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Bill Barrett 10-K 2008
Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

(Mark one)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007

or

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                                      to                                                      

Commission File No. 001-32367

BILL BARRETT CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware    80-0000545
(State or other jurisdiction
of incorporation or organization)
   (IRS Employer Identification No.)

 

1099 18th Street, Suite 2300

Denver, Colorado

   80202
(Address of principal executive offices)    (Zip Code)

(303) 293-9100

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

  

Name of each exchange on which registered

Common Stock, $.001 par value

   New York Stock Exchange

Series A Junior Participating Preferred Stock Purchase Rights

   New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨

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

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant as of June 30, 2007 was $1,232,782,371. For the purpose of the foregoing calculation only, the shares beneficially owned the Registrant’s directors, executive officers and the entity affiliated with a director that currently beneficially owns 10,081,278 shares of common stock have been assumed to be owned by affiliates.

 

* Without assuming that any of the issuer’s directors or executive officers, or the entity affiliated with a director that currently beneficially owns 10,081,278 shares of common stock, is an affiliate, the shares of which they are beneficial owners have been deemed to be owned by affiliates solely for this calculation.

As of February 15, 2008, the registrant had 44,790,978 outstanding shares of $.001 per share par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE:

The information required in Part III of this Annual Report on Form 10-K is incorporated by reference from the registrant’s definitive proxy statement for the registrant’s Annual Meeting of Stockholders to be held in May 2008 to be filed pursuant to Regulation 14A no later than 120 days after the end of the Registrant’s fiscal year ended December 31, 2007.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

      Page

Cautionary Note Regarding Forward-Looking Statements

   2

Part I

   3

Items 1 and 2. Business and Properties

   3

Glossary of Oil and Natural Gas Terms

   26

Item 1A. Risk Factors

   29

Item 1B. Unresolved Staff Comments

   39

Item 3. Legal Proceedings

   39

Item 4. Submission of Matters to a Vote of Security Holders

   40

Part II

   41

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

   41

Item 6. Selected Financial Data

   43

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

   45

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

   69

Item 8. Financial Statements and Supplementary Data

   70

Item 9. Changes in and Disagreements with Accountants and Financial Disclosure

   70

Item 9A. Controls and Procedures

   70

Report of Independent Registered Public Accounting Firm

   71

Item 9B. Other Information

   72

Part III

   72

Item 10. Directors, Executive Officers and Corporate Governance

   72

Item 11. Executive Compensation

   72

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

   72

Item 13. Certain Relationships and Related Transactions and Director Independence

   72

Item 14. Principal Accounting Fees and Services

   73

Part IV

   73

Item 15. Exhibits, Financial Statement Schedules

   73

Signatures

   76

Financial Statements—Index to Financial Statements

   F-1

Report of Independent Registered Public Accounting Firm

   F-2

Consolidated Balance Sheets

   F-3

Consolidated Statements of Operations

   F-4

Consolidated Statements of Stockholders’ Equity and Comprehensive Income

   F-5

Consolidated Statements of Cash Flows

   F-6

Notes to Consolidated Financial Statements

   F-7

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended, which are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements may include statements about our:

 

   

business and financial strategy;

 

   

identified drilling locations;

 

   

exploration and development drilling prospects, inventories, projects and programs;

 

   

natural gas and oil reserves;

 

   

ability to obtain permits and governmental approvals;

 

   

technology;

 

   

realized oil and natural gas prices;

 

   

production;

 

   

changing regulatory environment;

 

   

transportation and access to pipelines;

 

   

lease operating expenses and costs related to the acquisition and development of oil and gas properties;

 

   

availability and costs of drilling rigs and field services;

 

   

general and administrative costs, oilfield services costs and other expenses related to our business;

 

   

future operating results; and

 

   

plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this Annual Report on Form 10-K, are forward-looking statements. These forward-looking statements may be found in “Items 1 and 2. Business and Properties”, “Item 1A. Risk Factors”, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other sections of this Annual Report on Form 10-K. In some cases, you can identify forward-looking statements by terminology such as “may”, “could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”, “target”, “seek”, “objective”, or “continue”, the negative of such terms or other comparable terminology.

The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K. All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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PART I

Items 1 and 2. Business and Properties

BUSINESS

General

Bill Barrett Corporation (the “Company”, “we” or “us”) was formed in January 2002 and is incorporated in the State of Delaware. We explore for and develop oil and natural gas in the Rocky Mountain region of the United States. Our management has an extensive track record of growth and has significant expertise in unconventional and conventional reservoirs. Our strategy is to maximize stockholder value by leveraging our management team’s experience finding and developing oil and gas in the Rocky Mountain region to profitably grow our reserves and production, primarily through internally generated projects.

Our current strategy is to profitably grow our reserves and production by drilling low-risk repeatable development wells and finding developing gas and oil in the Rocky Mountain Region. In addition to low-risk development drilling, we plan to maintain our delineation and exploration progress on our extensive acreage portion of nearly 1.2 million net undeveloped acres. Our operating results reflect our exploration success and development growth on our properties.

We began active natural gas and oil operations in March 2002 with the acquisition of properties in the Wind River Basin. We acquired these properties from a subsidiary of the Williams Companies, which acquired these properties in connection with the Williams Companies’ acquisition of Barrett Resources Corporation in August 2001. Initially, we increased our activity level and the number of properties that we operate by acquiring a large inventory of undeveloped leasehold interests through federal and state sales as well as private purchases and trades. We have also acquired producing properties that had large undeveloped acreage positions associated with them. For example, in 2002, we completed two additional acquisitions of properties in the Uinta, Wind River, Powder River and Williston Basins; in early 2003, we completed an acquisition of largely undeveloped coalbed methane properties located in the Powder River Basin; in September 2004, we acquired interests in properties in the Piceance Basin in or around the Gibson Gulch field; and in May 2006, we added to our coalbed methane position in the Powder River Basin with our acquisition of CH4 Energy Corporation. In June 2007, we sold our Williston Basin properties.

The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the United States. Consequently, the Company currently reports a single industry segment. See “Financial Statements” and the notes to our consolidated financial statements for financial information about this industry segment. See definitions of oil and natural gas terms below at “—Glossary of Oil and Natural Gas Terms.”

 

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The following table provides information regarding our operations by basin.

 

Basin/Area

   State    Estimated Net
Proved
Reserves(1)
(Bcfe)
   December 2007
Average Daily
Net Production
(MMcfe/d)
   Net Producing
Wells
   Net
Undeveloped
Acreage
 

Uinta

   UT    243.6    75.6    99.4    166,212 (2)

Piceance

   CO    212.2    85.2    279.3    12,404  

Powder River

   WY    47.7    17.9    412.3    86,566  

Wind River

   WY    54.0    16.1    150.8    233,157  

Big Horn

   WY    —      0.1    1.5    77,327  

Paradox

   CO/UT    —      —      —      213,529  

Green River

   CO/WY    —      —      —      54,965  

Montana Overthrust

   MT    —      —      —      161,513  

Other(3)

      0.1    0.1    4.5    180,118 (3)
                        

Total

      557.6    195.0    947.8    1,185,791 (2)(3)
                        

 

(1) Our proved reserves were determined in accordance with SEC guidelines, using the market prices for natural gas (CIGRM price) and oil (WTI price) at December 31, 2007, which were $6.04 per MMBtu of natural gas and $92.50 per barrel of oil, without giving effect to hedging transactions. CIGRM refers to Colorado Interstate Gas Rocky Mountains price as quoted in Platt’s Inside FERC on the first business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. Our reserve estimates are based on a reserve report prepared by us and reviewed by our independent petroleum engineer. See “—Oil and Gas Data—Proved Reserves”.

 

(2) An additional 156,060 net undeveloped acres that are subject to drill-to-earn agreements are not included.

 

(3) Includes acreage associated with Denver-Julesburg Basin and Utah Hingeline properties that are held for sale.

Our Offices

We were founded in 2002 and incorporated in Delaware. Our principal executive offices are located at 1099 18th Street, Suite 2300, Denver, Colorado 80202, and our telephone number at that address is (303) 293-9100.

Business Strengths

We believe we have the following strengths:

 

   

Proven track record of efficient production and reserve growth through drilling activities. We have increased our production and proved reserves by double-digit percentage growth rates each year that we have been in existence. In 2002, we produced 6.6 Bcfe and, in 2007, we produced 61.2 Bcfe. Proved reserves grew from 119.1 Bcfe at year-end 2002 to 557.6 Bcfe at year-end 2007. Over this time period, we replaced 288% of production through drilling and 343% of production in total, including acquisitions. From inception through December 31, 2007, we participated in the drilling of 1,335 gross wells, achieving a 97% success rate.

 

   

Multi-year, low-risk, development drilling inventory. We have assembled an inventory of approximately 2,100 locations in our three core development areas in the Uinta, Piceance and Powder River Basins. The majority of these locations are in undeveloped areas or down-spacing programs where there are proved oil and gas reserves. We plan to allocate 80% or more of our capital budget to these low-risk development projects.

 

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High operatorship and control of capital program. Based on our year-end 2007 proved reserves, we had a weighted-average working interest of 94% and operatorship of 97%. High operatorship allows us to more effectively control operating costs, timing of development activities, application of technological enhancements, marketing of production and allocation of our capital budget. In addition, the timing of most of our capital expenditures is discretionary, which allows us a significant degree of flexibility to adjust the size and timing of our capital development.

 

   

Experienced management team. We believe our management team’s experience and expertise in the Rocky Mountains provides a distinct competitive advantage. Our 13 corporate officers average nearly 25 years of experience working in the industry. Our Chief Executive Officer, Chief Operating Officer, Chief Financial Officer and most other members of our management team worked together as managers or executives with Barrett Resources Corporation, a publicly-traded Rocky Mountain oil and gas company that was founded in 1980 and sold to the Williams Companies in 2001.

 

   

Expertise with unconventional resources. Approximately 70% of our properties are classified as unconventional resources, including basin-centered tight gas, CBM, fractured oil and shale gas plays. According to the Department of Energy’s Information Administration (“EIA”) 2008 Annual Energy Outlook, the EIA estimates that the lower 48 states unconventional natural gas resources will increase from 7.9 Tcf in 2005 to 9.3 Tcf in 2015.

 

   

Large undeveloped acreage position that provides potential future growth opportunities. We have established an asset base of 1,185,791 net undeveloped leasehold acres as of December 31, 2007, as well as an additional 156,060 net undeveloped acres that are subject to drill-to-earn agreements. We have multiple exploration projects in five different basins and along the overthrust belt. We typically allocate up to 20% of our capital towards exploration and delineation projects. These projects provide us with an inventory of future long-term growth potential.

