owned by them, and their address is c/o Pinnacle Gas Resources, Inc., 1 E. Alger, Sheridan, Wyoming 82801.

	Shares Beneficially Owned Prior to this Offering				Shares Beneficially Owned After this Offering if Over-Allotment Exercised in Full
				Maximum Number of Shares Offered in the Over-Allotment
Name of Beneficial Owner
Name of Beneficial Owner	Number	Percent			Number	Percent
DLJ Merchant Banking Partners III, L.P. and affiliated funds(2)	9,765,884	38.9	%	361,892	9,403,992	32.5
CCBM, Inc.(3)	2,465,647	9.8	%	91,121	2,367,981	8.2
Peter G. Schoonmaker(4)	142,500	*		—
Ronald T. Barnes(5)	93,750	*		—
Gary W. Uhland(6)	43,815	*		1,626	42,189	*
Steven A. Webster(7)†	15,636	*		—
Robert L. Cabes, Jr.†	6,545	*		—
Jeffrey P. Gunst†	6,545	*		—
Sylvester P. Johnson, IV†(8)	6,545	*		—
F. Gardner Parker†	6,545	*		—
Susan C. Schnabel†	6,545	*		—
All Directors and Executive Officers as a Group (8 Persons)	284,611	1.1	%

*: Less than 1%.
(1): The number of shares beneficially owned is determined under rules promulgated by the SEC and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any shares as to which the individual has sole or shared voting power or investment power and also any shares that the individual has the right to acquire within 60 days through the exercise of any stock option or other right. The inclusion herein of such shares, however, does not constitute an admission that the named stockholder is a direct or indirect beneficial owner of such shares. Unless otherwise indicated, each person or entity named in the table has sole voting power and investment power (or shares such power with his or her spouse) with respect to all shares of capital stock listed as owned by such person or entity.
(2): Includes shares of common stock held by the DLJ Merchant Banking funds, including: (i) DLJ Merchant Banking Partners III, L.P.; (ii) DLJ Merchant Banking III, Inc., as Advisory General Partner on behalf of DLJ Offshore Partners III, C.V.; (iii) DLJ Merchant Banking III, Inc., as Advisory General Partner on behalf of DLJ Offshore Partners III-1, C.V. and as attorney-in-fact for DLJ Merchant Banking III, L.P., as Associate General Partner of DLJ Offshore Partners III-1, C.V.; (iv) DLJ Merchant Banking III, Inc., as Advisory General Partner on behalf of DLJ Offshore Partners III-2, C.V. and as attorney-in-fact for DLJ Merchant

Banking III, L.P., as Associate General Partner of DLJ Offshore Partners III-2, C.V.; (v) DLJ MB Partners III GmbH & Co. KG; (vi) Millennium Partners II, L.P.; and (vii) MBP III Plan Investors, L.P.

: Credit Suisse, a Swiss bank (the "Bank"), owns the majority of the voting stock of Credit Suisse Holdings (USA) Inc., a Delaware corporation, which in turn owns all of the voting stock of Credit Suisse (USA) Inc., a Delaware corporation ("CS-USA"). The entities discussed in the above paragraph are merchant banking funds managed by indirect subsidiaries of CS-USA and form part of Credit Suisse's asset management business. The ultimate parent company of the Bank is Credit Suisse Group ("CSG"). CSG disclaims beneficial ownership of the reported common stock that is beneficially owned by its direct and indirect subsidiaries.
: All of the DLJ Merchant Banking entities can be contacted at Eleven Madison Avenue, New York, New York 10010-3629 except for the three "Offshore Partners" entities, which can be contacted at John B. Gosiraweg, 14, Willemstad, Curacao, Netherlands Antilles.
(3): The address of each of Carrizo and CCBM, Inc. is 1000 Louisiana Street, Suite 1500, Houston, Texas 77002. CCBM, Inc. is a wholly owned subsidiary of Carrizo. Includes 6,545 shares of restricted common stock granted to Mr. Johnson that he is obligated to transfer to CCBM, Inc. upon vesting.
(4): Includes 82,500 shares issuable within 60 days upon exercise of options granted under our 2003 Stock Option Plan. Also includes 50,000 shares issuable within 60 days upon exercise of options granted under our Stock Incentive Plan but does not include 100,000 shares underlying options that are not exercisable within 60 days granted under our Stock Incentive Plan. The number of shares also includes 10,000 shares that were purchased in our private placement.
(5): Includes 83,750 shares of common stock issuable within 60 days upon exercise of options granted under our Stock Incentive Plan but does not include 118,750 shares of common stock underlying options that are not exercisable within 60 days granted under our Stock Incentive Plan. The number of shares also includes 10,000 shares that were purchased in our private placement.
(6): The address of Mr. Uhland is 1000 Louisiana Street, Suite 1500, Houston, Texas 77002. Mr. Uhland resigned as President of Pinnacle effective July 31, 2005. In connection with his resignation, Mr. Uhland exercised options to purchase 50,000 shares of our common stock at an exercise price of $3.32 per share. Following the final closing of the private placement, we used a portion of the net proceeds to repurchase 6,185 shares of common stock from Mr. Uhland.
(7): Includes 9,091 shares that were purchased in our private placement.
(8): Mr. Johnson is obligated to transfer to CCBM, Inc. upon vesting any shares of restricted common stock granted to him as a non-employee director.
†: Includes 4,545 shares of restricted common stock granted to each of our non-employee directors under our stock incentive plan, effective as of April 11, 2006. These shares of restricted common stock vest 33%, 33%, and 34% over three years, beginning on the first anniversary of the date of grants. Also includes 2,000 shares of restricted common stock granted to each of our non-employee directors under our stock incentive plan, effective as of February 12, 2007. These shares of restricted common stock vest on the first anniversary of the effective date of the grants.

SELLING STOCKHOLDERS

The following table and related footnotes set forth certain information regarding the selling stockholders. The number of shares in the column "Number of Shares Offered" represents all of the shares that each selling stockholder may offer under this prospectus if the underwriters' over-allotment option is exercised in full. The selling stockholders will each sell a pro rata number of the total shares that may be sold pursuant to the underwriters' over-allotment option. To our knowledge, each of the selling stockholders has sole voting and investment power as to the shares shown, except as disclosed in this prospectus or to the extent this power may be shared with a spouse. Beneficial ownership as shown in the table below has been determined in accordance with the applicable rules and regulations promulgated under the Exchange Act. Except as noted in this prospectus, none of the selling stockholders is a director, officer or employee of ours or an affiliate of such person.

We and substantially all of the selling stockholders are parties to agreements pursuant to which we have granted such stockholders rights to register their shares of common stock. Please read "Registration Rights."

Except as noted in this prospectus, to our knowledge, none of the selling stockholders has, or has had within the past three years, any position, office or other material relationship with us or any of our predecessors or affiliates, other than their ownership of shares described below.

					Beneficial Ownership After this Offering if Over-Allotment Exercised in Full
	Beneficial Ownership Prior to this Offering
	Beneficial Ownership Prior to this Offering			Maximum Number of Shares Offered in the Over- Allotment
Selling Stockholders	Number of Shares	Percentage		Maximum Number of Shares Offered in the Over- Allotment	Number of Shares	Percentage
Alexandra Global Master Fund Ltd.(1)	200,000	*		7,414	192,586	*
Bavely, Donald & Kathleen	6,818	*		253	6,565	*
Brady Retirement Fund, L.P.(2)	25,000	*		928	24,072	*
CCBM, Inc.(3)	2,459,102	9.8	%	91,121	2,367,981	8.2	%
CRS Fund, Ltd.(4)	30,000	*		1,114	28,886	*
Cyrus Opportunities Master Fund II, Ltd.(4)	470,000	1.9	%	17,415	452,585	1.6	%
Deephaven Distressed Opportunities Trading Ltd.(5)‡	240,909	*		8,927	231,982	*
Deephaven Event Trading Ltd.(5)‡	609,091	2.4	%	22,573	586,518	2.0	%
DLJ Merchant Banking Partners III, L.P. and affiliated funds(6)‡	9,765,884	38.9	%	361,892	9,403,992	32.5	%
Geary Partners, L.P.(2)	76,000	*		2,818	73,182	*
Hayman Capital Master Fund, LP(7)	90,000	*		3,336	86,664	*
MA Deep Event Ltd.(5)‡	59,091	*		2,188	56,903	*
Modern Capital Fund LLC(8)	27,273	*		1,013	26,260	*
Morgan Stanley & Co. Incorporated†	727,273	2.9	%	26,949	700,324	2.4	%
Presidio Partners, L.P.(2)	99,000	*		3,668	95,332	*
Spring Street Partners LP(9)	50,000	*		1,851	48,149	*
The Catfish Fund, LP(10)	200,000	*		7,414	192,586	*
Uhland, Gary W.(11)	43,815	*		1,626	42,189	*

*: Percentage of common stock beneficially owned does not exceed one percent (1%).
†: Broker-dealer.
‡: Affiliate of a broker-dealer.

(1): Alexandra Investment Management, LLC, a Delaware limited liability company ("Alexandra"), serves as investment adviser to this selling stockholder. By reason of such relationship, Alexandra may be deemed to share voting or dispositive power over the shares of common stock stated as beneficially owned by this selling stockholder. Alexandra disclaims beneficial ownership of such shares of common stock. Mikhail A. Filimonov ("Filimonov") is a managing member of Alexandra. By reason of such relationship, Filimonov may be deemed to share voting or dispositive power over the shares of common stock stated as beneficially owned by this selling stockholder. Filimonov disclaims beneficial ownership of such shares of common stock.
(2): William Brady is the general partner of this selling stockholder and has voting and dispositive power over the shares held by this selling stockholder.
(3): CCBM, Inc. was one of our initial stockholders. Please see "Security Ownership of Certain Beneficial Owners and Management" for further information regarding its ownership in us.
(4): Cyrus Capital Partners GP, LLC is the general partner of, and Cyrus Capital Partners LP is the investment manager for, this selling stockholder. Stephen C. Friedheim is the Managing Partner of Cyrus Capital Partners LP and is deemed to have voting and dispositive power over the shares held by this selling stockholder.
(5): Deephaven Capital Management LLC ("Deephaven"), a registered investment advisor, is the investment manager for this selling stockholder. As investment manager, Deephaven has indirect ownership of, and full voting and dispositive power over, the shares held by this selling stockholder. Deephaven disclaims beneficial ownership of such shares except to the extent of its pecuniary interest in such shares.
(6): DLJ Merchant Banking Partners III, L.P. and its affiliated funds were some of our initial stockholders. Please see "Security Ownership of Certain Beneficial Owners and Management" for further information regarding their ownership in us.
(7): Hayman Advisors LP is the general partner of this selling stockholder. Hayman Investments LLC controls Hayman Advisors LP and J. Kyle Bass is the owner and Managing Member of Hayman Investments LLC. By virtue of his position with Hayman Investments LLC, Mr. Bass is deemed to have voting and dispositive power over the shares held by this selling stockholder.
(8): Dennis J. Mykytyn has voting and dispositive power over the shares held by this selling stockholder.
(9): Michael McConnell and Corby Robertson III have voting and dispositive power over the shares held by this selling stockholder.
(10): Bodri Capital Management, LLC is the general partner of The Catfish Fund, LP, and Jerome H. Debs, II and Neal S. Jacobs are the sole members of Bodri Capital Management, LLC. By virtue of their position with Bodri Capital Management, LLC, Messrs. Debs and Jacobs are deemed to have voting and dispositive power over the shares held by this selling shareholder.
(11): Mr. Uhland is our former President. Please see "Security Ownership of Certain Beneficial Owners and Management" for further information regarding his ownership in us.

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DESCRIPTION OF CAPITAL STOCK

The following description is based on relevant portions of the General Corporation Law of the State of Delaware and on our certificate of incorporation and bylaws. This summary is not necessarily complete, and we refer you to the Delaware General Corporation Law and our Second Amended and Restated Certificate of Incorporation and our Amended and Restated Bylaws for a more detailed description of the provisions summarized below.

Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.01 per share, and 25,000,000 shares of preferred stock, par value $0.01 per share.

Common Stock

There are a total of 25,178,301 shares of common stock issued and outstanding as of March 31, 2007, which includes 74,270 shares of restricted common stock issued to non-employee directors and certain employees under our stock incentive plan.

Voting Rights

The holders of common stock are entitled to one vote per share on all matters submitted to a vote of the stockholders. Cumulative voting of shares of common stock is prohibited, which means that the holders of a majority of shares voting for the election of directors can elect all members of our board of directors. Except as otherwise required by applicable law and except for certain matters set forth in our certificate of incorporation, some of which are discussed below, a majority vote is sufficient for any act of stockholders.

Dividend Rights

Subject to the preferences that may be applicable to any outstanding preferred stock, the holders of common stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by our board of directors out of funds legally available for the payment of dividends.

Liquidation Rights

In the event of our liquidation, dissolution, or winding up, the holders of common stock are entitled to share ratably in all assets remaining after payment of liabilities and amounts owed to creditors and holders of preferred stock, if any. All outstanding shares of our common stock are fully paid and nonassessable.

Other Matters

The holders of common stock have no preemptive or conversion rights or other subscription rights, and there are no redemption or sinking fund provisions applicable to the common stock.

The rights, preferences and privileges of holders of common stock are subject to, and may be adversely affected by, the rights of the holders of shares of any series of preferred stock that the board of directors may designate and issue in the future. The issuance of preferred stock could decrease the amount of earnings and assets available for distribution to holders of common stock or adversely affect the rights and powers of the holders of common stock, including their voting rights.

Preferred Stock

We are authorized to issue up to 25,000,000 shares of preferred stock, in one or more series, having rights senior to our common stock. Our board of directors is authorized to establish the powers, rights, preferences, privileges and designations of one or more series of preferred stock without further stockholder approval.

No shares of preferred stock are currently issued and outstanding and our board of directors has not designated any rights or preferences of any authorized shares of preferred stock. The rights,

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preferences, privileges and restrictions of any series of preferred stock issued by us in the future will be fixed by a certificate of designation relating to each series specifying the terms of the preferred stock, including:

•: the maximum number of shares in the series and the distinctive designation;
•: the terms on which dividends will be paid, if any, including whether dividends will be cumulative or non-cumulative;
•: the terms on which the shares may be redeemed, if at all;
•: the liquidation preference, if any;
•: the terms and conditions, if any, on which the shares of the series will be convertible into, or exchangeable for, shares of any other class or classes of capital stock;
•: restrictions on the issuance of shares;
•: the voting rights and powers, if any, on the shares of the series; and
•: any or all other powers, privileges, preferences and rights, and qualifications, limitations or restrictions of the shares.

Anti-Takeover Provisions

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

•: authorize the issuance of blank check preferred stock that could be issued by our board of directors to thwart a takeover attempt;
•: classify the board of directors into staggered, three-year terms, which may lengthen the time required to gain control of our board of directors;
•: prohibit cumulative voting in the election of directors, which would otherwise allow holders of less than a majority of stock to elect some directors;
•: require super-majority voting by our stockholders to effect amendments to provisions of our certificate of incorporation concerning the number of directors;
•: require super-majority voting by our stockholders to effect any stockholder-initiated amendment to any provision of our bylaws;
•: limit who may call special meetings of our stockholders;
•: prohibit stockholder action by written consent, thereby requiring all actions to be taken at a meeting of the stockholders;
•: establish advance notice requirements for stockholder nominations of candidates for election to the board of directors or for stockholder proposals that can be acted upon at annual meetings of stockholders; and
•: require that vacancies on the board of directors, including newly-created directorships, be filled only by a majority vote of directors then in office.

Business Combinations Under Delaware Law

We are subject to the provisions of Section 203 of the Delaware General Corporation Law. In general, Section 203 prohibits a publicly held Delaware corporation from engaging in a "business combination" with an "interested stockholder" for a period of three years after the date of the transaction in which the person became an interested stockholder, unless the business combination is approved in a prescribed manner.

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Under Section 203, a "business combination" is generally defined as a merger, asset sale or other transaction resulting in a financial benefit to the interested stockholders and an "interested stockholder" is generally defined as a person who, together with any affiliates and associates, owns, or, in some cases, within three years prior did own, 15% or more of our voting stock. Under Section 203, a business combination between us and an interested stockholder is prohibited unless:

•: our board of directors approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder prior to the date on which the stockholder attained such status;
•: upon consummation of the transaction which resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding, for purposes of determining the number of shares outstanding, shares owned by (i) persons who are directors and also officers of us and (ii) employee stock plans under which employee participants do not have the right to determine confidentially whether shares held under the plan will be tendered in a tender or exchange offer; or
•: the business combination is approved by our board of directors on or subsequent to the date on which the interested stockholder attained such status and authorized at an annual or special meeting of the stockholders by the affirmative vote of the holders of at least 66²/3% of the outstanding voting stock that is not owned by the interested stockholder.

This provision has an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock. With approval of our stockholders, we could amend our certificate of incorporation in the future to elect not to be governed by the anti-takeover law. This election would be effective 12 months after the adoption of the amendment and would not apply to any business combination between us and any person who became an interested stockholder on or before the adoption of the amendment.

Related Party Transactions and Corporate Opportunities

Subject to the limitations of our certificate of incorporation and applicable law, our certificate of incorporation, among other things:

•: permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;
•: permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments;
•: limits the fiduciary duties of certain of our stockholders, their affiliates and our directors and officers in potential conflict of interest, competition and corporate opportunity scenarios; and
•: provides that certain corporate opportunities made available to certain of our stockholders belong to such stockholders and that we waive any claim that any such corporate opportunity should have been presented to us.

Transfer Agent and Registrar

Our transfer agent and registrar for our common stock is Computershare Trust Company, N.A.

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock. The market price of our common stock could drop due to sales of a large number of shares of our common stock or the perception that these sales could occur. These factors could also make it more difficult to raise funds through future offerings of common stock.

After this offering, 28,928,301 shares of common stock will be outstanding. Of these shares, the 3,750,000 shares sold in this offering, or 4,312,500 shares if the underwriters exercise their over-allotment option in full, will be freely tradable without restriction under the Securities Act (except for any shares purchased by one of our "affiliates" as defined in Rule 144 under the Securities Act). All of the shares outstanding other than the shares sold in this offering (a total of 25,178,301 shares, or 24,615,801 shares if the underwriters exercise their over-allotment option in full) are "restricted securities" within the meaning of Rule 144 under the Securities Act and subject to lockup arrangements.

In connection with this offering, we, our directors and executive officers and the selling stockholders will enter into lockup agreements with the underwriters under which we and they will agree that, other than in this offering and subject to certain exceptions, we and they will not, directly or indirectly, offer, sell, contract to sell, pledge or otherwise dispose of or hedge any common stock or securities convertible into or exchangeable for shares of common stock, or publicly announce the intention to do any of the foregoing, without the prior written consent of Friedman, Billings, Ramsey & Co., Inc. for a period of 180 days from the date of this prospectus (60 days in the case of the selling stockholders other than DLJ Merchant Banking and Carrizo). Please see "Underwriting" for a description of these lockup arrangements. Pursuant to either our amended and restated securityholders agreement or the registration rights agreement entered into between us and Friedman, Billings, Ramsey & Co., Inc., our existing stockholders who are not participating in this offering as selling stockholders have agreed not to sell any shares of common stock or securities convertible into or exchangeable or exercisable for shares of common stock for a period of 60 days from the date of this prospectus. Please see "Registration Rights" for a description of these lockup arrangements. Upon the expiration of these restricted periods, 25,104,031 shares, or 24,541,531 shares if the underwriters exercise their over-allotment option in full, will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to the restrictions contained therein.

Restricted securities generally may not be sold unless they are registered under the Securities Act or are sold pursuant to an exemption from registration, such as the exemption provided by Rule 144 under the Securities Act. In connection with our April 2006 private placement, we agreed to use commercially reasonable efforts to file a shelf registration statement with the SEC registering the shares sold in our private placement for resale. We have filed a shelf registration statement with the SEC which will register all of the outstanding shares of our common stock (other than those sold in this offering and shares of restricted common stock issued to our non-employee directors and certain of our employees under our stock incentive plan) for resale, although this shelf registration statement has not been declared effective. We expect that the shelf registration statement will be declared effective subsequent to this offering. Upon the effectiveness of this shelf registration statement and the expiration of the applicable restricted periods described above, 25,104,031 shares, or 24,541,531 shares if the underwriters exercise their over-allotment option in full, will be eligible for sale in the public market and freely tradeable without restriction under the Securities Act. The market price of our common stock could drop significantly if the holders of these formerly restricted shares sell them, or are perceived by the market as intending to sell them.

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unexercised options or the expiration or waiver of vesting conditions for restricted stock and the expiration of lockups we and certain of our stockholders have entered into, shares registered under these registration statements on Form S-8 will be available for resale immediately in the public market without restriction.

Rule 144

In general, under Rule 144 as currently in effect, any person (or persons whose shares are aggregated), including an affiliate, who has beneficially owned shares for a period of at least one year is entitled to sell, within any three-month period, a number of shares that does not exceed the greater of:

•: 1% of the number of then outstanding shares of common stock; and
•: the average weekly trading volume of our common stock on the NASDAQ during the four calendar weeks immediately preceding the date on which the notice of the sale on Form 144 is filed with the SEC.

Sales under Rule 144 are also subject to other provisions relating to notice and manner of sale and the availability of current public information about us.

Rule 144(k)

Under Rule 144(k), a person who is not deemed to have been one of our affiliates at any time during the 90 days preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years, including the holding period of any prior owner other than an "affiliate," is entitled to sell the shares without complying with the manner of sale, public information, volume limitation or notice provisions of Rule 144.

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UNDERWRITING

Friedman, Billings, Ramsey & Co., Inc. (FBR) is the representative of the several underwriters named below. We and the selling stockholders will enter into an underwriting agreement with the representatives of the underwriters. Subject to the terms and conditions of the underwriting agreement, we and the selling stockholders will agree to sell to the underwriters, and each underwriter will agree to purchase, the number of shares of common stock listed next to its name in the following table:

Underwriter		Number of Shares
Friedman, Billings, Ramsey & Co., Inc.
RBC Capital Markets Corporation
A.G. Edwards & Sons, Inc.
Johnson Rice & Company L.L.C.

Total		3,750,000

At our request, the underwriters have reserved from the shares we are offering up to 75,000 shares, representing up to 2% of the aggregate number of shares offered in this offering, for sale to our employees, directors, family members, friends and certain other persons having business relationships with us at the public offering price per share. No underwriting discounts and commissions are paid upon these shares. We do not know if any employees, directors, family members, friends or business associates will choose to purchase all or any portion of the reserved shares, but any purchases such persons do make will reduce the number of shares available to the general public. Persons who purchase reserved shares will agree not to offer, sell or contract to sell or otherwise dispose of those shares, without the prior written consent of FBR, on behalf of the underwriters, for a period of 180 days from the date of this prospectus.

The underwriting agreement will be subject to a number of terms and conditions and provides that the underwriters must buy all of the shares if they buy any of them. The underwriters will sell the shares to the public when and if the underwriters buy the shares from us and the selling stockholders.

We and the selling stockholders have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act.

The underwriters initially will offer the shares to the public at the price specified on the cover page of this prospectus. The underwriters may allow a concession of not more than $ per share to selected dealers. The underwriters may also allow, and those dealers may re-allow, a concession of not more than $ per share to some other dealers. If all the shares are not sold at the public offering price, the underwriters may change the public offering price and the other selling terms. The common stock is offered subject to a number of conditions, including:

•: receipt and acceptance of the common stock by the underwriters; and
•: the underwriters' right to reject orders in whole or in part.

We and the selling stockholders estimate that our and their share of total expenses of the offering, excluding underwriting discounts and commissions, will be approximately $750,000.

Over-Allotment Option. The selling stockholders have granted the underwriters an over-allotment option to buy up to 562,500 additional shares of our common stock at the same price per share as they are paying for the shares shown in the table above. These additional shares would cover sales of shares by the underwriters that exceed the total number of shares shown in the table above. The underwriters may exercise this option at any time within 30 days after the date of this prospectus. To the extent that the underwriters exercise this option, each underwriter will purchase additional shares from us in

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approximately the same proportion as it purchased the shares shown in the table above. If purchased, the additional shares will be sold by the underwriters on the same terms as those on which the other shares are sold. We will pay the expenses associated with the exercise of this option.

Discounts and Commissions. The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters by us and by the selling stockholders. These amounts are shown assuming no exercise and full exercise of the underwriters' option to purchase additional shares.

	Paid by Us		Paid by the Selling Stockholders
	No Exercise	Full Exercise	No Exercise		Full Exercise
Per Share	$	$	$	—	$
Total	$	$	$	—	$

Listing. Our common stock has been approved for listing on The NASDAQ Global Market, subject to official notice of issuance, under the symbol "PINN." In order to meet one of the requirements for listing the common stock on the NASDAQ, the underwriters have undertaken to sell lots of 100 or more shares to a minimum of 400 beneficial owners.

Stabilization. In connection with this offering, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of our common stock, including:

•: stabilizing transactions;
•: short sales;
•: syndicate covering transactions;
•: imposition of penalty bids; and
•: purchases to cover positions created by short sales.

Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of our common stock while this offering is in progress. Stabilizing transactions may include making short sales of our common stock, which involves the sale by the underwriters of a greater number of shares of common stock than they are required to purchase in this offering, and purchasing shares of common stock from us or in the open market to cover positions created by short sales. Short sales may be "covered" shorts, which are short positions in an amount not greater than the underwriters' overallotment option referred to above, or may be "naked" shorts, which are short positions in excess of that amount. Syndicate covering transactions involve purchases of our common stock in the open market after the distribution has been completed in order to cover syndicate short positions.

The underwriters may close out any covered short position either by exercising their over-allotment option, in whole or in part, or by purchasing shares in the open market. In making this determination, the underwriters will consider, among other things, the price of shares available for purchase in the open market compared to the price at which the underwriters may purchase shares through the over-allotment option.

A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common stock in the open market that could adversely affect investors who purchased shares of our common stock in this offering. To the extent that the underwriters create a naked short position, they will purchase shares in the open market to cover the position.

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The representatives also may impose a penalty bid on underwriters and dealers participating in the offering. This means that the representatives may reclaim from any syndicate member or other dealers participating in the offering the commissions and selling concessions on shares sold by them and purchased by the representatives in stabilizing or short covering transactions.

These activities may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of our common stock. As a result of these activities, the price of our common stock may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them at any time. The underwriters may carry out these transactions on the NASDAQ, in the over-the-counter market or otherwise. Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common stock.

Discretionary Accounts. The underwriters have informed us that they do not expect to make sales to accounts over which they exercise discretionary authority in excess of 5% of the shares of common stock being offered.

IPO Pricing. Prior to this offering, there has been no public market for our common stock. The initial public offering price will be negotiated between us and the representative of the underwriters. The factors to be considered in these negotiations are:

•: the history of, and prospects for, us and the industry in which we compete;
•: our past and present financial performance;
•: an assessment of our management;
•: the present state of our development;
•: the prospects for our future earnings;
•: the prevailing conditions of the applicable United States securities market at the time of this offering; and
•: market valuations of publicly traded companies that we and the representatives of the underwriters believe to be comparable to us.

The estimated initial public offering price range set forth on the cover of this preliminary prospectus is subject to change as a result of market conditions and other factors.

Lockup Agreements. We, our directors and executive officers and all of the selling stockholders will enter into lockup agreements with the underwriters. Under these agreements, subject to exceptions, we may not issue any new shares of common stock, and we, our directors and executive officers and the selling stockholders may not, directly or indirectly, offer, sell, contract to sell, pledge or otherwise dispose of or hedge any common stock or securities convertible into or exchangeable for shares of common stock, or publicly announce the intention to do any of the foregoing, without the prior written consent of FBR, on behalf of the underwriters, for a period of 180 days from the date of this prospectus (60 days in the case of the selling stockholders other than DLJ Merchant Banking and Carrizo). This consent may be given at any time without public notice. In addition, other than the shelf registration statement, during the applicable restricted period we will agree not to file any registration statement for, and each of our directors and executive officers and the selling stockholders will agree not to make any demand for, or exercise any right of, the registration of any shares of common stock or any securities convertible into or exercisable or exchangeable for common stock without the prior written consent of FBR, on behalf of the underwriters. In addition, pursuant to the registration rights agreement, our stockholders who purchased shares of common stock in our April 2006 private

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placement but are not participating in this offering may not effect any public sale or distribution of shares of common stock or securities convertible into or exchangeable or exercisable for shares of common stock without the prior written consent of FBR, on behalf of the underwriters, for a period of 60 days from the effective date of this registration statement.

Other Relationships. Certain of the underwriters and their respective affiliates have from time to time performed, and may in the future perform, various financial advisory and investment banking services for us, for which they received or will receive customary fees and expenses. In particular, FBR acted as initial purchaser and placement agent in connection with our April 2006 private placement, in which we sold an aggregate of 12,835,230 shares of common stock in transactions exempt from the registration requirements of the Securities Act.

We have not authorized any dealer, salesperson or other person to give any information or to represent anything to you other than the information contained in this prospectus. You must not rely on unauthorized information. This prospectus does not offer to sell or ask for offers to buy any of the shares of common stock offered hereby in any jurisdictions where it is unlawful. The information in this prospectus is current only as of its date.

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REGISTRATION RIGHTS

All of our shares of common stock (other than those sold in this offering) are "restricted securities" within the meaning of the Securities Act, which means they generally may not be sold unless they are registered under an effective registration statement or are sold pursuant to an exemption from registration. In connection with our April 2006 private placement, and pursuant to the registration rights agreement described below, we agreed to use commercially reasonable efforts to file a shelf registration statement with the SEC registering the shares sold in our private placement for resale. We have filed a shelf registration statement with the SEC which will register all of the outstanding shares of our common stock (other than those sold in this offering and shares of restricted common stock issued to our directors and certain employees under our stock incentive plan) for resale, although this shelf registration statement has not been declared effective. We expect that the shelf registration statement will be declared effective subsequent to this offering.

Pursuant to the Securityholders Agreement. Subject to certain restrictions, our amended and restated securityholders agreement provides DLJ Merchant Banking and CCBM with certain demand rights to require us to register their shares of our common stock. DLJ Merchant Banking and its funds may require us to register shares of common stock on up to three occasions. At any time after the consummation of this offering, CCBM has the right on one occasion to require us to register shares of common stock, provided that CCBM holds of record not less than 10% of our common stock on a fully diluted basis. We are not obligated to effect a demand registration unless the proposed offering proceeds for the offering equal or exceed $25 million. In addition, DLJ Merchant Banking and CCBM also have certain piggyback registration rights pursuant to the securityholders agreement which they have exercised in connection with the filing of the shelf registration statement referenced above and the filing of this registration statement.

Pursuant to the securityholders' agreement, DLJ Merchant Banking and CCBM have agreed to lock up provisions to the extent required by the underwriters. Please see "Underwriting." This lockup prevents them from exercising any demand registration rights under the securityholders' agreement during the lockup period, except that each of such stockholders is entitled to include a portion of their common stock on this registration statement.

Pursuant to the Registration Rights Agreement. Holders of common stock who purchased in our private placement are entitled to the benefits of a registration rights agreement between us and Friedman, Billings, Ramsey & Co., Inc. Pursuant to that registration rights agreement, we agreed, at our expense, to file with the SEC no later than 60 days following the closing of the private placement a shelf registration statement registering for resale the shares of our common stock sold in the private placement. The shelf registration statement referenced above was filed to meet in part our obligations under the registration rights agreement.

Pursuant to the registration rights agreement, the holders of our common stock that are beneficiaries of the registration rights agreement will not be able to sell any shares of common stock or securities convertible into or exchangeable or exercisable for shares of common stock for a period of 60 days following the effective date of this registration statement.

We agreed to use our commercially reasonable efforts to continuously maintain the effectiveness of the shelf registration statement under the Securities Act until the first to occur of:

•: the sale, transfer or other disposition of all of the shares of common stock covered by the shelf registration statement pursuant to a registration statement or pursuant to Rule 144 under the Securities Act;
•: such time as all of the shares of our common stock originally sold in our private placement and covered by the shelf registration statement and not held by affiliates of us are, in the opinion of

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our counsel, eligible for sale pursuant to Rule 144(k) (or any successor or analogous rule) under the Securities Act;

•: the shares have been sold to us or any of our subsidiaries; or
•: the second anniversary of the initial effective date of the shelf registration statement.

In addition, the holders of our common stock who purchased shares in our private placement have certain piggyback registration rights pursuant to the registration rights agreement and certain of our stockholders have exercised their piggyback rights in connection with the filing of this registration statement.

We cannot, without the prior written consent of the holders of a majority of the outstanding registrable shares under the registration rights agreement, enter into any agreement with current or prospective holders that would allow them (i) to include their shares in any registration statement filed pursuant to the registration rights agreement, unless such holders reduce the amount of their shares to be included if necessary to allow the inclusion of all the shares of the holders under the registration rights agreement or (ii) to have their common stock registered on a registration statement that could be declared effective prior to or within 180 days of the effective date of the shelf registration statement filed pursuant to the registration rights agreement. The provisions described in this paragraph do not apply to the registration rights of our existing stockholders under the amended and restated securityholders agreement and other agreements entered into with our existing stockholders prior to our private placement.

We will bear certain expenses incident to our registration obligations upon exercise of registration rights under the registration rights agreement, including the payment of federal securities law and state blue sky registration fees and legal fees of one counsel representing all the holders of registrable shares. We will not bear any brokers' discounts or fees, underwriting discounts or commissions or transfer taxes relating to the sale of shares of our common stock. We will agree to indemnify each selling stockholder exercising registration rights for certain violations of federal or state securities laws in connection with any registration statement in which such selling stockholder sells its shares of our common stock pursuant to these registration rights. Each selling stockholder will in turn agree to indemnify us for federal or state securities law violations that occur in reliance upon written information it provides for us in the registration statement.