 

   

Financial flexibility. As of December 31, 2007, we had $60.3 million in cash. At December 31, 2007, the outstanding balance under our $545.0 million credit facility was $274.0 million. We are committed to maintaining a conservative financial position to preserve our financial flexibility. We have hedged approximately 70% of our 2008 estimated production through swaps and collars to provide certainty for a portion of operating cash flows. We hedge natural gas prices at sales points in the Rocky Mountain and Mid-Continent regions, which mitigates the risk of basis differential to the Henry Hub index. We believe that our operating cash flow and available borrowing capacity under our credit facility provide us with the financial flexibility to pursue our currently planned development and exploration activities through 2008.

Business Strategy

Our strategy is to profitably grow our reserves and production by drilling low-risk, repeatable development wells and exploring for developing natural gas and oil in the Rocky Mountain region. The following are key components of that strategy:

 

   

Drive growth through development drilling. We expect to generate profitable, long-term reserve and production growth predominantly through repeatable, low-risk drilling on our development assets. We typically allocate 80% of our capital budget to our development projects. Our three core development areas have approximately 2,100 identified drilling locations as of December 31, 2007. In 2008, we plan to participate in the drilling of up to 500 gross wells across our operations.

 

   

Maximize operational control. We seek to operate our properties and maintain a high working interest. For the month of December 2007, we operated approximately 96% of our net production. We believe the ability to control our drilling inventory will provide us with the opportunity to efficiently allocate capital, manage resources, control operating and development costs and utilize our experience and knowledge of oilfield technologies.

 

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Focus on natural gas in the Rocky Mountain region. We intend to capitalize on the large estimated undeveloped natural gas and oil resource base in the Rocky Mountains. We believe the Rocky Mountains represent one of the few natural gas regions in North America with significant remaining growth potential and, according to the EIA, the Rocky Mountains contain 22% of the United States’ natural gas reserves. All of our production is from the Rocky Mountains and, for the month of December 2007, 96% consisted of natural gas. The Rockies Express-West pipeline, which began operations in January 2008, provides Rocky Mountain producers additional takeaway capacity and access to markets with improved pricing for selling natural gas. There is additional pipeline capacity proposed to be built from the region over the next several years as Rocky Mountain production increases.

 

   

Maintain financial flexibility and conservative financial position. Historically, we have funded our capital program with operating cash flow, debt, sales of equity and sales of interests in our properties. We continually monitor our debt levels to maintain a conservative financial position. Furthermore, we intend to continue hedging approximately 50-70% of our anticipated production on a 12-month forward basis to ensure a certain level of cash flow from operations.

 

   

Pursue high potential projects. In addition to our low-risk development projects, we believe our management team’s experience and expertise enable us to identify, evaluate and develop new natural gas and oil reservoirs. We have assembled several exploration projects that we believe may provide future potential, long-term, cost-effective drilling inventories. We have a team of geologists and geophysicists dedicated to generating new geologic concepts to provide us exposure to high-potential exploration projects. We typically add partners and enter into joint exploration agreements to reduce our capital risk and accelerate our exposure to potential reserves and production in these high potential projects.

 

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Areas of Operation

LOGO

Uinta Basin

The Uinta Basin, located in northeastern Utah, was our largest producing area for the year ended December 31, 2007. Our development operations are conducted in West Tavaputs, and we are currently testing offsets to attempt to delineate our Lake Canyon/Blacktail Ridge exploration discoveries. We also have a position in several exploration prospects in the Uinta Basin.

Key Statistics

 

   

Estimated proved reserves as of December 31, 2007—243.6 Bcfe.

 

   

Producing wells—We held interests in 112 gross producing wells as of December 31, 2007.

 

   

2007 production—25.8 Bcfe.

 

   

Acreage—We held 166,212 net undeveloped acres as of December 31, 2007, along with 156,060 net acres that are subject to drill-to-earn agreements.

 

   

Capital budget—In 2007, our capital expenditures were $166.4 million in the Uinta Basin area to drill 42 gross wells and install compression and gathering facilities. In our current 2008 capital budget, we plan to spend between $220 million and $240 million for drilling wells and installation of compression and gathering facilities.

West Tavaputs

We serve as operator of our interests in the West Tavaputs area. As of December 31, 2007, we had 550 drilling locations and 238.1 Bcfe of estimated proved reserves with a weighted average working interest of 98%. We are actively drilling our shallow program, which targets the gas-productive sands of the Wasatch and

 

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Mesaverde formations at depths down to 8,000 feet. We drilled 31 shallow wells in 2007 and plan to drill 51 shallow wells in 2008. The Wasatch and Mesaverde formations are currently being developed on 40-acre density following testing and analysis of 40-acre pilots in 2007.

With 3-D seismic, we have also identified two deeper structures targeting the Jurassic Navajo and Entrada and the Cretaceous Dakota formations at depths of nearly 15,000 feet. The eastern deep structure has been productive in five of seven wells drilled thus far; the other two are currently testing. We intend to drill up to five deep wells in 2008, including one test in the western deep structure in 2008.

Full development of the West Tavaputs area will require the completion of an Environmental Impact Statement, or EIS, which we initiated in February 2005 and which we expect to have a Record of Decision issued in the second half of 2008. See “Operations—Environmental Matters and Regulation.”

Our natural gas production at West Tavaputs is gathered and compressed by our facilities and delivered to markets on the Questar and its various subsidiaries’ pipeline systems. We recently entered into precedent agreements with Questar to subscribe for firm transportation arrangements on an expansion project as well as additional processing that we believe will provide adequate capability to move anticipated gas volumes from West Tavaputs.

Lake Canyon/Blacktail Ridge

Lake Canyon. In 2004, we and an industry partner entered into a drill-to-earn exploration and development agreement with the Ute Indian Tribe of the Uintah and Ouray Reservation, or the Ute Tribe and Ute Development Corporation to explore for and develop oil and natural gas on approximately 125,000 of their net undeveloped acres that are located in Duchesne and Wasatch Counties, Utah. Pursuant to this agreement, we have the right to earn up to a 75% working interest in the Wasatch formation (targeting oil at approximately 8,000 feet) and deeper horizons, for which we serve as operator, plus up to a 25% interest in shallower Green River formations. To earn these interests pursuant to this agreement, we and our partner are required to drill 13 deep wells and 21 shallow wells prior to December 31, 2009. The Ute Tribe has an option to participate in a 25% working interest in wells drilled pursuant to the agreement. Through 2006, we drilled three wells to the Wasatch formation, one of which was deemed a dry hole. We are in the process of drilling and testing our 2007 three-well program.

Blacktail Ridge. In December 2006, we entered into an exploration and development agreement with the Ute Tribe and the Ute Development Corporation to explore for and develop oil and natural gas on approximately 51,000 of their net undeveloped acres that are located in Duchesne County, Utah. Pursuant to this agreement, we serve as operator and have the right to earn a minimum of 50% working interest in all formations. To earn these interests pursuant to this agreement, we were required to drill a five Wasatch well program that began in 2007 followed by eight Wasatch wells per year thereafter. The Ute Tribe has an option to participate in up to 50% working interest in wells drilled pursuant to the agreement. We are in the process of drilling and testing our 2007 five-well commitment program.

Hook

Hook is a shale gas prospect in the southwestern portion of the Uinta Basin. In late 2007, we sold a 50% working interest in 29,531 net acres. In 2008, we plan to continue to acquire leasehold acreage and drill two exploration tests in these prospects.

 

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Piceance Basin

The Piceance Basin is located in northwestern Colorado. We began operations in the Gibson Gulch area of the Piceance Basin on September 1, 2004, with the purchase of producing and undeveloped properties from Calpine Corporation and Calpine Natural Gas L.P. for approximately $137.3 million.

Key Statistics

 

   

Estimated proved reserves as of December 31, 2007—212.2 Bcfe.

 

   

Producing wells—We held interests in 312 gross producing wells as of December 31, 2007.

 

   

2007 production—20.8 Bcfe.

 

   

Acreage—We held 12,404 net undeveloped acres as of December 31, 2007.

 

   

Capital budget—Our capital expenditures for 2007 were $180.3 million for participation in the drilling of 91 gross wells and to expand our compression and gathering facilities. In our current 2008 capital budget, we plan to spend between $230 million and $240 million for drilling wells, including on 10-acre and 20-acre density, and installation of additional compression and gathering facilities.

The Gibson Gulch area is a basin-centered gas play along the north side of the Divide Creek anticline at the eastern end of the Piceance Basin’s productive Mesaverde (Williams Fork) trend at depths of 7,500 feet. Through 2006, we drilled on a 20-acre well pattern. Beginning in 2007, we commenced drilling 10-acre pilot programs, and our 2007 year-end reserves include proved reserves associated with these pilots. Our natural gas production in this basin is currently gathered through our own gathering system and Encana’s and delivered to markets through a variety of pipelines including pipelines owned by Questar Pipeline Company, Northwest Pipeline, Colorado Interstate Gas Rocky Mountains (CIGRM) and Rockies Express Pipeline LLC. Our natural gas is processed at an Enterprise Products Partners L.P. plant in Meeker, CO.

Powder River Basin

The Powder River Basin is primarily located in northeastern Wyoming. Our operations are focused on the development drilling of coalbed methane wells, typically to a depth of 1,200 feet. Future development is primarily located in the Big George Coals.

Key Statistics

 

   

Estimated proved reserves as of December 31, 2007—47.7 Bcfe.

 

   

Producing wells—We held interests in 617 gross producing wells as of December 31, 2007.

 

   

2007 production—6.0 Bcfe.

 

   

Acreage—We held 86,566 net undeveloped acres as of December 31, 2007.

 

   

Capital budget—In 2007, our capital expenditures for the Powder River Basin were $39.3 million, which included participating in drilling 175 wells and acquisitions. In our current 2008 capital budget, we plan to spend between $35 million and $40 million for wells and facilities.

Coalbed methane wells typically first produce water in a process called dewatering. This process lowers reservoir pressure, allowing the gas to desorb from the coal and flow to the well bore. As the reservoir pressure declines, the wells begin producing methane gas at an increasing rate. As the wells mature, the production peaks, stabilizes and then begins declining. The average life of a coal bed well can range from five to 11 years depending on the coal seam.

 

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We have dedicated significant resources to managing regulatory and permitting matters in the Powder River Basin to achieve efficient processing of federal permits and resource management plans. See “—Operations—Environmental Matters and Regulation.”

Our natural gas production in this basin is gathered through our own gathering systems and, for a majority of our gas, delivered to markets through additional gathering and pipeline systems owned by Fort Union Gas Gathering, LLC and Thunder Creek Gas Services.