The preceding summaries of certain provisions of the securityholders agreement and the registration rights agreement are not intended to be complete, and are subject to, and qualified in their entirety by reference to, all of the provisions of the securityholders agreement and the registration rights agreement, and you should read these summaries together with the complete text of the securityholders agreement and the registration rights agreement filed as exhibits to this registration statement.

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MATERIAL U.S. FEDERAL TAX CONSIDERATIONS
FOR NON-U.S. HOLDERS OF OUR COMMON STOCK

The following is a general discussion of the material U.S. federal tax consequences to a non-U.S. holder of the ownership and disposition of our common stock, but is not a complete analysis of all the potential tax consequences relating thereto. For the purposes of this discussion, a non-U.S. holder is any beneficial owner of our common stock that for U.S. federal income tax purposes is not a "U.S. person." For purposes of this discussion, the term "U.S. person" means:

•: an individual citizen or resident of the United States;
•: a corporation or a partnership (or other entity or arrangement taxable as a corporation or a partnership for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state, any political subdivision thereof or the District of Columbia;
•: an estate the income of which is subject to U.S. federal income tax regardless of its source; or
•: a trust (x) if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust or (y) which has made a valid election to be treated as a U.S. person.

If an entity classified as a partnership for U.S. federal income tax purposes holds our common stock, the tax treatment of a partner will generally depend on the status of the partner and upon the activities of the partnership. Accordingly, partnerships which hold our common stock and partners in such partnerships should consult their tax advisors.

This discussion does not address all aspects of U.S. federal income and estate taxation that may be relevant in light of a non-U.S. holder's special tax status or special circumstances. U.S. expatriates, insurance companies, tax-exempt organizations, dealers in securities, banks or other financial institutions, "controlled foreign corporations," "passive foreign investment companies," broker-dealers, corporations that accumulate earnings and profits to avoid U.S. federal income tax and investors that hold our common stock as part of a hedge, straddle or conversion transaction are among those categories of potential investors that may be subject to special rules not covered in this discussion. This discussion does not address any tax consequences arising under the laws of any state, local or non-U.S. jurisdiction. Furthermore, the following discussion is based on current provisions of the Internal Revenue Code of 1986, as amended (the "Code") and Treasury Regulations and administrative and judicial interpretations thereof, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. Accordingly, each non-U.S. holder should consult its tax advisors regarding the U.S. federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of shares of our common stock.

Dividends

We do not presently anticipate paying cash distributions on shares of our common stock. For more information, please see "Dividend Policy." In the event that we do pay distributions on our common stock, however, these distributions generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Amounts not treated as dividends for U.S. federal income tax purposes will constitute a return of capital and will first be applied against and reduce a holder's adjusted tax basis in the common stock, but not below zero, and then the excess, if any, will be treated as gain from the sale of the common stock.

Amounts treated as dividends paid to a non-U.S. holder of common stock generally will be subject to U.S. withholding tax either at a rate of 30% of the gross amount of the dividends or such lower rate

112

as may be specified by an applicable tax treaty. In order to receive a reduced treaty rate, a non-U.S. holder must provide a valid Internal Revenue Service, or "IRS," Form W-8BEN, or other successor form, certifying qualification for the reduced rate.

Dividends received by a non-U.S. holder that are effectively connected with a U.S. trade or business conducted by the non-U.S. holder are exempt from such withholding tax. In order to obtain this exemption, a non-U.S. holder must provide a valid IRS Form W-8ECI, or other successor form, properly certifying such exemption. Effectively connected dividends, although not subject to withholding tax, are generally taxed at the same graduated rates applicable to U.S. persons, net of allowable deductions and credits.

In addition to the graduated tax described above, dividends received by a corporate non-U.S. holder that are effectively connected with a U.S. trade or business of such holder may also be subject to a branch profits tax at a rate of 30% or such lower rate as may be specified by an applicable income tax treaty.

A non-U.S. holder of our common stock eligible for a reduced rate of U.S. withholding tax pursuant to an income tax treaty may obtain a refund of any excess amounts withheld by filing an appropriate claim for refund with the IRS.

Gain on Disposition of Common Stock

A non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:

•: the gain is effectively connected with a U.S. trade or business of the non-U.S. holder and, if a tax treaty applies, attributable to a U.S. permanent establishment maintained by such non-U.S. holder;
•: the non-U.S. holder is an individual who holds the common stock as a capital asset (generally, an asset held for investment purposes) and who is present in the United States for a period or periods aggregating 183 days or more during the taxable year in which the sale or disposition occurs and certain other conditions are met; or
•: our common stock constitutes a U.S. real property interest by reason of our status as a "U.S. real property holding corporation," or "USRPHC," for U.S. federal income tax purposes at any time within the shorter of the five-year period preceding the disposition or the holder's holding period for our common stock.

Unless an applicable treaty provides otherwise, gain described in the first bullet point above will be subject to U.S. federal income tax imposed on net income on the same basis that applies to U.S. persons generally and, for corporate holders under certain circumstances, the branch profits tax, but will generally not be subject to withholding, provided any certification requirements are met. Gain described in the second bullet point above, which may be offset by United States source capital losses even though the recipient is not considered a resident of the United States, will be subject to a flat 30% U.S. federal income tax. Non-U.S. holders should consult any applicable income tax treaties that may provide different rules.

We believe that we are a USRPHC for U.S. federal income tax purposes. However, our common stock would not be treated as a U.S. real property interest with respect to a non-U.S. holder if our common stock were considered to be "regularly traded on an established securities market," within the meaning of Section 897 of the Code and the applicable Treasury Regulations, at any time during the calendar year in which the sale or other disposition occurs and the non-U.S. holder does not actually or constructively own, at any time during the five-year period ending on the date of the sale or other disposition, more than 5% of our common stock. If our common stock is treated as a U.S. real

113

property interest, a non-U.S. holder of such common stock will be subject to U.S. federal income tax on a net income basis on any gain recognized on a sale or other disposition of our common stock, and a purchaser may be required to withhold 10% of the proceeds payable to such non-U.S holder from the disposition of our common stock. In addition, if the non-U.S. holder is a foreign corporation, the additional branch profits tax described above may apply. A non-U.S. holder disposing of a U.S. real property interest is required to file a U.S. tax return. Any amount withheld in excess of any tax owed may be refundable if the required information is timely furnished to the IRS. A non-U.S. holder should consult its tax advisors with respect to the application of the foregoing rules to its ownership and disposition of our common stock.

Federal Estate Taxes

Common stock owned or treated as being owned by an individual non-U.S. holder at the time of death will be included in such holder's gross estate for U.S. federal tax purposes and may be subject to U.S. federal estate tax, unless an applicable estate tax treaty provides otherwise.

Backup Withholding and Information Reporting

Generally, we must report annually to the IRS the amount of dividends paid, the name and address of the recipient, and the amount, if any, of tax withheld, together with other information. A similar report is sent to the recipient of the dividend. These information reporting requirements apply even if withholding was not required because the dividends were effectively connected dividends as described above or withholding could have been reduced or eliminated by an applicable income tax treaty. Pursuant to income tax treaties or other agreements, the IRS may make its reports available to tax authorities in the recipient's country of residence.

Backup withholding (currently at a rate of 28%) will generally not apply to payments of dividends made by us or our paying agents, in their capacities as such, to a non-U.S. holder of our common stock if the holder has provided the certification described above that it is not a U.S. person or has otherwise established an exemption.

Payment of the proceeds from a disposition by a non-U.S. holder of our common stock made by or through the U.S. office of a broker is generally subject to information reporting and backup withholding unless the non-U.S. holder certifies as to its non-U.S. holder status under penalties of perjury or otherwise establishes an exemption from information reporting and backup withholding.

Payments of the proceeds from a disposition effected outside the United States by a non-U.S. holder of our common stock made by or through a foreign office of a broker generally will not be subject to information reporting or backup withholding. However, information reporting (but not backup withholding) will apply to such a payment if the broker is a U.S. person, or has specified connections with the United States, unless in any such case the broker has documentary evidence that the beneficial owner is a non-U.S. holder and specified conditions are met or an exemption is otherwise established.

Backup withholding is not an additional tax. Rather, the tax liability of the non-U.S. holder subject to backup withholding will be reduced by the amount of any tax withheld. If any amounts withheld under the backup withholding rules result in an overpayment of taxes, a refund or a credit against a non-U.S. holder's U.S. federal income tax liability may be obtained provided that the required information is timely furnished to the IRS.

114

LEGAL MATTERS

The validity of the shares offered by this prospectus will be passed upon for us by our counsel, Andrews Kurth LLP, Houston, Texas. Certain legal matters in connection with the offering will be passed upon for the underwriters by Akin Gump Strauss Hauer & Feld LLP, New York, New York.

EXPERTS

The financial statements of Pinnacle Gas Resources, Inc. as of December 31, 2006 and 2005 and for the years ended December 31, 2006, 2005 and 2004 have been included herein in reliance upon the report of Ehrhardt Keefe Steiner & Hottman PC, independent registered public accounting firm, and upon the authority of said firm as experts in accounting and auditing.

The information included in this prospectus as of February 28, 2007 and December 31, 2006, 2005, 2004 and 2003 relating to our total gas supply and our owned gas reserves is derived from reports prepared or reviewed by Netherland, Sewell & Associates, Inc., independent petroleum engineers, as stated in their reserve reports with respect thereto. This information is included in this prospectus in reliance upon the authority of said firm as experts with respect to the matters covered by their reports and the giving of their reports.

CHANGE IN INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We dismissed PricewaterhouseCoopers LLP, our previous independent auditors, on September 19, 2005 based on the recommendation of our board of directors. We did not have any disagreements with PricewaterhouseCoopers regarding any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure which disagreement would have caused PricewaterhouseCoopers to make reference to the subject matter of the disagreement in connection with their audit report. PricewaterhouseCoopers' audit reports on our financial statements did not contain any adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles.

115

INDEX TO FINANCIAL STATEMENTS

		Page
Pinnacle Gas Resources, Inc. Audited Financial Statements:
Report of Independent Registered Public Accounting Firm		F-2
Balance Sheets as of December 31, 2005 and 2006		F-3
Statements of Operations the years ended December 31, 2004, 2005 and 2006		F-4
Statements of Cash Flows for the years ended December 31, 2004, 2005 and 2006		F-5
Statements of Redeemable Preferred Stock and Stockholders' Equity for the years ended December 31, 2004, 2005 and 2006		F-6
Notes to Financial Statements		F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Pinnacle Gas Resources, Inc.
Sheridan, Wyoming

We have audited the accompanying balance sheets of Pinnacle Gas Resources, Inc. as of December 31, 2006 and 2005, and the related statements of operations, redeemable preferred stock and stockholders' equity and cash flows for each of the years in the three year period ended December 31, 2006. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Pinnacle Gas Resources, Inc. as of December 31, 2006 and 2005 and the results of operations and cash flows for each of the years in the three year period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 13, the Company has changed its accounting method for stock-based compensation by adopting SFAS No. 123 (R) "Share-Based Payment" effective January 1, 2006.

/s/ Ehrhardt Keefe Steiner & Hottman PC

Denver, Colorado
March 22, 2007

F-2

PINNACLE GAS RESOURCES, INC.

Balance Sheets

				December 31
				2006			2005
				(in thousands except share and per share data)
Assets
Current assets
	Cash and cash equivalents			$	4,762		$	2,672
	Receivables
		Accrued gas sales			2,364			5,872
		Joint interest receivables, net of $100 (2006) allowance for doubtful accounts			9,237			2,645
	Assets held for sale				—			394
	Derivative instruments				2,856			—
	Inventory of material for drilling and completion				271			480
	Prepaid expenses				394			113

			Total current assets		19,884			12,176

Property and equipment, at cost, net of accumulated depreciation					2,107			1,888
Oil and gas properties, using full cost accounting, net of accumulated depreciation, depletion and amortization
	Proved				39,988			30,361
	Unproved				85,094			31,280
Inventory of material for drilling and completion					944			1,238
Deposits					520			—
Restricted certificates of deposit					1,795			138

			Total assets	$	150,332		$	77,081

Liabilities and Stockholders' Equity
Current liabilities
	Long-term debt-current portion			$	21		$	21
	Capital lease obligations				—			98
	Accrued dividends payable				—			1,213
	Trade accounts payable				17,567			5,339
	Revenue distribution payable				7,301			8,065
	Drilling prepayments from joint interest owners				289			—
	Accrued liabilities				2,375			2,030
	Derivative instruments				—			2,901

			Total current liabilities		27,553			19,667

Asset retirement obligations					2,321			1,277
Production taxes, non-current					843			1,005
Long-term debt-net of current portion					786			807
Derivative instruments					—			941
Derivative liability					—			200

			Total liabilities		31,503			23,897

Commitments and contingencies
Series A Redeemable Preferred stock, $0.01 par value; 25,000,000 authorized, 0 and 462,189 shares issued and outstanding at December 31, 2006 and December 31, 2005, respectively					—			31,400
Stockholders' equity
	Common stock, $0.01 par value; 100,000,000 authorized and 25,131,301 shares and 5,800,000 shares issued and outstanding at December 31, 2006 and December 31, 2005, respectively.				251			58
	Additional paid-in capital				119,354			10,852
	Warrants and options				—			15,428
	Accumulated deficit				(776	)		(4,554	)

			Total stockholders' equity		118,829			21,784

Total liabilities and stockholders' equity				$	150,332		$	77,081

The accompanying notes are an integral part of these financial statements.

F-3

PINNACLE GAS RESOURCES, INC.

Statements of Operations

			For the Years Ended December 31
			2006			2005			2004
			(in thousands except share and per share data)
Revenues
	Gas sales		$	12,196		$	14,136		$	7,393
	Gain/(loss) on derivatives			7,362			(4,815	)		(766	)
	Earn-in joint venture			379			1,629			368

		Total revenues		19,937			10,950			6,995

Operating Expenses
	Lease operating expenses			2,993			1,781			1,445
	Production taxes			1,198			1,637			838
	Marketing and transportation			1,962			1,582			1,218
	General and administrative, net			4,343			2,267			1,552
	Depreciation, depletion, amortization and accretion			6,673			5,622			3,328

		Total expenses		17,169			12,889			8,381

Operating income/(loss)				2,768			(1,939	)		(1,386	)

Other income(expense)
	Interest income			720			17			61
	Other income			484			129			4
	Unrealized derivative loss			(26	)		—			—
	Interest expense			(168	)		(47	)		(2	)

				1,010			99			63

Net income/(loss) before income taxes				3,778			(1,840	)		(1,323	)
Income taxes				—			—			—

Net income/(loss)				3,778			(1,840	)		(1,323	)
Preferred dividends				(20,964	)		(5,409	)		(2,623	)

Net loss attributabe to common shareholders			$	(17,186	)	$	(7,249	)	$	(3,946	)

Basic and diluted net loss per share			$	(0.87	)	$	(1.42	)	$	(0.79	)
Weighted average shares outstanding-basic and diluted				19,783,118			5,094,800			5,000,000

The accompanying notes are an integral part of these financial statements.

F-4

PINNACLE GAS RESOURCES, INC.

Statements of Cash Flows

				For the Years Ended December 31
				2006			2005			2004
				(in thousands)
Cash flows from operating activities
Net income/(loss)				$	3,778		$	(1,840	)	$	(1,323	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
	Depreciation, depletion, amortization and accretion				6,673			5,622			3,328
	(Gain)/loss on derivatives				(7,336	)		4,815			766
	Allowance for doubtful accounts				100			—			—
	Stock-based compensation				368			—			—
	Changes in assets and liabilities
		(Increase) in receivables			(3,184	)		(2,214	)		(4,869	)
		(Increase) decrease in inventory			209			24			(505	)
		(Increase) decrease in prepaid expenses			(281	)		289			(227	)
		Increase (decrease) in accounts payable and accrued liabilities			6,179			(1,573	)		320
		Increase (decrease) in revenue distribution payable			(764	)		3,672			3,891
		Increase in prepaids from third parties			289			—			—
		Asset retirement obligation settled during the period			(2	)		(3	)		(31	)

			Net cash provided by operating activities		6,029			8,792			1,350

Cash flows from investing activities
	Capital expenditures—exploration and production				(62,340	)		(20,866	)		(13,149	)
	Capital expenditures—property and equipment				(714	)		(1,698	)		(235	)
	Purchase of restricted certificates of deposit				(520	)		—			—
	Deposits				(1,657	)		—			—
	Increase (decrease) in inventory held for exploration and development				294			(733	)		(505	)
	Realized gain/(loss) on derivatives				663			(1,610	)		(128	)
	Proceeds from the sale of asset held for sale				394			—			—
	Increase in assets held for sale				—			(394	)		—

			Net cash used in investing activities		(63,880	)		(25,301	)		(14,017	)

Cash flows from financing activities
	Proceeds from issuance of preferred stock				—			15,000			12,000
	Issuance costs related to preferred stock				—			(300	)		(240	)
	Proceeds from issuance of common stock				141,187			169			—
	Issuance costs related to common stock				(11,252	)		—			—
	Dividends paid on preferred stock				(1,397	)		—			—
	Redemption of preferrred stock including redemption premium				(52,174	)		—			—
	Repurchase and cancellation of common shares				(16,304	)		—			—
	Principal payments on note payable and capital leases				(119	)		(116	)		(20	)
	Proceeds from long-term debt				—			829			—

			Net cash provided by financing activities		59,941			15,582			11,740

	Net increase (decrease) in cash and cash equivalents				2,090			(927	)		(927	)
	Cash and cash equivalents at beginning of year				2,672			3,599			4,526

	Cash and cash equivalents at end of year			$	4,762		$	2,672			3,599

Noncash investing and financing activities
	Capital expenditures included in trade accounts payable			$	6,232		$	2,941		$	1,779
	Asset retirement obligation included in oil and gas properties				884			656			128
	Assets acquired through capital leases				—			—			364
	Capital lease asset relequished				—			133			—
	Fair value of options and warrants				—			6,517			4,305
	Dividend paid in kind with the issuance of additional preferred stock				1,207			3,601			2,249
	Derivative liability related to preferred stock				232			42			59
	Cashless exercise of warrants and options				15,428			—			—
	Inventory used in oil and gas development				(294	)		733			505
Supplemental cash flow information
	Cash payments for interest, net of amount capitalized			$	168		$	47		$	2
	Cash payments for income taxes				—			—			—

The accompanying notes are an integral part of these financial statements.

F-5

PINNACLE GAS RESOURCES, INC.

Statements of Redeemable Preferred Stock and Stockholders' Equity

						Stockholders' Equity
	Preferred Stock					Common Stock
	Preferred Stock					Common Stock					Fair Value of Warrants and Options			Additional Paid-In Capital			Accumulated Deficit
	Shares		Amount			Shares		Amount			Fair Value of Warrants and Options			Additional Paid-In Capital			Accumulated Deficit			Total
	(in thousands except share amounts)
Balance at December 31, 2003	133,687		$	8,484		5,000,000		$	50		$	4,606		$	18,934		$	(1,391	)	$	22,199
Issuance of preferred stock for cash net of $240 offering costs	120,000			11,701		—			—			—			—			—			—
Fair value of warrants at issuance	—			(4,096	)	—			—			4,096			—			—			4,096
Fair value of escalating options	—			—		—			—			209			(209	)		—			—
Dividends on preferred	—			—		—			—			—			(2,623	)		—			(2,623	)
Dividends paid in-kind on preferred	22,495			2,249		—			—			—			—			—			—
Net loss	—			—		—			—			—			—			(1,323	)		(1,323	)

Balance at December 31, 2004	276,182			18,338		5,000,000			50			8,911			16,102			(2,714	)		22,349
Issuance of preferred stock for cash net of $300 of offering costs	150,000			14,658		—			—			—			—			—			—
Fair value of warrants at issuance	—			(5,197	)	—			—			5,197			—			—			5,197
Issuance of common stock upon exercise of Class B Warrants at $.01	—			—		750,000			8			—			(8	)		—			—
Issuance of common stock upon exercise of options	—			—		50,000			—			—			167			—			167
Dividends on preferred	—			—		—			—			—			(4,089	)		—			(4,089	)
Dividends paid in-kind on preferred	36,007			3,601		—			—			—			—			—			—
Warrants issued in connection with payment of dividend in-kind on preferred	—			—		—			—			1,320			(1,320	)		—			—
Net loss	—			—		—			—			—			—			(1,840	)		(1,840	)

Balance at December 31, 2005	462,189			31,400		5,800,000			58			15,428			10,852			(4,554	)		21,784
Dividends on preferred	—			—		—			—			—			(1,397	)		—			(1,397	)
Dividends paid in-kind on preferred	12,132			1,207		—			—			—			—			—			—
Stock-based compensation	—			—		—			—			—			289			—			289
Issuance of restricted shares	—			—		27,270			—			—			79			—			79
Sales of common stock for cash in a private placement, net of offering costs of $11,252	—			—		12,835,230			128			—			129,807			—			129,935
Redemption of preferred stock for cash, including redemption premium	(474,321	)		(32,607	)	—			—			—			(19,335	)		—			(19,335	)
Repurchase and cancellation of common stock	—			—		(1,593,783	)		(16	)		—			(16,288	)		—			(16,304	)
Cashless exercise of warrants and escalating options	—			—		8,062,584			81			(15,428	)		15,347			—			—
Net income	—			—		—			—			—			—			3,778			3,778

Balance as of December 31, 2006	—		$	—		25,131,301		$	251		$	—		$	119,354		$	(776	)	$	118,829

The accompanying notes are an integral part of these financial statements.

F-6

PINNACLE GAS RESOURCES, INC.

Notes to Financial Statements

Note 1—Summary of Significant Accounting Policies

Business and Basis of Presentation

On June 23, 2003, Pinnacle Gas Resources, Inc. (the "Company" or "Pinnacle") was formed as a Delaware corporation through a contribution of proved producing properties and undeveloped leaseholds from CCBM, Inc. ("CCBM"), a wholly-owned subsidiary of Carrizo Oil and Gas, Inc. ("Carrizo"), and Rocky Mountain Gas, Inc. ("RMG"), a former subsidiary of U.S. Energy Corporation, and a cash contribution from various Credit Suisse First Boston Private Equity entities ("CSFB"). In exchange for the contributed assets, CCBM and RMG each received 1,875,000 shares of common stock or approximately 37.5% of the Company's outstanding common stock as of the initial formation and options to purchase an additional 1,250,000 shares of the Company's common stock. In exchange for its cash contribution, CSFB received 1,250,000 shares of common stock, or approximately 25% of the Company's outstanding common stock as of the initial formation and 130,000 shares of redeemable preferred stock with detachable warrants to purchase 3,250,000 additional shares of common stock. The shares of common stock originally held by RMG were transferred to its affiliates, U.S. Energy and Crested Corp. (collectively, "U.S. Energy"), in May 2005.

Immediately following the formation, the Company used part of the cash proceeds to acquire an approximate 50% operative working interest in producing properties and undeveloped acreage in the eastern portion of the Powder River Basin, Wyoming, and has continued to acquire properties in this area, as well as in the Green River Basin.

In February 2004, March 2005 and September 2005, CSFB contributed additional cash in exchange for redeemable preferred stock with detachable warrants to purchase additional shares of common stock. In 2005, part of the cash proceeds were used for an acquisition of undeveloped properties in Montana and Wyoming.

In April 2006, the Company completed a private placement of 12,835,230 shares of common stock at a price of $11.00 per share. Immediately prior to the initial closing of the private placement, DLJ Merchant Banking exchanged all of its warrants for 6,894,380 shares of common stock in a tax-free reorganization and each of Carrizo and U.S. Energy entered into a cashless exercise of all of its options for 584,102 shares of commons stock, in each case based on the private placement price of $11.00 per share. The Company received net proceeds of approximately $130.6 million before out-of-pocket offering costs of $0.7 million, which were used as follows: (i) approximately $53.6 million to redeem all of the outstanding shares of Series A Redeemable Preferred Stock, including the payment of all accrued and unpaid dividends and a redemption premium, (ii) approximately $27.0 million for the acquisition of the Green River Basin assets, (iii) approximately $16.3 million to repurchase an aggregate of 1,593,783 shares of common stock at a price of $10.23 per share from shareholders, and (iv) approximately $33.0 million to fund the Company's development drilling program, additional out-of-pocket offering costs and for general corporate purposes.

Pinnacle's primary business is the exploration for, and the acquisition, development and production of coalbed methane natural gas in the United States. The Company is also engaged in gas property operations and the construction of low pressure gas collection systems which provide transportation for the Company's coal bed methane production.

The Company's proportionate share of capital expenditures, production revenue and operating expenses from working interests in oil and gas properties is included in the financial statements.

F-7

Stock Split

On March 10, 2006, the Company's board of directors approved a 25-for-1 stock split of its common stock in the form of a stock dividend. The board previously approved the amendment of the Company's certificate of incorporation to increase the authorized common stock to 100,000,000 shares. The earnings per share information and all common stock information have been retroactively restated for all years to reflect this stock split and amendment. The stock split was effective March 31, 2006.

Use of Estimates

The preparation of the Company's financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Significant estimates with regard to the financial statements include the estimated carrying value of unproved properties, the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, the estimated cost and timing related to asset retirement obligations, the estimated fair value of derivative assets and liabilities and the realizability of deferred tax assets.

Cash and Cash Equivalents

Cash in excess of daily requirements is generally invested in money market accounts and commercial paper with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the financial statements. The carrying amount of cash equivalents approximates fair value due to the short maturity and high credit quality of those investments. At times the Company maintains deposits in financial institutions in excess of federally insured limits. Management monitors the soundness of the financial institutions and believes the Company's risk is negligible.

Accounts Receivable

The Company's revenue producing activities are conducted primarily in Wyoming. The Company grants credit to qualified customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industry in which the Company operates and the financial condition of its customers. The Company continuously monitors collections and payments from its customers and if necessary, records an allowance for doubtful accounts based upon historical experience and any specific customer collection issues identified. As of December 31, 2006 and 2005, the Company had an allowance of $100,000 and $0, respectively.

Inventory

Pinnacle acquires inventory of oil and gas equipment, primarily tubulars, to take advantage of quantity pricing and to secure a readily available supply. Inventory is valued at the lower of average cost or market. Inventory is used in the development of gas properties and to the extent it is estimated that it will be billed to other working interest owners during the next year, it is included in current assets. Otherwise, the inentory is recorded in other non-current assets.

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Property and Equipment

Property and equipment is comprised primarily of a building, computer hardware and software, vehicles and equipment and is recorded at cost. Renewals and betterments that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed when incurred. Depreciation and amortization is provided using the straight-line method over the estimated useful lives of the assets as follows:

Buildings		30 years
Computer hardware and software		3-5 years
Machinery, equipment and vehicles		5 years
Office furniture and equipment		3-5 years

Long-Lived Assets

Long-lived assets to be held and used in the Company's business are reviewed for impairment whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable. When the carrying amounts of long-lived assets exceed the fair value, which is generally based on discounted expected future cash flows, the Company records an impairment. No impairments were recorded during the years ended December 31, 2006, 2005 and 2004.

Oil and Gas Properties

Pinnacle utilizes the full cost method of accounting for oil and gas producing activities. Under this method, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities are capitalized within a cost center. The Company's oil and gas properties are all located within the United States, which constitutes a single cost center. The Company has not capitalized any overhead costs. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of gas properties and the gain significantly alters the relationship between capitalized costs and proved gas reserves of the cost center. Expenditures for maintenance and repairs are charged to lease operating expense in the period incurred. Depreciation, depletion and amortization of oil and gas properties ("DD&A") is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves and asset retirement obligations. Pinnacle invests in unevaluated oil and gas properties for the purpose of exploration for proved reserves. The costs of such assets, including exploration costs on properties where a determination of whether proved oil and gas reserves will be established is still under evaluation, and any capitalized interest, are included in unproved oil and gas properties at the lower of cost or estimated fair market value and are not subject to amortization. On an annual basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonment of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized. The Company recorded an impairment of unproved properties of $0, $0, and $695,000, respectively, during the years ended December 31, 2006, 2005 and 2004. (See Note 6 for additional discussion of unproved

F-9

properties). Substantially all of such unproved property costs are expected to be developed and included in the amortization base over the next three to five years. Salvage value is taken into account in determining depletion rates and is based on the Company's estimate of the value of equipment and supplies at the time the well is abandoned. The estimated salvage value of equipment used in determining the depletion rate was $5,736,000, $3,306,000, and $741,000 as of December 31, 2006, 2005 and 2004, respectively.

Under full cost accounting rules, capitalized costs less accumulated depletion and related deferred income taxes, may not exceed the sum of (1) the present value discounted at ten percent of estimated future net revenue using current prices and costs, including the effects of derivative instruments designated as cash flow hedges but excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, less any related income tax effects; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of costs or estimated fair value of unproved properties; less (4) the income tax effects related to differences in the book to tax basis of oil and gas properties. This is referred to as the "full cost ceiling limitation." If capitalized costs exceed the limit, the excess must be charged to expense. The expense may not be reversed in future periods. At the end of each quarter, the Company calculates the full cost ceiling limitation.

At December 31, 2006, the carrying amount of oil and gas properties exceeded the full cost ceiling limitation by approximately $13.0 million, based upon a natural gas price of approximately $4.46 per Mcf in effect at that date. However, based on subsequent price increases to approximately $5.43 per Mcf of gas at the March 15, 2007 measurement date, the full cost ceiling limitation exceeded the carrying amount of the Company's oil and gas properties by approximately $1.4 million. Therefore, the Company was not required to record a ceiling write-down as of December 31, 2006. A decline in gas prices or an increase in operating costs subsequent to the measurement date or reductions in the economically recoverable quantities could result in the recognition of a ceiling write-down of the Company's oil and gas properties in a future period.

Asset Retirement Obligations

Pinnacle follows the provisions of Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires the Company to recognize an estimated liability for costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation with a corresponding increase to the carrying value of the related long-lived asset is recorded at the time a well is completed or acquired. The increased carrying value is depleted using the units-of-production method, and the discounted liability is increased through accretion over the remaining life of the respective oil and gas properties.

The estimated liability is based on historical gas industry experience in abandoning wells, including estimated economic lives, external estimates as to the cost to abandon the wells in the future and federal and state regulatory requirements. The Company's liability is discounted using Pinnacle's best estimate of its credit-adjusted risk free rate. Revisions to the liability could occur due to changes in estimated abandonment costs, changes in well economic lives or if federal or state regulators enact new requirements regarding the abandonment of wells.

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Changes in the carrying amount of the asset retirement obligations are as follows:

	December 31,
	2005			2004			2003
	(in thousands)
Beginning balance of asset retirement obligations	$	1,277		$	554		$	404
Additional obligation added during the period		953			186			128
Obligations settled during the period		(2	)		(3	)		(31	)
Revisions in estimates		(69	)		470			—
Accretion expense		162			70			53

Ending balance of asset retirement obligations	$	2,321		$	1,277		$	554

Capitalized Interest

The Company capitalizes interest costs to unproved oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Interest costs capitalized in 2006, 2005, and 2004 were $0, $148,000, and $0, respectively.

Restricted Assets

Certificates of deposit. The Company holds a certificate of deposit ("CD") which expires in July 2007, totaling $144,000. The CD is collateral on bonding requirements. Because the Company intends to renew the CD in order to maintain its bonding requirements, the Company included the CD in restricted certificates of deposit as of December 31, 2006. Additionally, the Company holds a CD for $624,000 which was issued in February 2006. This CD collateralizes a letter of credit in favor of Powder River Energy Corporation, a local rural electric association, in order to secure power lines to the Kirby and Deer Creek areas. The Company included the CD in restricted certificates of deposit as of December 31, 2006 because as of March 22, 2007, the Company has renewed this CD in order to maintain a power supply on a long-term basis. In April 2006, the Company issued a $1,027,000 letter of credit in favor of Bitter Creek Pipelines, LLC to secure the construction of a high pressure pipeline and related compression facilities to the Company's Deer Creek and Kirby areas. This letter of credit expires in April 2007. The Company included this amount in restricted certificates of deposit as of December 31, 2006 because the Company anticipates it will be required to renew the CD because construction of the pipeline and compression facility is expected to take over a year to complete.

Deposits. In addition, the Company prepaid $500,000 to EMIT Technologies, Inc. for the construction of a water treatment plant near the Cabin Creek drilling area. The Company has also included $20,000 in deposits related to royalty payments. This amount is included in Deposits in the accompanying balance sheet as of December 31, 2006.

Gas Sales

Pinnacle uses the sales method for recording natural gas sales. Sales of gas applicable to Pinnacle's interest in producing natural gas leases are recorded as revenues when the gas is metered and title transferred pursuant to the gas sales contracts covering its interest in gas reserves. During such times as

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Pinnacle's sales of gas exceed its pro rata ownership in a well, such sales are recorded as revenues unless total sales from the well have exceeded Pinnacle's share of estimated total gas reserves underlying the property at which time such excess is recorded as a gas imbalance liability. At December 31, 2006 and 2005, there was no such liability recorded.

General and Administrative Expenses

General and administrative expenses are reported net of amounts allocated and billed to working interest owners of gas properties operated by the Company.

Transportation Costs

The Company accounts for transportation costs under Emerging Issues Task Force Issues 00-10, "Accounting for Shipping and Handling Fees and Costs", whereby amounts paid for transportation are classified as operating expenses.

Per Share Information

All per share information for common stock has been retroactively restated for all years to reflect an authorized 25-for-1 stock split effected as a stock dividend.

Income Taxes

The Company uses the asset and liability method of accounting for income taxes, in accordance with SFAS No. 109, "Accounting for Income Taxes". Deferred tax assets and liabilities are recognized for the expected future tax consequences of temporary differences between the financial statement and tax bases of assets and liabilities. If appropriate, deferred tax assets are reduced by a valuation allowance which reflects expectations of the extent to which such assets will be realized. As of December 31, 2006 and 2005, the Company had recorded a full valuation allowance for its net deferred tax asset.