Wind River Basin

The Wind River Basin is located in central Wyoming. Our activities are concentrated primarily in the eastern Wind River Basin, along the greater Waltman Arch, where we generally serve as operator. In addition, we have a number of exploration projects, some of which are in areas of the Wind River Basin where we have no existing development operations. We are seeking industry partners to enter into joint exploration agreements, which may involve the sale of a portion of our interests and joint drilling obligations for certain exploration projects in the Wind River Basin.

Key Statistics

 

   

Estimated proved reserves as of December 31, 2007—54.0 Bcfe.

 

   

Producing wells—We held interests in 168 gross producing wells as of December 31, 2007.

 

   

2007 production—7.4 Bcfe.

 

   

Acreage—We held 233,157 net undeveloped acres as of December 31, 2007.

 

   

Capital budget—For 2007, our operations in the basin included recompletions and exploration drilling, and capital expenditures were $10.5 million. In our current 2008 capital budget, we plan to spend between $35 million and $40 million for drilling wells, recompletions and facilities.

Our natural gas production in this basin is gathered through our own gathering systems and delivered to markets through pipelines owned by Kinder Morgan Interstate (“KMI”) and CIGRM.

Cave Gulch

The Cave Gulch field is a structural-stratigraphic play along the Owl Creek Thrust at the northern end of the Waltman Arch. Our primary focus is on the productive overpressured deep Frontier, Muddy and Lakota formations at depths of up to 20,000 feet. In addition, we also produce from the shallower Lance and Fort Union formations.

We recently signed a joint exploration agreement with two industry partners for the drilling of at least two deep wells in 2008 on a partially promoted basis.

Paradox Basin

The Paradox Basin is located in southwestern Colorado and southeastern Utah, and is adjacent to the San Juan Basin of New Mexico and Colorado.

Key Statistics

 

   

Acreage—We held 213,529 net undeveloped acres as of December 31, 2007.

 

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Yellow Jacket

This prospect targets natural gas from a fractured shale reservoir at depths of 4,500 to 6,500 feet. Through 2007, we had drilled three exploratory vertical tests, of which one was deemed a dry hole and the other two are still being assessed. In 2008, we intend to drill at least two exploratory tests using horizontal well bores. We serve as operator in this area and have an average working interest of 46%.

Green Jacket

This prospect targets natural gas from a fractured shale reservoir at depths of 4,500 to 6,500 feet and is directly adjacent to our Yellow Jacket prospect. We plan to drill one vertical science well in 2008 and serve as operator in this area where we have a working interest of 100%.

Salt Flank

In the Salt Flank exploration prospect, we are targeting gas fields in stratigraphic and structural traps associated with salt diapirs. We plan to drill our first exploratory test on our Pine Ridge prospect in 2008, subject to selling down to an industry partner.

Montana Overthrust

We serve as operator and have a 50% working interest in this prospect in southwestern Montana. In 2007, we drilled two exploratory structural wells, which have been deemed dry holes below the Cody Shale interval. In 2008, we plan to conduct further tests on the Cody Shale.

Key Statistics

 

   

Acreage—We held 161,513 net undeveloped acres as of December 31, 2007.

Big Horn Basin

The Big Horn Basin is located in north central Wyoming. We are in the initial phases of an exploration project targeting both structural-stratigraphic and basin-centered tight gas plays.

Key Statistics

 

   

Acreage—We held 77,327 net undeveloped acres at December 31, 2007.

 

   

Capital budget—For 2007, our operations in the basin included a recompletion and seismic activity. In our current 2008 capital budget, we plan to spend up to $15 million for drilling exploratory tests.

Oil and Gas Data

Proved Reserves

The following table presents our estimated net proved natural gas and oil reserves and the present value of our estimated proved reserves at each of December 31, 2005, 2006 and 2007 based on reserve reports prepared by us and reviewed in their entirety by outside independent petroleum engineers. While we are not required by the SEC or accounting regulations or pronouncements to have our estimates independently reviewed, we are required by our revolving credit agreement with our lenders to have an independent engineering firm perform an annual review of our estimated reserves. All of our proved reserves included in our reserve reports are located in

 

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North America. Through December 31, 2006 Ryder Scott Company, L.P. reviewed all our reserve estimates except for our reserve estimates in the Powder River Basin, which were reviewed by Netherland, Sewell & Associates, Inc. (“NSAI”). As of December 31, 2007, NSAI reviewed all of our reserve estimates. When compared on a well-by-well or lease-by-lease basis, some of our estimates of net proved reserves are greater and some are less than the estimates of outside independent petroleum engineers. However, in aggregate, the independent petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC in connection with our registration statement for our initial public offering. The Standardized Measure shown in the table is not intended to represent the current market value of our estimated natural gas and oil reserves.

 

     As of December 31,
     2005    2006    2007

Proved Reserves:

        

Natural gas (Bcf)

     306.0      377.7      538.3

Oil (MMBbls)

     5.8      8.5      3.2

Total proved reserves (Bcfe)(1)

     341.0      428.4      557.6

Proved developed reserves (Bcfe)

     208.5      248.9      329.8

Standardized Measure (in millions)(2)

   $ 782.5    $ 529.3    $ 941.2

 

(1) Total does not add because of rounding.
(2) The Standardized Measure represents the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. In accordance with SFAS No. 69, our reserves and the future net revenues were determined using market prices for natural gas and oil, without giving effect to hedging transactions, at each of December 31, 2005, 2006 and 2007, which were $7.72 per MMBtu of gas and $61.04 per barrel of oil at December 31, 2005, $4.46 per MMBtu of gas and $61.06 per barrel of oil at December 31, 2006, and $6.04 per MMBtu of gas and $92.50 per barrel of oil at December 31, 2007. These prices were adjusted by lease for quality, transportation fees and regional price differences.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved undeveloped reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

The data in the above table represents estimates only. Oil and natural gas reserve engineering is an estimation of accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. See “ Item 1A. Risk Factors”.

At year-end 2007, we revised our proved reserves upward by 34.8 Bcfe, excluding pricing revisions, primarily as a result of adding increased density proved undeveloped locations in the West Tavaputs field and continued improved performance of wells drilled in the West Tavaputs and Piceance fields. We also revised our 2007 year-end proved reserves upward by 19.4 Bcfe, as year-end 2007 pricing was $6.04 per MMBtu and $92.50 per barrel of oil, relative to year-end 2006 at prices of $4.46 per MMBtu of gas and $61.06 per barrel of oil. These prices were adjusted by lease for quality, transportation fees and regional price differences. At year-end 2006, we revised our proved reserves upward by 12.4 Bcfe, excluding pricing revisions. This revision was primarily the result of increased performance of wells drilled during the last half of 2005 and the first half of 2006.

 

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During years 2004 and 2005, we participated in drilling 610 gross wells. Of the 610 wells, 158 were producing at less than 75% of the original forecast at December 31, 2005. The revision in forecast of these wells resulted in negative reserve revisions, excluding pricing effects, of 32 Bcfe and 24.7 Bcfe for year-end 2004 and 2005, respectively. These revisions resulted from estimating reserves with insufficient performance to define long term production profiles. In order to reduce the risk of negative reserve revisions, we place lower reserve values on new wells in areas of insufficient performance. We will only increase the reserve values after sufficient performance data is acquired.

We use our internal reserve estimates rather than the estimates from the independent engineering firms, because we believe that our reserve and operations engineers are more knowledgeable about the wells due to our continual analysis throughout the year as compared to the relatively short term analysis performed by the independent engineers. We use our internal reserve estimates on all properties regardless of the positive or negative variance to the independent engineers. If a variance greater than 10% occurs at the field level, it may suggest that a difference in methodology or evaluation techniques exists between us and the independent engineers. These differences are investigated by us and the independent engineers and discussed with the independent engineers to confirm that we used the proper methodologies and techniques in estimating reserves for these fields. These differences are not resolved to a specified tolerance at the field or property level.

For the year ended December 31, 2007, our outside independent engineer, NSAI, performed a well-by-well review of all of our properties and of our estimates of proved reserves and then provided us with their review report concerning our estimates. The review completed by NSAI, at our request, is a collective application of a series of procedures performed by NSAI. These review procedures may be the same or different from those review procedures performed by other independent engineering firms for other oil and gas companies. NSAI’s review report does not state the degree of their concurrence with the accuracy of our estimate for the proved reserves attributable to our interest in any specific basin, property or well.

For the year ended December 31, 2007, the estimate provided by NSAI was 4.5% above our reserve estimate. For the year ended December 31, 2006, in which the review was performed by two independent engineering firms, Ryder Scott Company, L.P.’s estimate was 6.2% below our reserve estimate, and NSAI’s estimate was 7.9% below our reserve estimate. For estimates of proved reserves at December 31, 2006, our outside independent reserve engineers arrived at reserve estimates that were greater than 10% above or below our own estimates for approximately 52% of our wells. This represents approximately 45% of the total proved reserves covered in the review reports. At the material property level, the independent engineer reserve estimates ranged between 21.3% above our internal reserve estimates to 2.4% below our estimates in the year-end 2006 reserve report. At December 31, 2005, at the material property level, the independent engineer reserve estimates ranged between 1.0% above our internal reserve estimates to 0.3% below our estimates. At December 31, 2004, at the material property level, the independent engineer reserve estimates ranged between 0.3% above our internal reserve estimates to 13.8% below our estimates.

The NSAI review process of our wells and reserve estimates is intended to determine the percent difference, in the aggregate, of our internal net proved reserve estimate and future net revenue (discounted 10%) and the reserve estimate and net revenue as determined by NSAI. The review process includes the following:

 

   

The NSAI engineer performs an independent decline curve analysis on proved producing wells based on production and pressure data. This data is provided to NSAI by us as well as other companies operating in the Powder River Basin.

 

   

The NSAI engineer may verify the production data with the public data.

 

   

The NSAI engineer uses his or her individual interpretation of the information and knowledge of the reservoir and area to make an independent analysis of proved producing reserves.

 

   

The NSAI technical staff will prepare independent maps and volumetric analyses on our properties and offsetting properties. They review our geologic maps, log data, core data, pertinent pressure data, test information and pertinent technical analyses, as well as data from offsetting producers.

 

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For the reserve estimates of proved non-producing and proved undeveloped locations, the NSAI engineer will estimate the potential for depletion by generating a potentiometric surface map, which relates directly to remaining gas-in-place, and analyzing this information with the maps generated earlier in the process.

 

   

The NSAI engineer will estimate the hydrocarbon recovery of the remaining gas-in-place based upon their knowledge and experience.

 

   

The NSAI engineer does not verify our working and net revenue interests or product price deductions.

 

   

The NSAI engineer does not verify our capital costs although they may ask for confirming information.

 

   

The NSAI engineer reviews 12 months of operating cost, revenue and pricing information that we provide.

 

   

The NSAI engineer confirms the oil and gas prices used for the SEC reserve estimate.