Derivatives

The Company accounts for derivative instruments or hedging activities under the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". SFAS No. 133 requires the Company to record derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings.

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The Company periodically hedges a portion of its oil and gas production through swap and collar agreements. The purpose of the hedges is to provide a measure of stability to the Company's cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. Management of the Company decided not to use hedge accounting for these agreements. Therefore, in accordance with the provisions of SFAS No. 133, the changes in fair market value are recognized in earnings. See Note 8 for additional discussion of derivatives.

The Company's Series A Redeemable Preferred Stock (Note 14) includes a redemption feature triggered under certain conditions that was determined to be an embedded derivative requiring separate accounting under SFAS No. 133 that was separately accounted for at estimated fair value. The determination of fair value includes significant estimates by management including the term of the instrument, volatility of the price of the Company's common stock, interest rates and the probability of redemption, among other items. In April 2006, following the initial closing of the Company's private placement, the Company redeemed all of the outstanding shares of Series A Redeemable Preferred Stock including the payment of accrued and unpaid dividends.

Stock-Based Compensation

Effective January 1, 2006, the Company adopted SFAS No. 123(R), "Share-Based Payments," which requires companies to recognize compensation expense for share-based payments based on the estimated fair value of the awards.

SFAS No. 123(R) also requires that the benefits of the tax deductions in excess of compensation cost recognized for stock awards and options ("excess tax benefits") be presented as financing cash inflows in the Statement of Cash Flows. Prior to January 1, 2006, the Company accounted for share-based payments under the recognition and measurement provisions of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related Interpretations, as permitted by SFAS No. 123, "Accounting for Stock-Based Compensation". In accordance with APB No. 25, no compensation cost was required to be recognized for options granted that had an exercise price equal to or greater than the market value of the underlying common stock on the date of the grant.

The Company is required to adopt the prospective method for grants prior to January 1, 2006 as the Company had elected to value employee grants using the minimum value method under SFAS No. 123. For option grants and restricted stock accounted for under the prospective method, the Company will continue to account for the grants under the intrinsic value-based method prescribed by APB No. 25 and the related interpretations in accounting for stock options. Therefore, the Company does not record any compensation expense for stock options granted to employees prior to January 1, 2006 if the exercise price equaled the fair market value of the stock option on the date of the grant, and the exercise price, the number of shares eligible for issuance under the options, and vesting period are fixed.

Under SFAS No. 123(R), compensation expense for all share-based payments granted subsequent to January 1, 2006, based on the estimated grant date fair value, has been recorded in the year ended December 31, 2006. Results for prior periods have not been retroactively adjusted. For prior periods, the Company applied APB No. 25 and related interpretations, and provided the required proforma disclosures under SFAS No. 123, "Accounting for Stock-Based Compensation." The Company records compensation expense related to non-employees under the provisions of SFAS No. 123 and Emerging Issues Task Force EITF 96-18 "Accounting for Equity Instruments that are Issued to Other than

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Employees for Acquiring, or in conjunction with Selling Goods or Services" and recognizes compensation expense over the vesting periods of such awards.

The Company has computed the fair value of options granted using the Black-Scholes option pricing model. In order to calculate the fair value of the options, certain assumptions are made regarding components of the model, including risk-free interest rate, volatility, expected dividend yield, and expected option life. Changes to the assumptions could cause significant adjustments to valuation. For options granted before January 1, 2006, expected volatility was not considered because the Company was a private company at the grant date of these options. For stock option grants after January 1, 2006, the Company used a volatility rate of 35% and began to include estimated forfeiture rates. The Company estimated the volatility rate of its common stock at the date of the grant based on the historical volatility of comparable companies. The Company factored in expected retention rates combined with vesting periods to determine the average expected life. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of the grant. Accordingly, the Company has computed the fair value of all options granted during the years ended December 31, 2006, 2005 and 2004, (2005 and 2004 were calculated for disclosure purposes only) using the Black-Scholes option pricing model and the following weighted average assumptions:

	Year ended December 31,
	2006	2005	2004
Expected Volatility	35%	0%	0%
Dividend Yield	—	—	—
Risk Free Interest Rate	4.30% to 5.03%	3.46% to 4.44%	2.71% to 3.90%
Weighted Average expected life (in years)	5	5	5

Because the Company applied the minimum value method of valuing employee stock options prior to becoming a public company, as allowed by SFAS No. 123, the Company is precluded from presenting pro forma historical statements of operations information under SFAS 123(R).

New Accounting Pronouncements

In February 2006, SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140" was issued. This Statement resolves issues addressed in Statement 133 Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interests in Securitized Financial Assets". SFAS No. 155 became effective for the Company on January 1, 2007. The impact of SFAS No. 155 will depend on the nature and extent of any new derivative instruments entered into after the effective date.

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limitations is open. The cumulative effect of the initial application will be reported as an increase or decrease to retained earnings as of the beginning of the period in which it is adopted. The provisions of FIN No. 48 were effective January 1, 2007. The Company has not yet completed its evaluation of the impact FIN No. 48 will have when adopted. However, the Company currently believes that its implementation will not have a material impact on results of operations, financial position or liquidity.

In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements", which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements. Accordingly, this Statement does not require any new fair value measurements. However, for some entities, the application of this Statement will change current practice. The provisions of SFAS No. 157 are effective as of January 1, 2008. The Company is currently evaluating the impact of adopting SFAS No. 157 on its financial statements.

In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin ("SAB") No. 108 which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. SAB No. 108 is effective for the Company as of January 1, 2007. The Company is currently evaluating the impact of SAB No. 108 on its financial statements. However, the Company currently believes that its implementation will not have a material impact on the Company's results of operations, financial position or liquidity.

In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities." SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The Statement will be effective as of January 1, 2008 for the Company. The Statement offers various options in electing to apply the provisions of this Statement, and at this time the Company has not made any decisions in its application to the financial position or results of operations of the Company.

Note 2—Assets Held For Sale

In December 2005, the Company acquired an additional 5% working interest in certain of its proved properties in the Powder River Basin of Wyoming (Note 5). Under an existing Area of Mutual Interest Agreement ("AMI"), the Company was required to offer one-half of the newly acquired working interest to another working interest owner. Subsequent to year end, the other working interest owner exercised its option and purchased one-half of the 5% working interest from the Company. As a result, the related carrying value of the assets were recorded as assets held for sale in the accompanying balance sheet at December 31, 2005. No assets held for sale were recorded at December 31, 2006.

Note 3—Earn-In Joint Venture Agreement

As part of the consideration related to the acquisition of the properties at formation, Pinnacle signed an Earn-In Joint Venture ("EIJV") agreement whereby Pinnacle committed to spend $14,500,000 ("Spending Commitment") to develop properties in an area of mutual interest on behalf of

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the Company and the seller. The funds were expended for the drilling of new coal bed methane wells, creation or improvement of infrastructure to promote the gathering and production of the properties, and for remedial work on previously drilled wells. Pinnacle funded 100% of the Spending Commitment to earn a 50% working interest in the acquired properties. The Spending Commitment was fully met by May 2004.

Additionally, once the Spending Commitment was met under the EIJV, the Company recouped $2,417,000 of the amount expended under the Spending Commitment. The EIJV entitled the Company to receive 60% of all monthly pre-tax cash flows from the acquired properties until the entire $2,417,000 was realized. During the years ended December 31, 2006, 2005 and 2004, the Company realized additional gas revenues related to the EIJV of $379,000, $1,629,000, and $368,000, respectively. As of March 31, 2006, the Company had fully recouped the $2,417,000 and therefore, realized no additional gas revenues during the remaining quarters of 2006.

Note 4—Property and Equipment

Property and equipment consists of the following:

	December 31,
	2006			2005
	(in thousands)
Building	$	1,420		$	1,420
Computer hardware and software		546			354
Machinery, equipment and vehicles		958			516
Office furniture and equipment		150			71

		3,074			2,361
Less accumulated depreciation and amortization		(967	)		(473	)

Total	$	2,107		$	1,888

Depreciation expense related to property and equipment for the years ended December 31, 2006, 2005 and 2004, was $496,000, $328,000, and $112,000 respectively.

Note 5—Acquisitions and Divestitures

2004 Transactions

Effective January 1, 2004, Pinnacle exchanged its interest in 2,078 undeveloped acres with Burning Rock Energy, LLC for an interest in 2,172 undeveloped acres. The Company accounted for this transaction as a like-kind-exchange and paid $20,000 for the additional acres received.

2005 Transactions

During 2005, the Company acquired a 100% working interest in unproved oil and gas properties comprising approximately 223,000 acres. In certain instances, the Company was required to offer other working interest owners a portion of the acquired interest under existing AMI agreements. The sale of any interest under the AMI's resulted in no gain or loss being recorded in the accompanying statement of operations.

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In November 2005, the Company sold a 12.5% working interest in approximately 33,000 acres in Wyoming. The acreage was undeveloped and no gain or loss was recognized when the proceeds were received.

Additionally, on December 31, 2005, effective September 1, 2005, the Company acquired an additional 5% working interest in certain proved oil and gas properties in which the Company already had a working interest for $950,000. The operating results from September 1, 2005 to December 31, 2005 (a net $189,000) was recorded as an adjustment to the purchase price. As discussed in Note 2, the Company subsequently sold one-half of the acquired interest for an amount equal to one-half of the net carrying costs.

2006 Transactions

On April 20, 2006, the Company purchased undeveloped natural gas properties, including related interests and assets, located in the Green River Basin of Wyoming from Kennedy Oil for an aggregate purchase price of approximately $27.0 million in cash. The undeveloped leasehold is located in Sweetwater County in the Hay Reservoir area of the Green River Basin. In addition, the Company acquired a 65% working interest in existing deep rights below the base of the Fort Union formation. The acquisition was funded with a portion of the net proceeds from the April 2006 private placement.

Effective June 1, 2006, Pinnacle acquired a 100% working interest in 10 producing wells and 1,410 gross acres for a total purchase price of $1,575.000.

Note 6—Unproved Properties

The Company is currently participating in coal bed methane gas exploration and development activities on acreage in Montana and Wyoming. At December 31, 2006, a determination cannot be made about the extent of additional gas reserves that should be classified as proved reserves as a result of the exploration activities to date. Consequently, the associated property costs and exploration costs have been excluded in computing DD&A for the full cost pool. The Company will begin to calculate DD&A on these costs when the project is evaluated, which is currently estimated to be over the next one to five years.

Costs excluded from amortization relating to unproved properties at December 31, 2006 (in thousands) are as follows:

Period Incurred	Acquisition Costs		Exploration Costs		Development Costs		Capitalized Interest		Total
2003	$	12,915	$	—	$	—	$	—	$	12,915
2004		112		—		—		—		112
2005		13,167		1,418		—		148		18,253
2006		30,316		27,018		—		—		53,814

	$	56,510	$	28,436	$	—	$	148	$	85,094

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Suspended Wells Costs

The following table reflects the net changes in capitalized exploratory well costs during 2006, 2005 and 2004, and does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same period.

	For the years ended December 31,
	2006			2005		2004
	(in thousands)
Beginning balance	$	4,938		$	—	$	—
Additions to capitalized exploratory well costs pending determination of proved reserves		27,018			4,938		—
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		(3,520	)		—		—

Ending balance	$	28,436		$	4,938	$	—

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized since the completion of drilling

	For the years ended December 31,
	2006		2005		2004
	(in thousands)
Exploratory well costs capitalized for one year or less	$	27,018	$	4,938	$	—
Exploratory well costs capitalized for more than one year		1,418		—		—

Ending balance at December 31,	$	28,436	$	4,938	$	—

Number of projects with exploratory well costs that have been capitalized more than a year		1		—		—

The $1.4 million of exploratory well costs capitalized for more than one year are for wells located in Montana. The wells are hooked up to a gas sale pipeline and are in the dewatering phase. As the wells produce gas and are determined to be proved reserves, the well costs will be reclassified to the full cost pool.

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Note 7—Accrued Liabilities

Accrued liabilities consist of the following:

	December 31,
	2006			2005
	(in thousands)
Production taxes	$	2,960		$	2,786
Payroll and related taxes		258			249

		3,218			3,035
Less production taxes due after one year		(843	)		(1,005	)

Total	$	2,375		$	2,030

Accrued liabilities consist of production taxes and payroll expenses that are attributable to the fiscal year end but are not payable until after fiscal year end.

Note 8—Derivatives

Hedging Contracts

As of December 31, 2006 and 2005, the Company had natural gas hedges in place as follows:

Product		MMbtu Per Day	Fixed Price Range	Time Period
December 31, 2006
	Natural Gas—Collar	1,000	$5.00-$5.20	10/04-9/07
	Natural Gas—Collar	1,000	$6.50-$10.50	9/06-12/07
	Natural Gas—Collar	3,000	$7.00-$9.05	1/07-12/07
December 31, 2005
	Natural Gas—Collar	1,000	$5.00-$5.20	10/04-9/07
	Natural Gas—Collar	750	$5.00-$5.50	10/04-9/06
	Natural Gas—Collar	1,750	$6.70-$7.90	1/06-12/06

The Company has elected not to designate these derivatives as cash flow hedges under provisions of SFAS No. 133. Under this method, these derivative instruments are marked to market at the end of each reporting period and changes in the fair value are recorded in the accompanying statements of operations. The aggregate fair value of these contracts were estimated to be an asset totaling $2,856,000 at December 31, 2006 and a liability of $3,842,000 at December 31, 2005. The Company realized a hedging gain in 2006 of $663,000 and a loss of $1,610,000 and $128,000 in 2005 and 2004 which amounts are included in gains/losses on derivatives in the statement of operations and are included in the cash flows used in investing activities in the statements of cash flows.

The Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.

Other Derivatives

In connection with the issuances of the Series A Redeemable Preferred Stock (Note 14), the Company evaluated the terms and conditions the instruments, and the related warrants, in order to

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determine whether such terms and conditions and warrants represent embedded or freestanding derivative instruments under the provisions of SFAS No. 133 and Emerging Issues Task Force ("EITF") issue No. 00-19, "Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in a Company's Own Stock".

As a result of such evaluations, the Company determined that a conditional redemption feature included in the preferred stock represented an embedded derivative instrument. Accordingly, the embedded derivative was accounted for separately at estimated fair value under SFAS No. 133 for each issuance and was recorded as a long-term derivative liability in the accompanying balance sheet as of December 31, 2005. In April 2006, the Company redeemed the preferred stock and the fair value of the derivative of $232,000 was reclassified to stockholder's equity. (See Note 14 for discussion of preferred stock).

Note 9—Revenues Distributions Payable

Revenue distributions payable consist of the following:

	December 31,
	2006		2005
	(in thousands)
Revenue payable on current production	$	1,193	$	3,668
Revenues payable in suspense		6,108		4,397

Total revenues payable	$	7,301	$	8,065

The Company operates and disburses revenue to other working interest owners and royalty owners. Proceeds from gas sales are distributed and paid around 45 days after the end of the respective sales month. Revenue held in suspense is due primarily to the issuance of title opinions for wells in which the Company holds funds to distribute. Once a title opinion is received, revenue held in suspense is placed in line for payment under the normal payment cycle indicated above.

Note 10—Line-of-Credit

Effective October 22, 2004, the Company entered into a $30 million Credit Facility Agreement (the "Previous Credit Facility") with a bank. As of December 31, 2006, the borrowing base under the Previous Credit Facility was $7.75 million. Borrowings under the Previous Credit Facility bore interest at a rate equal to prime plus 0.50% or a one, two, three, or six month advanced LIBOR rate plus 3%. The Chairman of the Company was also a 7% stockholder and director in one of the lending banks. At December 31, 2006 and 2005, the Company did not have any outstanding borrowings under the Previous Credit Facility. Effective February 12, 2007, the Company entered into a new revolving credit facility and terminated the Previous Credit Facility. (See Note 21 for discussion of the new credit facility).

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Note 11—Long-Term Debt and Capital Lease Obligations

Long-term debt and capital lease obligations consist of the following:

	December 31,
	2006			2005
	(in thousands)
Note payable to a bank with interest at 6.875% until December 15, 2008 when it goes to Sheridan Bank prime plus ¹/2%. Due in monthly installment of $6,414 through November 15, 2015 when unpaid principal and interest are due. The note is collateralized by the building.	$	807		$	828
Capital lease obligations		—			98

		807			926
Less current portion		(21	)		(119	)

Total	$	786		$	807

The Company had assets under capital lease with a net book value of $154,000 at December 31, 2005.

The following are future minimum obligations for long-term debt as of December 31, 2006 (in thousands):


2007	$	22
2008		23
2009		19
2010		20
Thereafter		723

Total	$	807

Note 12—Income Taxes

The provision for income taxes consists of the following:

	December 31,
	2006			2005			2004
	(in thousands)
Current income tax expense	$	—		$	—		$	—
Deferred income tax expense (benefit)		628			(203	)		(201	)
Change in valuation allowance		(628	)		203			201

Total income tax benefit	$	—		$	—		$	—

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The effective income tax rate varies from the statutory federal income tax rate as follows:

	December 31,
	2006		2005		2004
Federal income tax rate	(34	)%	(34	)%	(34	)%
Change in valuation allowance and other	34		34		34

Effective tax rate	—	%	—	%	—	%

The significant temporary differences and carry-forwards and their related deferred tax asset (liability) and deferred tax asset valuation allowance balances are as follows:

			December 31,
			2006			2005			2004
			(in thousands)
Deferred tax assets
	Net operating loss carry-forward		$	2,954		$	416		$	416
	Oil and gas properties			—			565			221
	Unrealized loss on hedges			—			1,089			—
	Other			92			36			37

	Gross deferred tax assets			3,046			2,106			674
Deferred tax liabilities
	Oil and gas properties			1,699			—			—
	Property and equipment			127			771			—
	Impairments and abandonments			—			458			—
	Unrealized gain on hedges			971			—			—

	Gross deferred tax liabilities			2,797			1,229			—

	Net deferred tax asset			249			877			674
		Less valuation allowance		(249	)		(877	)		(674	)

Deferred tax asset			$	—		$	—		$	—

For income tax purposes at December 31, 2006, the Company has net operating loss carry-forwards of approximately $8,687,000, which expire in 2027. The Company has provided for a valuation allowance of $249,000 due to the uncertainty of realizing the tax benefits from its net deferred tax asset.

Note 13—Stock Option Plans

Options Under Employee Option Plans

The Company has adopted stock option plans containing both incentive and non-statutory stock options. All options allow for the purchase of common stock at prices not less than the fair market value of such stock at the date of grant. If the option holder owns more than 10% of the total combined voting power of all classes of the Company's stock, the exercise price cannot be less than 110% of the fair market value of such stock at the date of grant.

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Options granted under the plans become vested as directed by the Company's Board of Directors and generally expire seven or ten years after the date of grant, unless the option holder owns more than 10% of the total combined voting power of all classes of the Company's stock, in which case the non-statutory stock options must be exercised within five years of the date of grant. The Company granted 455,000, 320,000, and 260,000 options to employees under the plans during the years ended December 31, 2006, 2005 and 2004, respectively. At December 31, 2006, there were 1,687,730 shares available for grant under the plans.

The options granted all vest as follows:

Year 1	20	%
Year 2	30
Year 3	50

	100	%

In 2005, as part of the separation agreement with a former employee, the Board reduced the exercise price of this employee option from $4.00 per share to $3.32 per share. The Company calculated the fair value of the change in the option under the provisions of SFAS No. 123. As the revised option had a life of 1 month, the fair value was determined to be de minimis.

At December 31, 2006, the Company had unvested options to purchase 767,250 shares with a weighted average grant date fair value of $1.7 million. During the year ended December 31, 2006, the Company granted 455,000 employee options and recognized compensation expense of approximately $289,000. The Company will recognize compensation expense relating to non-vested options granted after January 1, 2006 of approximately $2.0 million ratably over the next 3 years.

The following table summarizes stock option activity for the year ended December 31, 2006:

	Number of Shares		Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Life	Aggregate Intrinsic value
Outstanding, December 31, 2005	645,000		$	4.56
Granted	455,000			9.57
Canceled or forfeited	(65,000	)		5.92

Outstanding, December 31, 2006	1,035,000		$	6.68	5.51	$	4,471,500

Exercisable at December 31, 2006	267,750		$	4.36	4.33	$	1,778,050

Weighted average fair value of options granted during the period			$	4.48

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The following table summarizes information about stock options outstanding at December 31, 2006:

	Options Outstanding		Options Exercisable
Exercise Prices	Number of shares Outstanding	Weighted Average Remaining Contractual Life	Number Exercisable	Weighted Average Exercise Price		Fair Value Determination
$4.00	162,500	3.7 years	147,500	$	4.00	Black-Scholes (minimum value)
$4.80	432,500	5.3 years	120,250	$	4.80	Black-Scholes (minimum value)
$5.20	112,500	6.0 years	—		—	Black-Scholes
$11.00	327,500	6.4 years	—		—	Black-Scholes

	1,035,000		267,750

Subsequent to December 31, 2006, the Company granted an additional 75,000 options with an exercise price of $11.00 per share. The options expire in seven years and vest based on the vesting terms noted above.

The following table summarizes stock option activity for the years ended December 31, 2006, 2005 and 2004:

	Number of Shares		Weighted Average Exercise Price Per Share
Outstanding, December 31, 2003	215,000		$	4.00
Granted	260,000			4.48
Canceled or forfeited	(37,500	)		4.00

Outstanding, December 31, 2004	437,500			4.24
Granted	320,000			4.80
Exercised	(50,000	)		3.32
Canceled or forfeited	(62,500	)		4.00

Outstanding, December 31, 2005	645,000			4.56
Granted	455,000			9.57
Canceled or forfeited	(65,000	)		5.92

Outstanding, December 31, 2006	1,035,000		$	6.68

Restricted Stock

The Company has an incentive program whereby grants of restricted stock have been awarded to members of the Board of Directors. Restrictions and vesting periods for the awards are determined at the discretion of the Board of Directors and are set forth in the award agreements.

Effective April 11, 2006, the Company granted, and effective May 1, 2006 the Company issued an aggregate of 36,360 shares of restricted common stock to its non-employee directors pursuant to the Company's stock incentive plan. During September 2006, 9,090 shares were forfeited leaving 27,270 restricted shares. The total fair value associated with the issued and outstanding restricted shares is

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$300,000 which the Company will recognize over a 3 year period. The restricted shares vest equally over a three year period. The Company recognized an expense of approximately $79,000 for the year ended December 31, 2006 based on the fair value of the vested shares during the period.

A summary of the status and activity of the restricted stock for the year ended December 31, 2006 is presented below.

	Shares		Weighted-Average Grant-Date Fair Value
Non-vested at beginning of period	—			—
Granted	36,360		$	11.00
Forfeited	(9,090	)	$	11.00
Vested	(6,575	)	$	11.00

Non-vested at end of period	20,695		$	11.00

As of December 31, 2006, the Company had $221,000 of unrecognized share-based compensation expense related to non-vested stock awards, which is expected to be amortized over the remaining period of 2.25 years.

Subsequent to December 31, 2006, the Company granted an additional 37,000 shares of restricted stock to key employees and non-employee directors.

Note 14—Redeemable Preferred Stock

Series A Redeemable Preferred Stock

The Company is authorized by the certificate of incorporation to issue up to 25,000,000 shares of preferred stock in one or more series, having rights senior to the shares of common stock. As of December 31, 2006, there are no shares of preferred stock issued and outstanding. All of the issued and outstanding shares of the Company's Series A Redeemable Preferred Stock Shares ("Preferred Stock") with a par value of $0.01 were redeemed with proceeds from the Company's April 2006 private placement. Shares of the Preferred Stock had a liquidation value of $100 per share and had preference to shares of the Company's common stock. Through the period ending on the seventh anniversary of the issue date at which time the dividends would have accrued at 12.5%, the Preferred Stock would have accrued dividends at the rate of 10.5% per annum compounded quarterly. The Preferred Stock had no stated maturity date. Holders of Preferred Stock had the right to vote on all matters voted on by holders of common stock.

Through June 30, 2009, Pinnacle would have had the right to redeem shares of the Preferred Stock at prices ranging from 110% to 100% of liquidation value ("Redemption Premium") depending on the date of redemption. In the event that there would have been a change in the control of the Company, or in an event of default, the holder of the Preferred Stock had the right (a "Mandatory Redemption Right") to require the Company to redeem all or any portion of its shares of the Preferred Stock at a price equal to 101% of the liquidation value, plus any accrued but unpaid dividends. Under EITF Topic D-98, if the Mandatory Redemption Right is outside the control of the Company, the Preferred Stock should be classified outside permanent equity. Management determined that the Mandatory Redemption Right was not under the control of the Company and therefore, the Preferred Stock was

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classified outside permanent equity in the accompanying balance sheet as of December 31, 2005. The Redemption Premium was not recognized by the Company until the triggering event became certain in accordance with EITF Topic D-98.

During the years ended December 31, 2006, 2005 and 2004, the Company issued 0, 150,000, and 120,000 shares of Preferred Stock, respectively for cash of $0, $14,700,000 and $11,760,000, respectively, net of offering costs paid to an affiliate of the preferred stockholders of $0, $300,000 and $240,000, respectively.

Until June 30, 2008, the Company had the option to pay accrued dividends on the Preferred Stock in additional shares of Preferred Stock ("PIK Dividends") in lieu of cash payments. For each additional share of Preferred Stock distributed as a PIK Dividend, Pinnacle delivered one Class A Warrant (as defined below). During the years ended December 31, 2006, 2005 and 2004, the Company issued 12,132, 36,007 and 22,495 respectively, of additional Preferred Stock in satisfaction of accrued dividends on the Preferred Stock. During 2005, the Company issued Class A Warrants exercisable into 530,725 shares of common stock in connection with PIK Dividends issued after June 30, 2005 with a fair value of $747,000 which was recorded as preferred dividends, in the accompanying statements of operations. In addition, the Company accrued additional dividends of $573,000 related to Class A Warrants exercisable into 303,300 shares of common stock that were issued in January 2006, along with the 12,132 shares of Preferred Stock issued in January 2006 noted above, as they related to payment of December 31, 2005 accrued dividends.

In April 2006, following the initial closing of the Company's private placement discussed above, the Company redeemed all of the outstanding shares of Series A Redeemable Preferred Stock with a portion of the proceeds from the private placement including the payment of accrued and unpaid dividends of $1.4 million. The difference between the redemption price and the carrying value of the Series A Redeemable Preferred Stock resulted in a $19.6 million redemption premium that was recorded as dividend expense in the accompanying statement of operations.

Note 15—Stockholders' Equity

Common Stock

As of December 31, 2006, there were 25,131,301 shares of common stock issuance and outstanding. The Board of Directors has authorized 100,000,000 shares of common stock with a par value of $0.01.

At formation, Pinnacle issued 3,750,000 shares of common stock, in equal portions to CCBM and RMG in exchange for the contribution of proved producing properties and undeveloped leasehold valued at $15,000,000.

Pinnacle issued an additional 1,250,000 shares of common stock to CSFB in exchange for a cash contribution of $5,000,000 less offering costs of $113,000.

In 2005, the Company received $167,000 from the exercise of employee stock options into 50,000 shares of common stock at $3.32 per share and Class B Warrants exercisable into 750,000 shares of common stock at $0.01 per share.

In April 2006, the Company completed a private placement, exempt from registration under the Securities Act, of 12,835,230 shares of common stock to qualified institutional buyers, non-U.S. persons and accredited investors at a price of $11.00 per share (gross proceeds of $141.2 million), or $10.23 per

F-26

share net of the initial purchaser's discount and placement fee. The gross proceeds were used in expending $11.3 million on placement fees and offering costs, $53.6 million for the redemption of all outstanding shares of Series A Redeemable Preferred Stock and all unpaid accrued dividends, $27.0 million for the acquisition of undeveloped assets in the Green River Basin, $16.3 million for the repurchase of 1,593,783 shares of common stock from the initial shareholders, and $33.0 million for future capital expenditures and general corporate purposes. The Company filed a Registration Statement on Form S-1 with the Securities and Exchange Commission on May 10, 2006.

Assignment of shares

On May 31, 2005, RMG assigned 65% and 35% of their common stock and options to U. S. Energy Corp. and Crested Corp., respectively. Both of these entities were affiliates of RMG.

Warrants

During the years ended December 31, 2005, 2004 and the period from June 23, 2003 (inception) through December 31, 2003, in connection with the issuance of Preferred Stock discussed above, the Company issued detachable warrants ("Class A Warrants") to acquire 3,750,000, 3,000,000 and 3,250,000 shares of common stock, respectively, at $4.00 per share and Class B Warrants to acquire 750,000, 0 and 0 shares of common stock, respectively, at $.01 per share. The Class A and Class B Warrants expire on June 30, 2013. The relative fair value of the Class A and Class B Warrants for the 2005, 2004 and 2003 issuances valued using the Black-Scholes valuation model was $5,197,000, $4,096,000 and $4,422,000, respectively, which was recorded as a reduction to the Preferred Stock at issuance in the accompany balance sheets and statements of redeemable preferred stock and stockholders' equity.

In addition, as noted above, the Company issued Class A Warrants exercisable for 530,725 shares of common stock during 2005 in connection with the issuance of Preferred Stock for PIK Dividends.

The following table summarizes warrant activity for the years ended December 31, 2006, 2005 and 2004:

	Number of Warrants		Weighted Average Price Per Share		Weighted Average Grant Date Fair Value Per Share
Outstanding, December 31, 2003	3,250,000		$	4.00
Granted	3,000,000			4.00	$	2.07
Outstanding, December 31, 2004	6,250,000			4.00
Granted	5,030,725			3.40		1.58
Exercised	(750,000	)		.01
Outstanding, December 31, 2005	10,530,725			4.00
Granted	303,300			4.00		2.49
Redemption	(10,834,025	)		4.00

Outstanding, December 31, 2006	—			—

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Options

In connection with the initial Contribution and Subscription Agreement on June 23, 2003, CSFB agreed to contribute a total of $30,000,000 ($25,000,000 in Preferred Stock purchases and $5,000,000 in common stock purchases). Pinnacle agreed to issue options to purchase a total of 2,500,000 shares of common stock at $4.00 per share to CCBM and RMG based on a formula with the numerator being cash contributed by CSFB to date and the denominator being the total $30,000,000 CSFB commitment. The options have an exercise escalation clause that separates the options into two tranches as follows:

•: Tranche A Options (1,250,000)—the options are 7 year options and with the exercise price escalating at 10% per annum
•: Tranche B Options (1,250,000)—the options are 7 year options and with the exercise price escalating at 20% per annum

On June 23, 2003, CSFB made total cash contributions of $18,000,000 ($13,000,000 for the purchase of Preferred Stock and $5,000,000 for the purchase of common stock). As a result, 60% of the Tranche A Options exercisable for 750,000 shares of common stock and 60% of the Tranche B Options exercisable for 750,000 shares of common stock were granted in equal amounts to CCBM and RMG.

On February 19, 2004, CSFB made total the final cash contribution of $12,000,000 under their commitment for the purchase of Preferred Stock. As a result, 40% of the Tranche A Options exercisable for 500,000 shares of common stock and 40% of the Tranche B Options exercisable for 500,000 shares of common stock were granted in equal amounts to CCBM and RMG. As CCBM and RMG acquired common stock at inception of the Company; therefore, the fair value of the escalating options was recorded as a reduction to the common stock on the grant date in the accompany balance sheets and statements of redeemable preferred stock and stockholders' equity.

The following table summarizes escalating stock option activity for the years ended December 31, 2006, 2005 and 2004:

	Number of Shares		Weighted Average Price Per Share (at grant(1))		Weighted Average Grant Date Fair Value Per Share
Outstanding, December 31, 2003	1,500,000		$	4.00
Granted	1,000,000			4.00	$	0.21

Outstanding, December 31, 2004	2,500,000			4.00
Granted	—			—		—

Outstanding, December 31, 2005	2,500,000			4.00
Redemption	(2,500,000	)		4.00

Outstanding, December 31, 2006	—			—

(1): Does not include the effects of the escalation clause.

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Note 16—Commitments and Contingencies

Operating Lease

Pinnacle had an office lease which was effective September 1, 2003. The lease was terminated when the Company purchased the building on August 26, 2005. Rent expense was $25,000 and $31,000 for the years ended December 31, 2005 and 2004, respectively.

Upon purchase of the building, Pinnacle was assigned the lease agreements for existing tenants in the building. The leases expire from May 2008 to December 2008. Future minimum lease income under noncancelable operating leases is as follows:


2007	$	59,000
2008		50,000

Total minimum lease payments	$	109,000

Gas Gathering Contracts

The Company has entered into gas gathering and compression agreements with service providers in order to compress and transport its gas to the point of sale. Compression agreements and gathering agreements are based on a fee per Mcf either compressed or gathered. The Company accounts for these fees as a marketing and transportation expense. The Company does not pay or charge marketing fees associated with the movement and sale of natural gas.

Employment Agreements

On June 23, 2003, the Company entered into employment agreements with two key executives. The employment agreements provide for aggregate annual base salaries of $300,000, aggregate annual performance bonuses of up to $200,000 and other perquisites commonly found in such agreements. In the event of termination of these executives without cause, as defined, such amounts would be payable to the executives for the period from the date of termination through the expiration of their respective agreements. The employment agreements expired in June 2006, but provided for an automatic extension such that the remaining term of the agreements will not be less than one year at any point in time.

On July 31, 2005, one of the key executives covered by an employment agreement resigned. Pursuant to his agreement, the employee was paid one year of base salary and received full benefits from Pinnacle for the period August 1, 2005 through July 31, 2006. As of December 31, 2006, the Chief Executive Officer and President of the Company is the only executive with an employment agreement.