 

   

NSAI will confirm that their reserve estimate is within a 10% variance of our internal net reserve estimate and estimated future net revenue (discounted 10%), in the aggregate, before a review letter is issued.

 

   

The review by NSAI is not performed such that differences in reserves or revenue on a well level are resolved to any specific tolerance.

The reserve review letter provided by NSAI states that “in our opinion the estimates of Bill Barrett’s proved reserves and future revenue shown herein are, in the aggregate, reasonable” following an independent estimation of reserve quantities with economic parameters and other factual data provided by us and accepted by NSAI.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

From time to time, we engage NSAI and Ryder Scott to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. Neither NSAI nor Ryder Scott nor any of their respective employees has any interest in those properties, and the compensation for these engagements is not contingent on their estimates of reserves and future cash inflows for the subject properties. During 2007, we paid NSAI approximately $216,000 for reviewing our reserve estimates and $0 for other consulting services. During 2007, we did not employ Ryder Scott to review our reserves or provide other consulting services.

 

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Production and Price History

The following table sets forth information regarding net production of oil, natural gas and natural gas liquids and certain price and cost information for each of the periods indicated:

 

     Year Ended December 31,
     2005    2006    2007

Production Data:

        

Natural gas (MMcf)(1)

     36,287      47,928      57,678

Oil (MBbls)

     523      696      586

Combined volumes (MMcfe)

     39,425      52,104      61,194

Daily combined volumes (MMcfe/d)

     108.0      142.8      167.7

Average Prices(2):

        

Natural gas (per Mcf)

   $ 7.16    $ 6.40    $ 5.89

Oil (per Bbl)

     46.68      53.50      59.87

Combined (per Mcfe)

     7.21      6.60      6.13

Average Costs (per Mcfe):

        

Lease operating expense

   $ 0.50    $ 0.57    $ 0.68

Gathering and transportation expense

     0.30      0.30      0.38

Production tax expense

     0.85      0.50      0.37

Depreciation, depletion and amortization(3)

     2.27      2.69      2.87

General and administrative(4)

     0.62      0.53      0.52

 

(1) Production of natural gas liquids is included in natural gas revenues and production.

 

(2) Includes the effects of hedging transactions, which reduced average natural gas prices by $0.57 per Mcf in 2005, and increased average natural gas prices by $0.46 and $1.52 per Mcf in 2006 and 2007, respectively, and reduced average oil prices by $7.01, $5.90, and $1.31 per Bbl in 2005, 2006 and 2007, respectively.

 

(3) The depreciation, depletion and amortization per Mcfe for the years ended December 31, 2006 and 2007 excludes the production associated with our properties held for sale throughout the year in the Uinta, Williston and DJ Basins, as these properties were excluded from amortization during the appropriate periods in which these properties were classified as held for sale.

 

(4) General and administrative expense presented herein excludes non-cash stock-based compensation of $3.2 million, $6.5 million and $10.2 million for the years ended December 31, 2005, 2006 and 2007, respectively, which equates to a reduction to G&A of $0.08 per Mcfe, $0.12 per Mcfe and $0.17 per Mcfe, respectively. Non-cash stock-based compensation is combined with general and administrative expense for a total of $27.8 million, $34.2 million and $42.2 million for the years ended December 31, 2005, 2006 and 2007, respectively, in the Consolidated Statement of Operations. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, who may have higher or lower costs associated with equity grants.

 

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Productive Wells

The following table sets forth information at December 31, 2007 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

 

     Gas    Oil
      Gross
Wells
   Net
Wells
   Gross
Wells
   Net
Wells

Basin

           

Uinta

   109.0    97.3    3.0    2.1

Piceance

   312.0    279.3    —      —  

Powder River

   570.0    403.7    47.0    8.5

Wind River

   168.0    150.9    —      —  

Other

   12.0    6.0    —      —  
                   

Total

   1,171.0    937.2    50.0    10.6
                   

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2007 relating to our leasehold acreage.

 

     Developed Acreage(1)    Undeveloped Acreage(2)  
         Gross        Net    Gross    Net  

Basin/Area

           

Uinta

   14,631    13,337    229,119    166,212 (3)

Piceance

   4,767    3,837    15,136    12,404  

Powder River

   63,519    43,351    133,794    86,566  

Wind River

   6,911    5,293    366,252    233,157  

Big Horn

   801    374    181,419    77,327  

Paradox

   —      —      360,427    213,529  

Green River

   —      —      62,556    54,965  

Montana Overthrust

   —      —      377,227    161,513  

Denver-Julesburg(4)

   1,974    987    314,803    146,086  

Utah Hingeline(4)

   —      —      26,417    18,096  

Other

   1,241    904    30,131    15,936  
                     

Total

   93,844    68,083    2,097,281    1,185,791 (3)
                     

 

(1) Developed acres are acres spaced or assigned to productive wells.

 

(2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

 

(3) An additional 156,060 net undeveloped acres that are subject to drill-to-earn agreements are not included.

 

(4) These properties are held for sale as of December 31, 2007. Subsequent to December 31, 2007, we sold 249,700 gross and 120,019 net acres.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. We generally have been able

 

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to obtain extensions of the primary terms of our federal leases for the period in which we have been unable to obtain drilling permits due to a pending Environmental Assessment, Environmental Impact Statement or related legal challenge. The following table sets forth, as of December 31, 2007, the expiration periods of the gross and net acres that are subject to leases summarized in the above table of undeveloped acreage.

 

     Undeveloped Acres
Expiring

Twelve Months Ending:

   Gross    Net

December 31, 2008

   301,226    139,089

December 31, 2009

   152,584    73,064

December 31, 2010

   266,927    129,031

December 31, 2011

   260,982    150,410

December 31, 2012 and later(1)

   1,115,562    694,197
         

Total

   2,097,281    1,185,791
         

 

(1) Includes 393,524 gross and 226,120 net undeveloped acres held by production from other leasehold acreage or held by federal units.

Drilling Results

The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found or economic value. Productive wells are wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

 

     Year Ended
December 31,
2005
   Year Ended
December 31,
2006
   Year Ended
December 31,
2007(1)
     Gross    Net    Gross    Net    Gross    Net

Development

                 

Productive

   98.0    82.3    48.0    41.1    54.0    46.6

Dry

   3.0    3.0    —      —      1.0    0.5

Exploratory

                 

Productive

   103.0    84.9    121.0    85.2    177.0    136.4

Dry

   5.0    3.3    3.0    1.6    6.0    2.5
                             

Total

                 

Productive

   201.0    167.2    169.0    126.3    231.0    183.0

Dry

   8.0    6.3    3.0    1.6    7.0    3.0

 

(1) The determination of development and exploratory wells shown in the table above is based on an interpretation of the definitions of those terms in Rule 4-10(a) of Regulation S-X, which governs financial disclosures in filings with the SEC, that includes as development wells only those wells drilled on drilling locations to which proved undeveloped reserves have been attributed at the time at which drilling of the wells commenced and in which all other wells are considered exploratory. We also are providing information with respect to drilling results in which development wells include not only wells drilled on PUD locations but also wells drilled in a proved area in which proved reserves have been attributed by our reservoir engineers as of the time of commencement of drilling. On this basis, during 2007, we completed 227 gross (180.4 net) productive and 1 gross (0.5 net) dry development wells and 4 gross (2.6 net) productive and 6 gross (2.5 net) dry exploratory wells.

From our inception through December 31, 2007, we participated in drilling 1,335 gross wells, of which 936 were completed as producing; 363 were in process of completing or dewatering; and 36 were dry holes. Also during that time, we recompleted 40 gross wells, which are not included in the totals above.

 

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Operations

General

In general, we serve as operator of wells in which we have a greater than 50% interest. In addition, we seek to be operator of wells in which we have lesser interests. As operator, we obtain regulatory authorizations, design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on the properties we operate. Independent contractors engaged by us provide all of the equipment and personnel associated with these activities. We employ drilling, production and reservoir engineers and geologists and other specialists who work to improve production rates, increase reserves and lower the cost of operating our natural gas and oil properties.

Marketing and Customers

We market the majority of the natural gas and oil production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell the majority of our production to a variety of purchasers under gas purchase contracts with daily, monthly, seasonal, annual or multi-year terms, all at market prices. Purchasers include pipelines, processors, marketing companies, local distribution companies, and end users. We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. However, based on the current demand for natural gas and oil and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations.

We enter into hedging transactions with unaffiliated third parties for portions of our natural gas production to achieve more predictable cash flows and to reduce our exposure to fluctuations in gas prices. For a more detailed discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview” and “—Quantitative and Qualitative Disclosures About Market Risk”.

 

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Our natural gas and oil are transported through our own and third party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas shippers. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes. In order to meet pipeline specifications, we are required, in some cases, to process our gas before we can transport it. We typically contract with third parties in the Piceance, Wind River and Uinta Basins to process our natural gas. We also may enter into firm sales agreements to ensure that we are selling to a purchaser who has contracted for pipeline capacity. These agreements are subject to the limitations discussed above in this paragraph. The following table sets forth information about material long-term (greater than one year from December 31, 2007) firm transportation contracts for pipeline capacity and firm processing contracts, both of which typically require a demand charge and firm sales contracts.

 

Type of Arrangement

  

Pipeline System / Location

  

Gross Deliveries

(MMBtu/d)

  

          Term          

Firm Sales

   Questar Pipeline    10,000      4/06 – 12/09

Firm Sales

   Questar Pipeline      5,000        4/06 – 3/09

Firm Sales

   Questar Pipeline      8,500        5/05 – 3/10

Firm Sales

   KMI    10,000    11/07 – 12/08

Firm Transport

   WIC Medicine Bow      5,000        6/08 – 3/14

Firm Transport

   WIC Medicine Bow    30,000      11/07 – 3/15

Firm Transport

   Questar Pipeline    12,000    11/05 – 10/15

Firm Transport

   Questar Pipeline    25,000      1/07 – 12/16

Firm Transport

   Cheyenne Plains      9,000        2/05 – 4/17

Firm Transport

   Cheyenne Plains      5,000        5/17 – 4/18

Firm Transport

   Questar Pipeline    25,000    11/07 – 10/17

Firm Transport

   Rockies Express    25,000        1/08 – 6/19

Firm Transport

   Questar Pipeline    15,000        1/08 – 6/09

Firm Transport

   Questar Gas    70,000        4/08 – 1/17

Firm Transport

   Questar Pipeline    11,000        4/07 – 9/08

Firm Processing

   Questar Pipeline    50,000        8/06 – 8/16

Firm Processing

   Questar Gas    50,000      4/07 – 12/08

Hedging Activities

We have an active commodity hedging program to mitigate the risks of the volatile prices of natural gas and oil. Typically, we intend to be approximately 50-70% hedged on a forward 12-month basis using a combination of swaps, cashless collars and other financial derivative instruments with creditworthy counterparties. For additional information on our hedging activities, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”

Competition

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

 

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our financial or human resources permit. In addition, these companies have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or integrated competitors are better able to absorb the burden of existing, and any changes to, federal, state, local and Native American tribal laws and regulations more easily than we can, which would adversely affect our competitive position. 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. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work for significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing natural gas and oil leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our natural gas and oil properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of our properties or affect of our carrying value of the properties.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the spring and fall months and increases during the summer and 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 can 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.