Litigation

From time to time, the Company may be involved in litigation that arises in the ordinary course of business operations.

As of the date of this report, the Company is a defendant in litigation with Burning Rock Energy, LLC. The Company believes this litigation, if decided adversely to the Company, could reasonably be expected to have an adverse effect on its financial position, results of operations and cash flows. Burning Rock Energy, LLC and its affiliates ("the plaintiff") brought various contract and tort claims

F-29

against the Company relating to a like-kind exchange of approximately 1,000 acres of leased acreage in January 2004. The plaintiff claims that the leases transferred by the Company to Burning Rock did not terminate upon nonpayment of shut-in rentals and, further, that the Company trespassed by releasing from the original lessors the property originally transferred to Burning Rock under the exchange agreement. In February 2007, the court ruled against the Company with respect to whether the failure of Burning Rock to make shut-in royalty payments caused the leases to expire. Trial is currently scheduled to begin in April 2007 unless a settlement agreement is reached. The Company estimates that if a settlement cannot be reached and the outcome of this litigation is adverse to the Company, the Company could be required to forfeit any cash flows generated by the Company's development of the disputed leases and could lose its ownership in the disputed leases. The Company has accrued for $500,000 in losses as of December 31, 2006 in connection with this litigation.

The Company is also a defendant in two lawsuits with Diamond Cross Properties (the "plaintiff") in Montana whereby the plaintiff, among other claims, is seeking to permanently enjoin the State of Montana and its administrative bodies from issuing licenses or permits to drill on, or from authorizing the removal of ground water from under, the plaintiff's property. Based on the information available to date, the Company believes the claims are without merit and intends to defend the cases vigorously.

The Company has intervened in several federal environmental cases in Montana and Wyoming. The outcome of these cases could affect the ability of the Montana and Wyoming Bureaus of Land Management to approve plans of development and issue drilling permits on federal lands. In particular, the United States Court of Appeals for the Ninth Circuit has issued a temporary blanket injunction prohibiting the Montana Bureau of Land Management from approving any coal bed methane drilling permits on federal lands in the Power River Basin. The Company cannot predict how or when the courts will resolve these matters, although the Company expects that it will ultimately be successful in developing its federal leases.

Regulations

The Company's oil and gas operations are subject to various federal, state and local laws and regulations. The Company could incur significant expense to comply with the new or existing laws and non-compliance could have a material adverse effect on the Company's operations.

Environmental

The Company produces significant amounts of water from its wells. If future wells produce water of a lesser quality than allowed under state laws or if water is produced at rates greater than the Company can dispose of, the Company could incur additional costs to dispose of the water.

Note 17—Loss Per Share

For the years ended December 31, 2006, 2005 and 2004, all of the Company's common stock options and warrants were anti-dilutive as a result of the losses incurred. Therefore, the impact of 1,035,000, 13,676,200 and 9,187,500 potential shares of common stock equivalents outstanding as of December 31, 2006, 2005 and 2004, respectively, were not included in the calculation of diluted loss per share.

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Note 18—Major Customers

Following is a table summarizing the percentage of sales made to each purchaser that accounted for over 10% of the Company's gas sales for the years ended December 31, 2006, 2005 and 2004. The loss of any of these customers could have a material adverse effect on the Company's operations; however, the Company believes it would be able to locate other customers for the purchase of its production.

	December 31,
	2006		2005		2004
Enserco	66	%	76	%	74	%
Western Gas Resources	21	%	24	%	26	%
United Energy Trading	11	%	—		—
Other	2	%	—		—

	100	%	100	%	100	%

Note 19—Fair Value of Financial Instruments

The carrying values of the Company's cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, and revenue distributions payable represent the fair value due to the short-term nature of the accounts. Long-term debt at December 31, 2006 and 2005, with a carrying value of approximately $807,000 and $926,000, respectively, is estimated to approximate fair value as the terms are comparable to current market terms.

The fair value of the Company's derivatives are estimated using various models and assumptions related to the estimated terms of the instruments, volatility of the price of the Company's common stock, interest rates and the probability of conversion, among other items.

Note 20—Related Party Transactions

At formation, Pinnacle engaged Carrizo and RMG to provide transitional accounting, recordkeeping, treasury and similar services (the "Transition Services Agreements") until these activities could be performed on a stand alone basis. Pinnacle terminated the Transition Services Agreement with both companies in 2004 and Pinnacle incurred administrative and rental costs totaling $41,000.

Note 21—Subsequent Events

Effective January 1, 2007, the Company sold a 50% working interest in approximately 3,972 undeveloped acres in Wyoming.

Effective February 12, 2007, the Company entered into a new $100 million credit facility (the "New Credit Agreement") with The Royal Bank of Scotland ("RBS"), with an initial commitment of $27 million which permits borrowings up to the borrowing base as designated by the administrative agent. As of March 22, 2007, the borrowing base under the New Credit Facility was $22 million although the borrowing availability is less than the initial borrowing base due to covenant limitations. As of March 22, 2007, the borrowing availability was $16.7 million. The borrowing base is determined on a semi-annual basis and at such other times as may be requested by the borrower or administrative agent. Based on the Company's reserve report as of December 31, 2006, management expects that the borrowing base will be reduced below the initial level. Borrowing under the New Credit Agreement

F-31

bears interest either: (i) at a domestic bank rate plus an applicable margin between 0.25% and 1.25% per annum based on utilization or (ii) on a sliding scale from the one, two, three, or six month LIBOR rate plus 1.25% to 2.25% per annum based on utilization. The New Credit Agreement matures February 12, 2011 and replaces the Previous Credit Facility. The New Credit Agreement with RBS is collateralized by substantially all of the Company's producing assets. At March 22, 2007 the Company had $2.5 million outstanding under the New Credit Facility.

The credit agreement contains covenants that, among other things, restrict the Company's ability, subject to certain exceptions, to do the following:

•: incur liens;
•: incur debt;
•: make investments in other persons;
•: declare dividends or redeem or repurchase stock;
•: engage in mergers, acquisitions, consolidations and asset sales or amend our organizational documents;
•: enter into certain hedging arrangements;
•: amend material contracts; and
•: enter into related party transactions.

With regard to hedging arrangements, the credit facility provides that acceptable commodity hedging arrangements cannot be greater than 80 to 85% depending on the measurement date of the Company's monthly production from its hydrocarbon properties that are used in the borrowing base determination and that the fixed or floor price of the Company's hedging arrangements must be equal to or greater than the gas price used by the lenders in determining the borrowing base.

The credit agreement also requires that the Company satisfy certain affirmative covenants, meet certain financial tests, maintain certain financial ratios and make certain customary indemnifications to lenders and the administrative agent. The financial covenants include requirements to maintain: (i) earnings before income taxes, depreciation, depletion, amortization and accretions ("EBITDA") to cash interest expense of not less than 3.00 to 1.00, (ii) current ratio of not less than 1.00 to 1.00, (iii) total debt to annualized EBITDA of not more than 3.0 to 1.0, (iv) quarterly total senior debt to annualized EBITDA equal to or less than 3.0 to 1.0 until June 30, 2007 and 2.00 to 1.0 thereafter, and (v) total proved PV-10 value of reserves to total debt of at least 1.50 to 1.00. The credit agreement contains customary events of default, including, without limitation, payment defaults, covenant defaults, certain events of bankruptcy and insolvency, defaults in the payment of other material debt, judgment defaults, breaches of representations and warranties, loss of material permits and licenses and a change in control. In addition, the Company is required to eliminate scheduled title defects within periods specified on or prior to August 12, 2007, and the failure to eliminate all of these defects could result in an event of default.

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Note 22—Supplemental Oil and Gas Information

Estimated Proved Oil and Gas Reserves (Unaudited)

Proved oil and gas reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and gas that are ultimately recovered.

All of the Company's proved reserves are located in the United States. The following information about the Company's proved and proved developed oil and gas reserves was developed from reserve reports prepared by independent reserve engineers:

		Natural Gas (Mcf)
Proved reserves as of December 31, 2003		18,144,960
	Extension, discoveries and other additions	8,052,360
	Revisions of previous estimates	87,685
	Production	(1,507,652	)

Proved reserves as of December 31, 2004		24,777,353
	Purchases of reserves in place	249,510
	Extension, discoveries and other additions	3,214,834
	Revisions of previous estimates	1,003,745
	Production	(2,206,813	)

Proved reserves as of December 31, 2005		27,038,629
	Purchases of reserves in place	329,792
	Extension, discoveries and other additions	7,954,735
	Revisions of previous estimates(1)	(12,621,500	)
	Production	(2,413,130	)

Proved reserves as of December 31, 2006		20,288,526

Proved developed reserves as of
	December 31, 2004	7,430,984
	December 31, 2005	8,211,794
	December 31, 2006	7,879,271

(1): The revision in 2006 is primarily due to price the price decrease from December 31, 2005 of $7.715, based on the Rocky Mountain CIG Index, to December 31, 2006 price of $4.460.

Pinnacle's proved producing reserves are primarily from the Recluse area; purchases and extensions pertain exclusively to the Recluse area.

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Aggregate Capitalized Costs

Aggregate capitalized costs relating to the Company's oil and gas producing activities, and related accumulated depreciation, depletion, amortization and ceiling write-down are as follows:

		December 31,
		2006			2005
		(in thousands)
Proved oil and gas properties		$	55,179		$	39,537
Unproved oil and gas properties			85,094			31,280

	Total		140,273			70,817
Less accumulated depreciation, depletion, amortization and ceiling write-down			(15,191	)		(9,176	)

Net capitalized costs		$	125,082		$	61,641

Costs Incurred in Oil and Gas Producing Activities

Costs incurred in connection with the Company's oil and gas acquisition, exploration and development activities are as follows:

			December 31,
			2006		2005		2004
			(in thousands)
Property acquisition costs
	Proved		$	7,283	$	423	$	709
	Unproved			30,316		13,315		112

		Total property acquisition costs		37,599		13,738		821
	Exploration costs			23,498		4,938		—
	Development costs			7,496		5,114		14,109
	Asset retirement costs			863		656		128

Total costs			$	69,456	$	24,446	$	15,058

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Oil and Gas Operations

Aggregate results of operations in connection with the Company's gas producing activities are shown below:

	December 31,
	2006		2005		2004
	(in thousands)
Revenues	$	13,238	$	11,348	$	6,995
Production costs and taxes		6,153		5,000		3,501
Depreciation, depletion, amortization		6,015		5,224		3,163
Accretion of asset retirement obligations		162		70		53

Results of operations from producing activities (excluding corporate overhead and interest costs)	$	908	$	1,054	$	278

Depletion per MCF equivalent	$	2.49	$	2.37	$	2.10

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

Future gas sales and production and development costs have been estimated using prices and costs in effect at the end of the period indicated, except in those instances where the sale of natural gas is covered by contracts, as required by SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." SFAS No. 69 requires that net cash flow amounts be discounted at 10%. This information does not represent the fair market value of the Company's proved oil and gas reserves.

	December 31,
	2006			2005			2004
	(in thousands)
Future cash inflows	$	73,376		$	175,314		$	112,480
Future production costs		(25,975	)		(54,167	)		(38,941	)
Future development costs		(12,596	)		(36,754	)		(24,133	)
Future income tax expense		(2,950	)		(14,859	)		(6,402	)

Future cash flows		31,855			69,534			43,004
10% annual discount for estimated timing on cash flows		(9,471	)		(25,849	)		(14,596	)

Standardized measure of discounted future cash flows	$	22,384		$	43,685		$	28,408

The following table presents the average year-end market gas price used to compute future cash inflows for each period:

	December 31,
	2006		2005		2004
Weighted average gas price per Mcf	$	4.460	$	7.715	$	5.515

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Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the Company's proved oil and gas reserves at December 31, 2006, 2005 and 2004 assuming continuation of existing economic conditions.

The following reconciles the change in the standardized measure of discounted future net cash flow:

	December 31,
	2006			2005			2004
	(in thousands)
Beginning of period	$	43,685		$	28,408		$	18,729
Net change from purchases of minerals in place		760			394			—
Net change in sales and transfer prices, net of production costs		(40,437	)		(669	)		(95	)
Revision of previous quantity estimates		(7,018	)		2,634			1,322
Sales of oil and gas, net of production costs		(6,043	)		(7,524	)		(4,133	)
Development cost incurred, previously estimated		(8,044	)		(8,926	)		(4,998	)
Net change in income taxes		11,908			(7,276	)		(4,814	)
Changes in future development costs		21,719			34,058			20,937
Accretion of discount		5,854			2,586			1,460

End of period	$	22,384		$	43,685		$	28,408

Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to the Company's proved oil and gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Company's proved gas reserves.

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APPENDIX A

GLOSSARY OF CERTAIN NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and gas industry terms used in this prospectus.

Bcf. One billion cubic feet of natural gas.

British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

CBM. Coal bed methane.

CIG. Colorado Interstate Gas Company.

Completion. The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Enhancement. The method used to increase the deliverability of a well by pumping a liquid into a well under pressure to crack and prop open the formation.

Environmental Impact Statement (EIS). A detailed statement of the environmental effects of proposed actions and of alternative actions that is required prior to commencement of operations on federal lands.

Exploitation. Ordinarily considered to be a form of development within a known reservoir.

Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

Fee land. Private land, as compared to state or federal land.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. The section of rock from which gas is expected to be produced in commercial quantities.

Gathering system. Pipelines and other equipment used to move natural gas from the wellhead to the trunk or the main transmission lines of a pipeline system.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Highly volatile bituminous coal. Bituminous coal with a high concentration of methane gas.

Low-pressure gas gathering. Transportation to the inlet of third-party compression facilities.

Mcf. One thousand cubic feet of natural gas.

A-1

MMBtu. One million British Thermal Units.

MMcf. One million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

NYMEX. The New York Mercantile Exchange.

Operator. The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.

Perforation. The making of holes in casing and cement (if present) to allow formation fluids to enter the well bore.

Permeability. The ease of movement of water and/or gases through a soil material.

POD. Plans of development that are prepared and submitted to regulatory agencies for approval of drilling projects.

PV-10, or present value of estimated future net revenues. An estimate of the present value of the estimated future net revenues from proved gas reserves at the date indicated, after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the SEC's practice, to determine their "present value." The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed non-producing reserves. Proved developed reserves expected to be recovered from zones behind casings in existing wells.

Proved developed producing reserves. Proved developed reserves from completion intervals that are open and producing at the time of the estimate.

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Scf. Standard cubic feet of natural gas.

Shut-in well. An oil or gas well from which production has been stopped.

A-2

Spacing. The number of acres that one gas well will efficiently drain. State regulatory authorities establish the size of the spacing unit for each field.

Tcf. One trillion cubic feet of natural gas.

Telemetry. Data transferred by radiowave.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether or not such acreage contains proved reserves. Please see also "developed acreage."

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

A-3

PINNACLE GAS RESOURCES, INC.
LEASEHOLD POSITION
(as of December 31, 2006)

PINNACLE GAS RESOURCES, INC.

3,750,000 Shares of
Common Stock

Prospectus

, 2007

Book-Running Manager

FRIEDMAN BILLINGS RAMSEY

RBC CAPITAL MARKETS
A.G. EDWARDS
JOHNSON RICE & COMPANY L.L.C.

Until (25 days after the commencement of this offering), all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

PART II
INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION

The following table sets forth estimates of all expenses payable by the registrant in connection with the offering. The selling stockholders will not bear any portion of such expenses. All the amounts shown are estimates except for the registration fee, the NASD filing fee and the NASDAQ listing fee.

SEC registration fee		$	6,592
NASD filing fee			6,661
NASDAQ listing fee			100,000
Accounting fees and expenses			75,000
Legal fees and expenses			200,000
Engineer fees and expenses			20,000
Printing and engraving			105,000
Transfer agent fee			75,000
Miscellaneous fees and expenses			161,747

	Total	$	750,000

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS

Our second amended and restated certificate of incorporation provides that no director will be personally liable to the corporation or any of its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability for (i) any breach of the director's duty of loyalty to the corporation, (ii) acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of the law, (iii) the payment of dividends in violation of Section 174 of the General Corporation Law of the State of Delaware or (iv) any transaction from which the director derived an improper personal benefit. In addition, if the General Corporation Law of the State of Delaware is amended to authorize corporate action further eliminating or limiting the personal liability of directors, then the liability of the directors of the corporation shall be eliminated or limited to the fullest extent permitted by the General Corporation Law of the State of Delaware, as so amended.

Section 145 of the General Corporation Law of the State of Delaware provides that a corporation may indemnify directors and officers, as well as other employees and individuals, against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in connection with any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, other than a action by or in the right of the corporation, if they acted in good faith and in a manner they reasonably believed to be in, or not opposed to, the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of actions by or in the right of the corporation, except that indemnification extends only to expenses, including attorneys' fees, actually and reasonably incurred in connection with the defense or settlement of such actions and court approval is required for any indemnification if the person seeking indemnification has been found liable to the corporation. Section 145 also provides that any indemnification granted pursuant to Section 145 is not exclusive of other indemnification to which a person may be entitled under any bylaw, agreement, vote of stockholders or disinterested directors or otherwise.