Environmental Matters and Regulation

General. Our operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Our operations are subject to the same environmental laws and regulations as other companies in the oil and gas exploration and production industry. These laws and regulations may:

 

   

require the acquisition of various permits before drilling commences;

 

   

require the installation of expensive pollution control equipment;

 

   

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

 

   

limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

 

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require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

 

   

impose substantial liabilities for pollution resulting from our operations;

 

   

with respect to operations affecting federal lands or leases, require time consuming environmental analysis; and

 

   

expose us to litigation by environmental and other special interest groups.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or more stringent and costly waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of more stringent future laws and regulations at this time. For the year ended December 31, 2007, we did not incur any material capital expenditures for remediation or retrofit of pollution control equipment at any of our facilities.

The environmental laws and regulations which could have a material impact on the oil and natural gas exploration and production industry are as follows:

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental assessment, or EA, prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study, or EIS, that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes affect oil and gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and on the disposal of non-hazardous wastes. Under the auspices of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil, natural gas, or geothermal energy constitute “solid wastes,” which are regulated under the less stringent, non-hazardous waste provisions, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes”.

We believe that we are in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we held all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative

 

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or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site, or site where the release occurred, and companies that disposed or arranged for the disposal of the hazardous substance. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such “hazardous substances” have been deposited.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These prescriptions also prohibit the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with the terms thereof. Obtaining permits has the potential to delay the development of oil and natural gas projects.

Air Emissions. The Federal Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to remain in compliance. These regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining permits has the potential to delay the development of oil and natural gas projects.

Other Laws and Regulation. The Kyoto Protocol to the United Nations Framework Convention on Climate Change went into effect in February 2005 and requires all industrialized nations that ratified the Protocol to reduce or limit greenhouse gas emissions to a specified level by 2012. The United States has not ratified the Protocol, and the U.S. Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there is increasing public pressure from environmental groups and some states for the United States to develop a national program for regulating greenhouse gas emissions, and several states have already adopted regulations or announced initiatives focused on decreasing or stabilizing greenhouse gas emissions associated with industrial activity, primarily carbon dioxide emissions from power plants. The oil and natural gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could impact our future operations. Our operations are not adversely impacted by current state and local climate

 

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change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Legislation continues to be introduced in Congress, and development of regulations continues in the Department of Homeland Security and other agencies, concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production. Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribes also regulate one or more of the following:

 

   

the location of wells;

 

   

the method of drilling and casing wells;

 

   

the rates of production or “allowables”;

 

   

the surface use and restoration of properties upon which wells are drilled and other third parties;

 

   

the plugging and abandoning of wells; and

 

   

notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Natural Gas Sales Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission, or FERC, has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales”, which include all of our sales of our own production.

 

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FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes might have on our natural gas-related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering services, which occurs upstream of jurisdictional transmission services, is regulated by state agencies. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point-of-sale locations.

Operations on Native American Reservations. A portion of our leases in the Uinta Basin are, and some of our future leases in this and other areas may be, regulated by Native American tribes. In addition to regulation by various federal, state and local agencies and authorities, an entirely separate and distinct set of laws and regulations applies to lessees, operators and other parties within the boundaries of Native American reservations. Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, together with each Native American tribe, promulgate and enforce regulations pertaining to oil and gas operations on Native American reservations. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards and numerous other matters.

Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs. However, each Native American tribe is a sovereign nation and has the right to enforce certain other laws and regulations entirely independent from federal, state and local statutes and regulations, as long as they do not supersede or conflict with such federal statutes. These tribal laws and regulations include various fees, taxes, requirements to employ Native American tribal members and numerous other conditions that apply to lessees, operators and contractors conducting operations within the boundaries of a Native American reservation. Further, lessees and operators within a Native American reservation are subject to the Native American tribal court system, unless there is a specific waiver of sovereign immunity by the Native American tribe allowing resolution of disputes between the Native American tribe and those lessees or operators to occur in federal or state court.

Therefore, we are subject to various laws and regulations pertaining to Native American tribal surface ownership, Native American oil and gas leases, fees, taxes and other burdens, obligations and issues unique to oil and gas ownership and operations within Native American reservations. One or more of these requirements may increase our costs of doing business on Native American tribal lands and have an impact on the economic viability of any well or project on those lands.

Employees

As of February 15, 2008, we had 252 full time employees. Of our 252 full time employees, 156 work in our Denver office and 96 are in our district and field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees is represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are good.

 

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Offices

As of December 31, 2007, we leased approximately 62,633 square feet of office space in Denver, Colorado at 1099 18th Street, where our principal offices are located. The lease for our Denver office expires in March 2011. We also own field offices in Waltman, Wyoming, Roosevelt, Utah and Silt, Colorado, and lease a field office in Gillette, Wyoming. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.

Website and Code of Business Conduct and Ethics

Our website address is http://www.billbarrettcorp.com. We make available free of charge through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC at http://www.sec.gov. Additionally, our Code of Business Conduct and Ethics, which includes our code of ethics for senior financial management, Corporate Governance Guidelines and the charters of our Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee are posted on our website at http://www.billbarrettcorp.com and are available in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our principal office at 1099 18th Street, Suite 2300, Denver, Colorado 80202. We intend to disclose on our website any amendments or waivers to our Code of Business Conduct and Ethics that are required to be disclosed pursuant to Item 5.05 of Form 8-K. This Annual Report on Form 10-K and our website contain information provided by other sources that we believe are reliable. We cannot assure you that the information obtained from other sources is accurate or complete. No information on our website is incorporated by reference herein.

Annual CEO Certification

As required by New York Stock Exchange rules, on June 8, 2007 we submitted an annual certification signed by our Chief Executive Officer certifying that he was not aware of any violation by us of New York Stock Exchange corporate governance listing standards as of the date of the certification.

 

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and gas industry:

3C 3-D seismic. A three dimensional seismic survey employing three-component geophones. These multi-component geophones record three orthogonal components of ground motion and provide information about shear waves that are unobtainable by conventional 3-D seismic surveys.

3-D seismic. Acoustical reflection data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Basin-centered gas. A regional, abnormally pressured, gas-saturated accumulation in low-permeability reservoirs lacking a down-dip water contact.

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Coalbed methane (CBM). Natural gas formed as a byproduct of the coal formation process, which is trapped in coal seams and produced by nontraditional means.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Curtailments. The delivery of gas below contract entitlements due to system restrictions.

Desorb. A physical process whereby gas molecules are liberated from a host rock, such as a shale or coal reservoir, when the formation pressure is reduced.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Down-dip. The occurrence of a formation at a lower elevation than a nearby area.

Drill-to-earn. The process of earning an interest in leasehold acreage by drilling a well pursuant to a farm-in, exploration, or other agreement.

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.

Environmental Assessment (EA). An environmental assessment, a study that can be required pursuant to federal law prior to drilling a well.

 

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Environmental Impact Statement (EIS). An environmental impact statement, a more detailed study that can be required pursuant to federal law of the potential direct, indirect and cumulative impacts of a project that may be made available for public review and comment.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir, or to extend a known reservoir.

Farm-in or farm-out. An agreement under which the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

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.

Fractured oil. A type of hydrocarbon accumulation where the storage and movement of oil in the reservoir is strongly controlled by natural fractures.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Identified drilling locations. Total gross locations specifically identified and scheduled by management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. Thousand cubic feet of natural gas.

Mcf/d. Mcf per day.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBbls. Million barrels of crude oil or other liquid hydrocarbons.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcf/d. MMcf per day.

MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMcfe/d. MMcfe per day.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

 

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Overpressured. A subsurface formation that exerts an abnormally high formation pressure on a wellbore drilled into it.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Potentiometric surface. An imaginary surface defined by the level to which water in an aquifer would rise due to the natural pressure in the rocks.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves (PDP). Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves (PUD). 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.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Salt diapir. A generally long and linear geologic structure formed from the emplacement of a large column of salt into pre-existing rock layers.

Standardized Measure. The present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.

Stratigraphic play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.

Tcf. Trillion cubic feet (of gas)

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 natural gas and oil regardless of whether such acreage contains proved reserves.

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 and requires the owner to pay a share of the costs of drilling and production operations.

 

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Item 1A. Risk Factors

Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect our company.

Risks Related to the Oil and Natural Gas Industry and Our Business

Oil and natural gas prices are volatile and a decline in oil and natural gas prices can significantly affect our financial results and impede our growth.

Our revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

   

the domestic and foreign supply of oil and natural gas;

 

   

the price of foreign imports;

 

   

overall domestic and global economic conditions;

 

   

political and economic conditions in oil producing countries, including the Middle East and South America;

 

   

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

   

the level of consumer product demand;

 

   

weather conditions;

 

   

technological advances affecting energy consumption;

 

   

domestic and foreign governmental regulations;

 

   

proximity and capacity of oil and gas pipelines and other transportation facilities;

 

   

the price and availability of alternative fuels; and

 

   

variations between product prices at sales points and applicable index prices.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration or development results deteriorate, successful efforts accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

 

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We have incurred losses from operations for various periods since our inception and may do so in the future.

We incurred net losses of $5.0 million, $4.0 million and $5.3 million in the period from January 7, 2002 (inception) through December 31, 2002 and in the years ended December 31, 2003 and 2004, respectively. Our development of and participation in an increasingly larger number of prospects has required and will continue to require substantial capital expenditures. The uncertainty and factors described throughout this section may impede our ability to economically find, develop, exploit and acquire natural gas and oil reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these assumptions will materially affect the quantities of our reserves.

No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect. At year-end 2004 and 2005, we revised our reserves downward by 32 Bcfe and 24.7 Bcfe, excluding pricing revisions, respectively. We participated in drilling 798 gross wells from inception through December 31, 2005. Of the 798 wells, 219 were producing at less than 75% of original forecast at year-end 2005, which resulted in the reserve revisions in 2004 and 2005.

Our estimates of proved reserves are determined at prices and costs at the date of the estimate. Any significant variance from these prices and costs could greatly affect our estimates of reserves. The pricing revision at year-end 2006 at prices of $4.46 per MMBtu of gas and $61.06 per barrel of oil, relative to year-end 2005 prices of $7.72 per MMBtu and $61.04 per barrel of oil, was downward 33.8 Bcfe.

We prepare our own estimates of proved reserves, which are reviewed by independent petroleum engineers. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. For additional information about these risks and their impact on our reserves, see “Items 1 and 2. Business and Properties—Oil and Gas Data—Proved Reserves” and “Notes to Consolidated Financial Statements—14. Supplementary Oil and Gas Information (unaudited)—Analysis of Changes in Proved Reserves” in this Annual Report on Form 10-K.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2007, production will decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent upon our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

Prospects that we decide to drill may not yield natural gas or oil in commercially viable quantities.

We describe some of our prospects and our plans to explore those prospects in “Items 1 and 2. Business and Properties”. A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of natural gas or oil. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. However, the use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling and

 

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testing whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in sufficient quantities to recover drilling or completion costs or to be economically viable. From inception through December 31, 2007, we participated in drilling a total of 1,335 gross wells, of which 936 were completed as producing, 363 were in process of completing or dewatering and 36 were identified as dry holes. Of the 797 wells drilled from inception through December 31, 2005, 219 were producing at less than 75% of original forecast at year-end 2005. If we drill additional wells that we identify as dry holes in our current and future prospects, our drilling success rate may decline and materially harm our business. The cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive. Such uncertainties may harm our business and results of operations.

Certain of our leases in the Powder River Basin are in areas that may have been partially depleted or drained by offset wells.

The Powder River Basin represents a significant part of our drilling program and production. In the Powder River Basin, nearly all of our operations are in coalbed methane plays, and our key project areas are located in areas that have been the most active drilling areas in the Rocky Mountain region. As a result, many of our leases are in areas that may have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, natural gas and oil prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business. In 2008, we plan to participate in the drilling of up to 500 gross wells.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of natural gas and oil, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures. We are employing 3C 3-D seismic technology to certain of our projects. The implementation and practical use of 3C 3-D seismic technology is relatively new, unproven and unconventional, which can lessen its effectiveness, at least in the near term, and increase our costs. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 3-D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may chose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 3-D data without having an opportunity to attempt to benefit from those expenditures.

 

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Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

   

unusual or unexpected geological formations;

 

   

pressures;

 

   

fires;

 

   

blowouts;

 

   

loss of drilling fluid circulation;

 

   

title problems;

 

   

facility or equipment malfunctions;

 

   

unexpected operational events;

 

   

shortages or delivery delays of equipment and services;

 

   

objections from surface owners and nearby surface owners in the areas where we operate;

 

   

compliance with environmental and other governmental requirements and related lawsuits; and

 

   

adverse weather conditions.

The occurrence of these events could also impact third parties, including persons living near our operations, our employees and employees of our contractors, leading to injuries or death or property damage. As a result, we face the possibility of liabilities from these events that could adversely affect our business, financial condition or results of operations.

Additionally, the coal beds in the Powder River Basin from which we produce methane gas frequently contain water, which may hamper our ability to produce gas in commercial quantities. The amount of coalbed methane that can be commercially produced depends upon the coal quality, the original gas content of the coal seam, the thickness of the seam, the reservoir pressure, the rate at which gas is released from the coal and the existence of any natural fractures through which the gas can flow to the well bore. Coal beds, however, frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore. The average life of a coal bed well can range from five to 11 years depending on the coal seam compared to up to 30 years for a non-coal bed well. Our ability to remove and economically dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce coalbed methane in commercial quantities.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

 

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Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. To date, we have financed capital expenditures primarily with sales of our equity securities, proceeds from bank borrowings and cash generated by operations. We intend to finance our capital expenditures with cash flow from operations and our existing financing arrangements. Our cash flow from operations and access to capital are subject to a number of variables, including:

 

   

our proved reserves;

 

   

the level of oil and natural gas we are able to produce from existing wells;

 

   

the prices at which oil and natural gas are sold; and

 

   

our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. Our revolving credit facility restricts our ability to obtain new financing. There can be no assurance as to the availability or terms of any additional financing.

If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our natural gas and oil reserves as well as our revenues and results of operations.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. In addition, a portion of our leases in the Uinta Basin are, and some of our future leases may be, regulated by Native American tribes. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Our Powder River Basin coalbed methane exploration and production activities result in the discharge of large volumes of produced groundwater into adjacent lands and waterways. The ratio of methane gas to produced water varies over the life of the well. The environmental soundness of discharging produced groundwater pursuant to water discharge permits has come under increased scrutiny. Moratoriums on the issuance of additional water discharge permits or more costly methods of handling these produced waters, may affect future well development. Compliance with more stringent laws or regulations, more vigorous enforcement policies of the regulatory agencies, difficulties in negotiating required surface use agreements with land owners or receiving other governmental approvals could delay our Powder River Basin exploration and production activities and/or require us to make material expenditures for the installation and operation of systems and equipment for

 

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pollution control and/or remediation, all of which could have a material adverse effect on our financial condition or results of operations.

In August 2004, the Tenth Circuit Court of Appeals in Pennaco Energy, Inc. v. United States Department of the Interior, upheld a decision by the Interior Board of Land Appeals that the Department of the Interior’s Bureau of Land Management, or BLM, failed to fully comply with the National Environmental Policy Act, or NEPA, in granting certain federal leases in the Powder River Basin to Pennaco Energy, Inc. for coalbed methane development. Other recent decisions in the federal district court in Montana have also held that BLM failed to comply with NEPA when considering coalbed methane development in the Powder River Basin. While these recent decisions have not had a material direct impact on our current operations or planned exploration and development activities, future litigation and/or agency responses to such litigation could materially impact our ability to obtain required regulatory approvals to conduct operations in the Powder River Basin.

Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to the regulation by oil and natural gas-producing states and Native American tribes of conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state, local and Native American tribal authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating area. See “Items 1 and 2. Business and Properties—Business—Operations—Environmental Matters and Regulation” and “Items 1 and 2. Business and Properties—Business—Operations—Other Regulation of the Oil and Gas Industry”.

Recent Colorado legislative changes could limit our Colorado operations and adversely affect our cost of doing business.

Our properties located in Colorado are subject to the authority of the Colorado Oil & Gas Conservation Commission (the “COGCC”). The COGCC has the authority to regulate oil and gas activities to protect public health, safety and welfare, including the environment and wildlife. In 2007, the Colorado legislature approved legislation changing the composition of the COGCC to reduce industry representation and to add the heads of the Colorado Department of Natural Resources and the Colorado Department of Public Health and Environment (“CDPHE”) plus other stakeholders. In addition, the legislation required the COGCC to promulgate rules, (1) in consultation with CDPHE, to provide CDPHE an opportunity to provide comments on public health issues during the COGCC’s decision-making process and (2) in consultation with the Colorado Wildlife Commission, to establish standards for minimizing adverse impacts to wildlife resources affected by oil and gas operations and to ensure the proper reclamation of wildlife habitat during and following such operations. The COGCC has published a draft proposal to implement these provisions and expects to initiate formal rule-making in the first quarter of 2008. Final rules could be effective by the third quarter of 2008. While this regulatory development has not adversely affected our operations to date, these additional rules could cause additional costs, delay and uncertainty in our operations in Colorado and may be emulated in other jurisdictions in which we operate.

Substantially all of our producing properties are located in the Rocky Mountains, making us vulnerable to risks associated with operating in one major geographic area.

Our operations have been focused on the Rocky Mountain region, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are

 

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not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of natural gas and oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells.

During the second half of 2007, natural gas prices in the Rocky Mountain region fell disproportionately when compared to other markets, due in part to continuing constraints in transporting natural gas from producing properties in the region. Because of the concentration of our operations in the Rocky Mountain region, such price decreases are more likely to have a material adverse effect on our revenue, profitability and cash flow than those of our more geographically diverse competitors.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. For example, we encountered limitations on our activities in the West Tavaputs area of the Uinta Basin earlier than expected in the fourth quarter of 2004 due to lease stipulations, which prevented us from completing wells. In addition, our costs increased due to removal of a drilling rig, incurrence of expenses relating to the reinstallation of that rig and additional mobilization costs when the winter stipulations ended in the spring of 2005.

Properties that we buy 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 them.

One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. However, our reviews of acquired properties are inherently incomplete, because it generally 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 and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

Substantially all of our business activities are conducted through joint operating agreements under which we own partial interests in oil and natural gas properties. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.

 

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Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.

Our hedging activities could result in financial losses or could reduce our income.

To achieve a more predictable cash flow, to reduce our exposure to adverse fluctuations in the prices of oil and natural gas and to comply with credit agreement requirements, we currently, and may in the future, enter into hedging arrangements for a portion of our oil and natural gas production. Hedging arrangements for a portion of our oil and natural gas production expose us to the risk of financial loss in some circumstances, including when:

 

   

production is less than expected;

 

   

the counterparty to the hedging contract defaults on its contractual obligations; or

 

   

there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

In addition, these types of hedging arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.

The risk that a counterparty may default on its obligations is heightened by the recent sub-prime mortgage losses incurred by many banks and other financial institutions, including our counterparties or their affiliates. These losses may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which would reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales, thus triggering the hedge payments. As a result, our financial condition could be materially, adversely affected.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties.

We depend on a limited number of key personnel who would be difficult to replace.

We depend on the performance of our executive officers and other key employees. The loss of any member of our senior management or other key employees could negatively impact our ability to execute our strategy. We do not maintain key person life insurance policies on any of our employees.

 

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Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas 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, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. 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. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations.

We will depend on our revolving credit facility for a portion of our future capital needs. Our current revolving credit facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We also are, and expect to continue to be, required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility could result in a default under those facilities, which could cause all of our existing indebtedness to be immediately due and payable.

Our current revolving credit facility limits the amounts we can borrow up to a borrowing base amount, determined by the lenders in their sole discretion, based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 75% of the commitments. If the required lenders do not agree on an increase, then the borrowing base will be the lowest borrowing base acceptable to the required number of lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility.

The ability of our banks to fund their lending obligations under our credit facility may be limited, which would affect our ability to fund our operations.

Our credit facility has commitments from 14 banks. With the current turbulent credit markets, including as a result of losses from the sub-prime mortgage crisis, the banks may become more restrictive in their lending practices or unable to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserve growth, leading to losses and declining production.

Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and gas.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s

 

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atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have already taken legal measures to reduce emissions of greenhouse gases. As a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA also may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations have already agreed to regulate emissions of greenhouse gases, pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Passage of state or federal climate control legislation or other regulatory initiatives or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for oil and gas.

Risks Related to Our Common Stock

Our stock price and trading volume may be volatile, which could result in losses for our stockholders.