Our second amended and restated certificate of incorporation and amended and restated bylaws contain indemnification rights for our directors and our officers. Specifically, they provide that we shall indemnify our officers and directors with respect to actions, suits or proceedings other than actions by

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or in the right of the corporation to the fullest extent authorized by the General Corporation Law of the State of Delaware. In addition, they provide that we shall pay expenses (including attorneys' fees) incurred by a director or officer in defending any civil, criminal, administrative or investigative action, suit or proceeding in advance of the final disposition of such action, suit or proceeding, subject to certain conditions.

We have entered into written indemnification agreements with our directors and executive officers. Pursuant to these agreements, we have agreed to indemnify our directors and officers with respect to actions, suits or proceedings, including actions by or in the right of the corporation, to the fullest extent authorized by applicable law and to advance all reasonable expenses incurred by a director or officer in connection with any action, suit, investigation or other proceeding, in each case subject to certain conditions. Under these agreements, if an officer or director makes a claim of indemnification, and if required by applicable law, either a majority of the directors not party to, or otherwise involved in, the proceeding for which indemnification is sought or independent legal counsel selected by the board of directors must review the relevant facts and make a determination whether such officer or director is entitled to indemnification.

Our second amended and restated certificate of incorporation and amended and restated bylaws provide that we may maintain insurance on behalf of our directors and officers against any liability asserted against them or incurred by them in their capacities as directors or officers or arising out of their status as such. We have obtained directors' and officers' insurance to insure our directors officers against certain liabilities.

The amended and restated securityholders agreement we entered into in February 2006 provides for the indemnification by the securityholders party to such agreement of our officers and directors against certain liabilities. The registration rights agreement and purchase/placement agreement we entered into in connection with our April 2006 private placement provide for the indemnification by the investors in that private placement of our officers and directors against certain liabilities.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES

In the three years preceding the filing of this registration statement, we have issued and sold the following securities that were not registered under the Securities Act. Except as otherwise noted, the numbers of shares of common stock referenced below have been adjusted to give effect to a 25-for-1 stock split in the form of a stock dividend that was effective March 31, 2006.

1. On June 23, 2003, in connection with our formation, CCBM, Inc., a subsidiary of Carrizo Oil & Gas, Inc., and Rocky Mountain Gas, Inc., a former subsidiary of U.S. Energy Corporation, contributed interests in approximately 81,000 gross (40,000 net) acres, including proved producing properties and undeveloped leaseholds, valued at $15.0 million. In exchange for such contribution, we issued 1,875,000 shares of our common stock and options to purchase an additional 1,250,000 shares of our common stock to each of CCBM and Rocky Mountain Gas. The shares of our common stock and options held by Rocky Mountain Gas were transferred to its affiliates, U.S. Energy and Crested Corp., in May 2005. Half of the options had an exercise price of $4.00 per share increased by 10% per annum, compounded quarterly, beginning on the date of issuance. The other half of the options had an exercise price of $4.00 per share increased by 20% per annum, compounded quarterly, beginning on the date of issuance. The issuance of these securities was exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

2. On June 23, 2003, also in connection with our formation, funds affiliated with DLJ Merchant Banking III, Inc., or DLJ Merchant Banking, contributed approximately $17.6 million cash in exchange for 1,250,000 shares of our common stock, Series A warrants for the purchase of

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3,250,000 additional shares of common stock at an exercise price of $4.00 per share, and 130,000 shares of our Series A Redeemable Preferred Stock. The issuance of these securities was exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

3. On February 19, 2004, we issued 120,000 shares of our Series A Redeemable Preferred Stock and Series A warrants for the purchase of 3,000,000 shares of our common stock at an exercise price of $4.00 per share to DLJ Merchant Banking in exchange for a capital contribution of approximately $11.8 million. On March 28, 2005, we issued 100,000 shares of our Series A Redeemable Preferred Stock, Series A warrants for the purchase of 2,500,000 shares of our common stock at an exercise price of $4.00 per share and Series B warrants for the purchase of 20,000 shares (pre-split; 500,000 shares post-split) of our common stock at an exercise price of $0.01 per share to DLJ Merchant Banking in exchange for a capital contribution of $9.8 million. On September 1, 2005, we issued 50,000 shares of our Series A Redeemable Preferred Stock, Series A warrants for the purchase of 1,250,000 shares of our common stock at an exercise price of $4.00 per share and Series B warrants for the purchase of 10,000 shares (pre-split; 250,000 shares post-split) of our common stock at an exercise price of $0.01 per share to DLJ Merchant Banking in exchange for a capital contribution of $4.9 million. The issuances of these securities were exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

4. On November 18, 2005, DLJ Merchant Banking exercised all of its Series B warrants to purchase an aggregate 30,000 shares (pre-split; 750,000 shares post-split) of our common stock for an aggregate exercise price of $300.00. The issuance of these securities was exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

5. On the following dates, we elected to pay dividends on our Series A Redeemable Preferred Stock in the form of in-kind dividends, resulting in the issuance to DLJ Merchant Banking of the number of additional shares of Series A Redeemable Preferred Stock stated below. Beginning on July 1, 2005, in connection with the payment of paid-in-kind dividends on our Series A Redeemable Preferred Stock, we issued to DLJ Merchant Banking additional Series A warrants to purchase the number of shares of our common stock stated below.

Date	Number of Shares of Series A Redeemable Preferred Stock Issued	Number of Shares of Common Stock Subject to Series A Warrants Issued
July 1, 2003	267	—
October 1, 2003	3,420	—
January 1, 2004	3,510	—
April 1, 2004	5,036	—
July 1, 2004	6,884	—
October 1, 2004	7,065	—
January 1, 2005	7,250	—
April 1, 2005	7,528	—
July 1, 2005	10,261	10,261
October 1, 2005	10,968	10,968
January 1, 2006	12,132	12,132

The issuances of these securities were exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

6. On the following dates, pursuant to our 2003 Stock Option Plan or Stock Incentive Plan, we issued to certain of our officers and employees options to purchase the number of shares of our common stock stated below at the exercise price stated below.

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Date		Number of Shares of Common Stock Subject to Options Granted	Exercise Price
June 23, 2003		190,000	$	4.00
December 31, 2003		25,000		4.00
March 5, 2004		60,000		4.00
March 10, 2004		25,000		4.00
May 24, 2004		25,000		4.80
June 23, 2004		75,000		4.80
October 17, 2004		25,000		4.80
January 3, 2005		37,500		4.80
January 14, 2005		37,500		4.80
February 1, 2005		12,500		4.80
July 15, 2005		75,000		4.80
December 9, 2005		170,000		4.80
January 1, 2006		100,000		5.20
February 16, 2006		12,500		5.20
June 1, 2006		297,500		11.00
August 8, 2006		45,000		11.00
February 12, 2007		75,000		11.00

	Total:	1,287,500

These option grants were exempt from the registration requirements of the Securities Act pursuant to Rule 701 under the Securities Act. Options to purchase a total of 273,500 shares of common stock have been subsequently cancelled due to the termination of the employment of grantees. On November 30, 2005, Gary W. Uhland, our former President, exercised options to purchase 50,000 shares of our common stock for an aggregate exercise price of $166,000.00. The issuance of these securities was exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

7. On April 11, 2006, (a) DLJ Merchant Banking exercised, in a cashless exchange, all of its Series A warrants to purchase an aggregate of 6,894,380 shares of our common stock, (b) CCBM, Inc. exercised, in a cashless exercise, all of its options to purchase an aggregate of 584,102 shares of our common stock and (c) U.S. Energy Corporation and Crested Corp. exercised, in a cashless exercise, all of their options to purchase an aggregate of 584,102 shares of our common stock. Because each of the foregoing transactions was cashless, we received no consideration for the issuance of the underlying shares of common stock. The issuances of these securities were exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

8. On April 11 and 12, 2006, we issued an aggregate of 11,790,397 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors in transactions exempt from the registration requirements of the Securities Act under Section 4(2), Rule 144A, Regulation S and/or Regulation D of the Securities Act. We received aggregate net proceeds before expenses of $120,615,761.31 and we paid Friedman, Billings, Ramsey & Co, Inc., who acted as initial purchaser and placement agent in these transactions, an initial purchaser's discount and placement fee of $9,078,605.69.

9. Effective April 11, 2006, we granted, and effective May 1, 2006, we issued an aggregate of 36,360 shares of restricted common stock to our non-employee directors pursuant to our Stock Incentive Plan. The issuance of these securities was exempt from the registration requirements of the Securities Act pursuant to Rule 701 under the Securities Act.

10. On April 26, 2006, we issued 1,044,833 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors in transactions exempt from the registration requirements of the Securities Act under Section 4(2), Rule 144A, Regulation S and/or

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Regulation D of the Securities Act. We received aggregate net proceeds before expenses of $10,688,641.59 and we paid Friedman, Billings, Ramsey & Co, Inc., who acted as initial purchaser and placement agent in these transactions, an initial purchaser's discount and placement fee of $804,521.41.

11. On February 12, 2007, we granted an aggregate of 37,000 shares of restricted stock to non-employee directors and certain employees pursuant to our Stock Incentive Plan. The issuance of these securities was exempt from the registration requirements of the Securities Act pursuant to Rule 701.

12. Effective March 26, 2007, we granted 10,000 shares of restricted stock to an employee pursuant to our Stock Incentive Plan. The issuance of these securities was exempt from the registration requirements of the Securities Act pursuant to Rule 701.

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ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibit Number		Description
*1.1	—	Form of Underwriting Agreement
3.1	—	Second Amended and Restated Certificate of Incorporation of Pinnacle Gas Resources, Inc. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (File No. 333-133983) filed May 10, 2006, Exhibit 3.1)
3.2	—	Amended and Restated Bylaws of Pinnacle Gas Resources, Inc. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (File No. 333-133983) filed May 10, 2006, Exhibit 3.2)
4.1	—	Amended and Restated Securityholders Agreement, dated February 16, 2006. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (File No. 333-133983) filed May 10, 2006, Exhibit 4.1)
4.2	—	Registration Rights Agreement, dated April 11, 2006. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (File No. 333-133983) filed May 10, 2006, Exhibit 4.2)
**5.1	—	Opinion of Andrews Kurth LLP as to the legality of the securities being registered.
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 Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.1)
**10.2	—	Credit Agreement, effective as of February 12, 2007, by and among Pinnacle Gas Resources, Inc., as Borrower, the Lenders from time to time party thereto, and The Royal Bank of Scotland plc, individually and as Administrative Agent
**10.3	—	Letter regarding Waiver and Amendment to Credit Agreement dated March 9, 2007.
10.4	—	Purchase and Sale Agreement, effective March 1, 2005, by and between Pennaco Energy, Inc. and Pinnacle Gas Resources, Inc. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.4)
10.5	—	Purchase and Sale Agreement, dated February 7, 2006, between Kennedy Oil and Pinnacle Gas Resources, Inc. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.5)
10.6	—	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 Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.6)
10.7	—	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 Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.7)
10.8	—	Midstream Transportation Agreement, effective December 1, 2003, by and between Pinnacle Gas Resources, Inc. and Clear Creek Natural Gas, LLC. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.8)

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10.9	—	Amended and Restated Stock Incentive Plan, effective February 16, 2006. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.9)
10.10	—	Form of Stock Option Agreement. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.10)
10.11	—	Form of Restricted Stock Grant Agreement. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.11)
10.12	—	Employment Agreement, dated June 23, 2003, between Pinnacle Gas Resources, Inc. and Peter G. Schoonmaker. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.12)
10.13	—	Form of Indemnification Agreement. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.13)
10.14	—	Purchase/Placement Agreement, dated March 31, 2006, between Pinnacle Gas Resources, Inc. and Friedman, Billings, & Ramsey & Co., Inc. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (File No. 333-133983) filed May 10 2006, Exhibit 10.18)
10.15	—	Summary of Director Compensation (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.15)
**10.16	—	Term Sheet and Summary regarding New Employment Agreement and Equity Awards for Peter G. Schoonmaker
**10.17	—	Term Sheet and Summary regarding New Employment Agreement and Equity Awards for Ronald T. Barnes
16.1	—	Letter regarding change in certifying accountant (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 16.1)
*23.1	—	Consent of Ehrhardt Keefe Steiner & Hottman PC
*23.2	—	Consent of Netherland, Sewell & Associates, Inc.
**23.3	—	Consent of Andrews Kurth LLP (included in Exhibit 5.1)
**24.1	—	Powers of Attorney

*: Filed herewith.
**: Previously filed.
***: To be filed by amendment.

ITEM 17. UNDERTAKINGS

(a) The undersigned registrant hereby undertakes:

(1) To provide to the underwriter(s) at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriter(s) to permit prompt delivery to each purchaser.

(2) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in

II-7

reliance upon Rule 430A and contained in the form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

(3) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(b) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the provisions described in Item 14 above, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

II-8

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement on Form S-1 to be signed on its behalf by the undersigned, thereunto duly authorized, in Sheridan, Wyoming on April 27, 2007.

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

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated.

Signature	Capacity	Date

/s/ PETER G. SCHOONMAKER Peter G. Schoonmaker	Chief Executive Officer, President and Director (principal executive officer)	April 27, 2007
/s/ RONALD T. BARNES Ronald T. Barnes	Chief Financial Officer, Senior Vice President and Secretary (principal financial officer and principal accounting officer)	April 27, 2007
* Steven A. Webster	Chairman of the Board of Directors
* Robert L. Cabes, Jr.	Director
* Jeffrey P. Gunst	Director
* S.P. Johnson, IV	Director
* Susan C. Schnabel	Director

*By:

/s/ RONALD T. BARNES

Ronald T. Barnes
Attorney-in-Fact

April 27, 2007

II-9

INDEX TO EXHIBITS

Exhibit Number		Description
*1.1	—	Form of Underwriting Agreement
3.1	—	Second Amended and Restated Certificate of Incorporation of Pinnacle Gas Resources, Inc. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (File No. 333-133983) filed May 10, 2006, Exhibit 3.1)
3.2	—	Amended and Restated Bylaws of Pinnacle Gas Resources, Inc. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (File No. 333-133983) filed May 10, 2006, Exhibit 3.2)
4.1	—	Amended and Restated Securityholders Agreement, dated February 16, 2006. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (File No. 333-133983) filed May 10, 2006, Exhibit 4.1)
4.2	—	Registration Rights Agreement, dated April 11, 2006. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (File No. 333-133983) filed May 10, 2006, Exhibit 4.2)
**5.1	—	Opinion of Andrews Kurth LLP as to the legality of the securities being registered.
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 Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.1)
**10.2	—	Credit Agreement, effective as of February 12, 2007, by and among Pinnacle Gas Resources, Inc., as Borrower, the Lenders from time to time party thereto, and the Royal Bank of Scotland plc, individually and as Administrative Agent
**10.3	—	Letter regarding Waiver and Amendment to Credit Agreement dated March 9, 2007
10.4	—	Purchase and Sale Agreement, effective March 1, 2005, by and between Pennaco Energy, Inc. and Pinnacle Gas Resources, Inc. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.4)
10.5	—	Purchase and Sale Agreement, dated February 7, 2006, between Kennedy Oil and Pinnacle Gas Resources, Inc. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.5)
10.6	—	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 Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.6)
10.7	—	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 Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.7)
10.8	—	Midstream Transportation Agreement, effective December 1, 2003, by and between Pinnacle Gas Resources, Inc. and Clear Creek Natural Gas, LLC. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.8)

10.9	—	Amended and Restated Stock Incentive Plan, effective February 16, 2006. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.9)
10.10	—	Form of Stock Option Agreement. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.10)
10.11	—	Form of Restricted Stock Grant Agreement. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.11)
10.12	—	Employment Agreement, dated June 23, 2003, between Pinnacle Gas Resources, Inc. and Peter G. Schoonmaker. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.12)
10.13	—	Form of Indemnification Agreement. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.13)
10.14	—	Purchase/Placement Agreement, dated March 31, 2006, between Pinnacle Gas Resources, Inc. and Friedman, Billings, & Ramsey & Co., Inc. (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (File No. 333-133983) filed May 10 2006, Exhibit 10.18)
10.15	—	Summary of Director Compensation (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 10.15)
**10.16	—	Term Sheet and Summary regarding New Employment Agreement and Equity Awards for Peter G. Schoonmaker
**10.17	—	Term Sheet and Summary regarding New Employment Agreement and Equity Awards for Ronald T. Barnes
16.1	—	Letter regarding change in certifying accountant (Incorporated by reference to Pinnacle Gas Resources, Inc.'s Registration Statement on Form S-1 (Amendment No. 1) (File No. 333-133983) filed September 15, 2006, Exhibit 16.1)
*23.1	—	Consent of Ehrhardt Keefe Steiner & Hottman PC
*23.2	—	Consent of Netherland, Sewell & Associates, Inc.
**23.3	—	Consent of Andrews Kurth LLP (included in Exhibit 5.1)
**24.1	—	Powers of Attorney

*: Filed herewith.
**: Previously filed.
***: To be filed by amendment.