The equity trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of equity securities. The market price of our common stock could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition. In addition, the trading volume in our common stock may fluctuate and cause significant price variations to occur. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our common stock include:

 

   

actual or anticipated quarterly variations in our operating results;

 

   

changes in expectations as to our future financial performance or changes in financial estimates, if any, of public market analysts;

 

   

announcements relating to our business or the business of our competitors;

 

   

conditions generally affecting the oil and natural gas industry;

 

   

the success of our operating strategy; and

 

   

the operating and stock price performance of other comparable companies.

Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.

Future sales of our common stock or other equity linked products may cause our stock price to decline.

Sales of substantial amounts of our common stock in the public market or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of these shares could impair our ability to raise capital through the sale of additional common or preferred stock.

As of December 31, 2007, we had 44,760,955 shares of common stock outstanding, excluding stock options. All of the 14,950,000 shares sold in our initial public offering in December 2004, other than shares purchased by our affiliates, are freely tradable. In addition, the remaining outstanding shares are either freely tradable or may be sold in accordance with the provisions of Rule 144. Certain of our stockholders have contractual rights to cause us to register the resale of up to 10,081,278 of our outstanding shares. This registration may be accomplished quickly by filing prospectus supplements under our currently effective shelf registration statement. The resale of a large number of shares could cause our stock price to decline.

 

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Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.

Delaware corporate law and our certificate of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:

 

   

a classified board of directors;

 

   

giving the board the exclusive right to fill all board vacancies;

 

   

permitting removal of directors only for cause and with a super-majority vote of the stockholders;

 

   

requiring special meetings of stockholders to be called only by the board;

 

   

requiring advance notice for stockholder proposals and director nominations;

 

   

prohibiting stockholder action by written consent;

 

   

prohibiting cumulative voting in the election of directors; and

 

   

allowing for authorized but unissued common and preferred shares, including shares used in our shareholder rights plan.

These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

We have significant stockholders with the ability to influence our actions.

Warburg Pincus Private Equity VIII, L.P. owns approximately 23% of our outstanding common stock. Accordingly, this stockholder may be able to control the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws and the approval of mergers and other significant corporate transactions. This concentrated ownership makes it less likely that any other holder or group of holders of common stock will be able to affect the way we are managed or the direction of our business. These factors also may delay or prevent a change in our management or voting control. In addition, one of our directors is affiliated with Warburg Pincus Private Equity VIII, L.P.

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Warburg Pincus, on the other hand, concerning, among other things, potential competitive business activities or business opportunities. None of the institutional investors is restricted from competitive oil and natural gas exploration and production activities or investments, and our certificate of incorporation contains a provision that permits Warburg Pincus to participate in transactions relating to the acquisition, development and exploitation of oil and natural gas reserves without making such opportunities available to us.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 3. Legal Proceedings

We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business and a matter with the Environmental Protection Agency (“EPA”). In September 2006, the EPA alleged that we and an industry partner failed to comply with air quality and emissions standards for equipment used at our North Hill Creek compressor station in the Uinta Basin of Utah. Discussions

 

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with the EPA to resolve these issues are continuing. We believe that our monetary sanctions related to this matter will be less than $100,000 based on our discussions with the EPA and our analysis of monetary sanctions in similar actions. However, potential fines of up to $32,500 per day are possible if we are not able to reach a settlement agreement with the EPA and all the allegations were determined to be accurate.

While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

Item 4. Submission of Matters to a Vote of Security Holders

Not applicable.

 

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PART II

 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market for Registrant’s Common Equity.

Our common stock is listed on the New York Stock Exchange under the symbol “BBG”.

The range of high and low sales prices for our common stock for the two most recent fiscal years as reported by the New York Stock Exchange, is as follows:

 

     High    Low

2006

     

First Quarter

   $ 40.85    $ 29.00

Second Quarter

     37.90      26.00

Third Quarter

     31.60      23.35

Fourth Quarter

     33.20      22.60

2007

     

First Quarter

   $ 32.94    $ 24.76

Second Quarter

     39.25      32.33

Third Quarter

     40.45      32.12

Fourth Quarter

     47.14      38.02

On February 15, 2008, the closing sales price for the common stock as reported by the NYSE was $45.84 per share.

Holders. On February 15, 2008, the number of holders of record of common stock was 380.

Dividends. We have not paid any cash dividends since our inception. Because we anticipate that all earnings will be retained for the development of our business and our credit facility prohibits the payment of cash dividends, no cash dividends will be paid on our common stock in the foreseeable future.

Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, 2007.

Issuer Purchases of Equity Securities

 

Period

   Total
Number of
Shares (1)
   Average
Price Paid
Per Share
   Total Number of
Shares (or Units)
Purchased as Part of
Publicly Announced
Plans or Programs
   Maximum Number (or
Approximate Dollar
Value) of Shares (or
Units) that May Yet
Be Purchased Under
the Plans or Programs

October 1 – 31, 2007

   —        —      —      —  

November 1 – 30, 2007

   —        —      —      —  

December 1 – 31, 2007

   638      42.75    —      —  
                     

Total

   638    $ 42.75    —      —  
                     

 

(1) Represents shares delivered by employees to satisfy the exercise price of stock options and tax withholding obligations in connection the exercise of stock options and shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of equity shares of common stock issued pursuant to our employee incentive plans.

 

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Stockholder Return Performance Presentation

As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the following assumptions:

1.     $100 was invested in our common stock at $25.00 per share on December 10, 2004 (the first full trading day following the effective date of our registration statement filed in connection with the initial public offering of our common stock), and $100 was invested in each of the Standard & Poors 500 Index, the Standard & Poors SmallCap 600 Index-Energy Sector and the Standard & Poors MidCap 400 Index-Energy Sector at the closing price on December 9, 2004.

 

  2. Dividends are reinvested on the ex-dividend dates.

LOGO

 

     December 10,
2004(1)
   December 31,
2004
   December 31,
2005
   December 31,
2006
   December 31,
2007(2)

BBG

   $ 100.00    $ 127.96    $ 154.44    $ 108.84    $ 167.48

S&P SmallCap 600-Energy

   $ 100.00    $ 105.04    $ 159.85    $ 188.03    $ 232.04

S&P MidCap 400-Energy

   $ 100.00    $ 103.83    $ 157.84    $ 160.91    $ 227.30

S&P 500

   $ 100.00    $ 102.00    $ 107.88    $ 122.90    $ 123.47

 

(1) December 10, 2004 was the first full trading day following the effective date of the Company’s registration statement filed in connection with the initial public offering of its common stock.

 

(2) In 2007, we were added to the Standard and Poors MidCap 400 Index and have, therefore, changed our comparative peer group to that index.

 

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Item 6. Selected Financial Data

The following table presents selected historical financial data of the Company for the years ended December 31, 2003, 2004, 2005, 2006 and 2007. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines and other factors. This information should be read in conjunction with the financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”, presented elsewhere in this Annual Report on Form 10-K.

Selected Historical Financial Information

The consolidated income statement information for the years ended December 31, 2005, 2006 and 2007 and the balance sheet information as of December 31, 2006 and 2007 are derived from our audited financial statements included elsewhere in this report. The income statement information for the years ended December 31, 2003 and 2004 and the balance sheet information at December 31, 2003, 2004 and 2005 is derived from audited financial statements that are not included in this report. The information in this table should be read in conjunction with the consolidated financial statements and accompanying notes and other financial data included herein.

 

     Year Ended December 31,  
     2003     2004     2005     2006     2007  
     (in thousands, except per share data)  

Statement of Operations Data:

          

Production revenues(1)

   $ 75,252     $ 165,843     $ 284,406     $ 344,127     $ 374,956  

Other revenues

     184       4,137       4,353       31,202       15,314  

Operating expenses:

          

Lease operating expense

     8,462       14,592       19,585       29,768       41,643  

Gathering and transportation expense

     3,646       5,968       11,950       15,721       23,163  

Production tax expense

     9,815       20,087       33,465       25,886       22,744  

Exploration expense

     3,655       12,661       10,930       9,390       8,755  

Impairment, dry hole costs and abandonment expense

     4,274       24,011       55,353       12,824       25,322  

Depreciation, depletion and amortization

     30,724       68,202       89,499       138,549       172,054  

General and administrative expense

     14,213       18,061       24,540       27,752       32,074  

Non-cash stock-based compensation expense

     3,637       3,031       3,212       6,491       10,154  
                                        

Total operating expenses

     78,426       166,613       248,534       266,381       335,909  
                                        

Operating (loss) income

     (2,990 )     3,367       40,225       108,948       54,361  

Other income (expense):

          

Interest and other income

     123       437       1,977       2,527       2,391  

Interest expense

     (1,431 )     (9,945 )     (3,175 )     (10,339 )     (12,754 )

Total other income and expense

     (1,308 )     (9,508 )     (1,198 )     (7,812 )     (10,363 )
                                        

Income (loss) before income taxes

     (4,298 )     (6,141 )     39,027       101,136       43,998  

Provision for (benefit from) income taxes

     (320 )     (875 )     15,222       39,125       17,244  
                                        

Net income (loss)

     (3,978 )     (5,266 )     23,805       62,011       26,754  

Less deemed dividends on preferred stock

     —         (36,343 )     —         —         —    

Less cumulative dividends on preferred stock

     (12,682 )     (18,633 )     —         —         —    
                                        

Net income (loss) attributable to common stockholders

   $ (16,660 )   $ (60,242 )   $ 23,805     $ 62,011     $ 26,754  
                                        

Income (loss) per common share(2):

          

Basic

   $ (19.38 )   $ (15.40 )   $ 0.55     $ 1.42     $ 0.61  

Diluted

   $ (19.38 )   $ (15.40 )   $ 0.55     $ 1.40     $ 0.60  

Weighted average number of common shares outstanding, basic(3)

     859.4       3,912.3       43,238.3       43,694.8       44,049.7  

Weighted average number of common shares outstanding, diluted

     859.4       3,912.3       43,439.6       44,269.4       44,677.5  

 

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     Year Ended December 31,  
     2003     2004     2005     2006     2007  
     (in thousands)  

Selected Cash Flow and Other Financial Data:

          

Net income (loss)

   $ (3,978 )   $ (5,266 )   $ 23,805     $ 62,011     $ 26,754  

Depreciation, depletion, impairment and amortization

     30,724       68,202       89,499       138,549       172,054  

Other non-cash items

     7,786       26,887       71,168       37,765       40,938  

Change in assets and liabilities

     (659 )     (2,941 )     (202 )     (1,427 )     11,707  
                                        

Net cash provided by operating activities

   $ 33,873     $ 86,882       184,270       236,898       251,453  
                                        

Capital expenditures(4)

   $ 186,327     $ 347,520 (5)   $ 347,427 (5)   $ 501,161 (5)   $ 443,678 (5)

 

(1) Revenues are net of effects of hedging transactions.

 

(2) All per share information has been adjusted to reflect the 1-for-4.658 reverse common stock split effected upon the completion of our initial public offering in December 2004.

 

(3) The weighted average number of common shares outstanding used in the loss per share calculation are computed pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 128 Earnings Per Share. The weighted average common shares outstanding for the year ended December 31, 2004 does not include the 6,594,725 Series A or the 51,951,418 Series B preferred stock that were converted into a total of 26,387,679 common shares upon the completion of our initial public offering in December 2004.

 

(4) Excludes future reclamation liability accruals of $2.9 million, $7.1 million, $10.7 million, $6.3 million and $1.3 million in 2003, 2004, 2005, 2006 and 2007, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $6.1 million, $36.2 million, $23.6 million, $21.0 and $29.0 million in 2003, 2004, 2005, 2006 and 2007, respectively. Also includes furniture, fixtures and equipment costs of $1.8 million in 2003, $2.1 million in 2004, $2.6 million in 2005, $2.4 million in 2006 and $4.6 million in 2007.

 

(5) Not deducted from the amount is $8.8 million, $13.8 million, $92.3 million and $96.5 million of proceeds received principally from the sale of interests in oil and gas properties during the years ended December 31, 2004, 2005, 2006 and 2007, respectively.

 

     As of December 31,
     2003    2004    2005    2006    2007
     (in thousands)

Balance Sheet Data:

              

Cash and cash equivalents

   $ 16,034    $ 99,926    $ 68,282    $ 41,322    $ 60,285

Other current assets

     19,613      37,964      73,036      97,185      71,142

Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment

     307,920      549,182      737,992      951,132      1,182,664

Other property and equipment, net of depreciation

     1,539      2,983      7,956      11,967      10,865

Oil and natural gas properties held for sale, net of accumulated depreciation, depletion, amortization and impairment

     —        —        —        75,496      2,303

Other assets

     2,663      6,103      1,679      10,299      2,428
                                  

Total assets

   $ 347,769    $ 696,158    $ 888,945    $ 1,187,401    $ 1,329,687
                                  

Current liabilities

   $ 46,156    $ 62,106    $ 132,798    $ 119,795    $ 139,568

Long-term debt

     58,900      —        86,000      188,000      274,000

Other long-term liabilities

     4,387      14,320      39,364      123,209      142,608

Stockholders’ equity

     238,326      619,732      630,783      756,397      773,511
                                  

Total liabilities and stockholders’ equity

   $ 347,769    $ 696,158    $ 888,945    $ 1,187,401    $ 1,329,687
                                  

 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the accompanying financial statements and related notes included elsewhere herein. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Item 1A. Risk Factors” and the “Cautionary Note Regarding Forward-Looking Statements”, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Overview

We explore for and develop oil and natural gas in the Rocky Mountain region of the United States. On December 15, 2004, we completed our initial public offering in which we received net proceeds of $347 million after deducting underwriting fees and other offering costs.

We intend to increase stockholder value by profitably growing reserves and production, primarily through drilling operations. We seek high quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of natural gas and oil production at market prices. Approximately 96% of our December 2007 production volume was natural gas.

Our company was formed in January 2002. We began active natural gas and oil operations in March 2002 upon the acquisition of properties in the Wind River Basin. We acquired these properties from a subsidiary of the Williams Companies, which acquired these properties in connection with the Williams Companies’ acquisition of Barrett Resources Corporation in August 2001. Since inception, we substantially increased our activity level and the number of properties that we operate. Our operating results reflect this growth. Also in 2002, we completed two additional acquisitions of properties in the Uinta, Wind River, Powder River and Williston Basins. In early 2003, we completed an acquisition of largely undeveloped coalbed methane properties located in the Powder River Basin. In September 2004, we acquired properties in the Piceance Basin consisting of 8,537 net developed and 9,044 net undeveloped lease acres and 79 net producing wells in or around the Gibson Gulch field (the “Piceance Basin Acquisition Properties”). In May 2006, we acquired properties in the Powder River Basin consisting of approximately 84,300 gross (52,000 net) acres of oil and gas leasehold interests of coal bed methane properties in the Powder River Basin of Wyoming. In June 2007, we sold our Williston Basin properties. A summary of our significant property acquisitions is as follows:

 

Primary Locations of Acquired Properties

   Date Acquired    Purchase Price
          (in millions)

Wind River Basin

   March 2002    $ 74

Uinta Basin

   April 2002      8

Wind River, Powder River and Williston Basins

   December 2002      62

Powder River Basin

   March 2003      35

Piceance Basin

   September 2004      137

Powder River Basin

   May 2006      79

 

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Because of our rapid growth through acquisitions and development of our properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.

Our acquisitions were financed with a combination of funding from equity investments in us, our credit facility, cash flow from operations and, in the case of the Piceance Basin properties, a bridge loan that we repaid in December 2004 with a portion of the proceeds from our initial public offering.

As of December 31, 2007, we had 558 Bcfe of estimated net proved reserves with a Standardized Measure of $941 million (at $6.04 CIGRM and $92.50 WTI). As of December 31, 2006, we had 428 Bcfe of estimated net proved reserves with a Standardized Measure of $529 million (at $4.46 CIGRM and $61.06 WTI), while at December 31, 2005, we had 341 Bcfe of estimated net proved reserves with a Standardized Measure of $782 million (at $7.72 CIGRM and $61.04 WTI).

The average sales prices received for natural gas, before the effects of hedging contracts, for the years ended December 31, 2005, 2006 and 2007 were $7.73 per Mcf, $5.94 per Mcf and $4.37 per Mcf, respectively, and $53.69 per Bbl, $59.39 per Bbl and $61.18 per Bbl, respectively, for oil.

Higher oil and natural gas prices over the past several years have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of those goods and services. To date, the higher sales prices for natural gas and oil have more than offset the higher field costs. Given the inherent volatility of oil and natural gas prices, particularly in the Rockies, that are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions, which generally are lower than the average sales prices we received in 2007. In addition, we hedge 50%-70% of our expected production on a forward 12-month basis. We focus our efforts on increasing natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production.

Like all oil and gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and gas production from a given well naturally decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. The permitting and approval process has been more difficult in recent years than in the past due to increased activism from environmental and other groups and has extended the time it takes us to receive permits and other necessary approvals. Because of our relatively small size and concentrated property base, we can be disproportionately disadvantaged by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we are less able to shift drilling activities to areas where permitting may be easier and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.

 

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Results of Operations

The following table sets forth selected operating data for the periods indicated:

 

     Year Ended
December 31,
2005
   Year Ended
December 31,
2006
   2005 to 2006
Increase (Decrease)
    Year Ended
December 31,
2007
   2006 to 2007
Increase (Decrease)
 
           Amount     Percent        Amount     Percent  
     (in thousands)  

Operating Results:

                 

Operating Revenues

                 

Oil and gas production

   $ 284,406    $ 344,127    $ 59,721     21 %   $ 374,956    $ 30,829     9 %

Other

     4,353      31,202      26,849     617 %     15,314      (15,888 )   (51 )%

Operating Expenses

                 

Lease operating expense

     19,585      29,768      10,183     52 %     41,643      11,875     40 %

Gathering and transportation expense

     11,950      15,721      3,771     32 %     23,163      7,442     47 %

Production tax expense

     33,465      25,886      (7,579 )   (23 )%     22,744      (3,142 )   (12 )%

Exploration expense

     10,930      9,390      (1,540 )   (14 )%     8,755      (635 )   (7 )%

Impairment, dry hole costs and abandonment expense

     55,353      12,824      (42,529 )   (77 )%     25,322      12,498     97 %

Depreciation, depletion and amortization

     89,499      138,549      49,050     55 %     172,054      33,505     24 %

General and administrative expense

     24,540      27,752      3,212     13 %     32,074      4,322     16 %

Non-cash stock-based compensation expense(1)

     3,212      6,491      3,279     102 %     10,154      3,663     56 %
                                         

Total operating expenses

   $ 248,534    $ 266,381    $ 17,847     7 %   $ 335,909    $ 69,528     26 %
                                         

Production Data:

                 

Natural gas (MMcf)

     36,287      47,928      11,641     32 %     57,678      9,750     20 %

Oil (MBbls)

     523      696      173     33 %     586      (110 )   (16 )%

Combined volumes (MMcfe)

     39,425      52,104      12,679     32 %     61,194      9,090     17 %

Daily combined volumes (Mmcfe/d)

     108      143      35     32 %     168      25     17 %

Average Prices(2):

                 

Natural gas (per Mcf)

   $ 7.16    $ 6.40    $ (0.76 )   (11 )%   $ 5.89    $ (0.51 )   (8 )%

Oil (per Bbl)

     46.68      53.50      6.82     15 %     59.87      6.37     12 %

Combined (per Mcfe)

     7.21      6.60      (0.61 )   (8 )%     6.13      (0.47 )   (7 )%

Average Costs (per Mcfe):

                 

Lease operating expense

   $ 0.50    $ 0.57    $ 0.07     14 %   $ 0.68    $ 0.11     19 %

Gathering and transportation expense

     0.30      0.30      0.00     0 %     0.38      0.08     27 %

Production tax expense

     0.85      0.50      (0.35 )   (41 )%     0.37      (0.13 )   (26 )%

Depreciation, depletion and amortization(3)

     2.27      2.69      0.40     18 %     2.87      0.18     7 %

General and administrative expense(4)

     0.62      0.53      (0.09 )   (15 )%     0.52      (0.01 )   (2 )%

 

(1) Non-cash stock-based compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $27.8 million, $34.2 million and $42.2 million for the years ended December 31, 2005, 2006 and 2007, respectively, in the Consolidated Statement of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful, because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, who may have higher or lower costs associated with equity grants.

 

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(2) Average prices shown in the table are net of the effects of our realized hedging transactions. As a result of our realized hedging transactions, natural gas production revenues were reduced by $20.7 million for the year ended 2005 and increased by $22.2 million and $87.7 million for the years ended December 31, 2006 and 2007, respectively. Oil production revenues were reduced by $3.7 million, $4.1 million and $0.8 million for the years ended December 31, 2005, 2006 and 2007, respectively. Before the effect of hedging contracts, the average price we received for natural gas in 2007 was $4.37 per Mcf compared with $5.94 per Mcf in 2006 and $7.73 per Mcf in 2005, and the average price we received for oil in 2007 was $61.18 per Bbl compared to $59.39 per Bbl in 2006 and $53.69 per Bbl in 2005.

 

(3) The depreciation, depletion and amortization (“DD&A”) per Mcfe as calculated based on the DD&A expense and MMcfe production data presented in the table for the years ended December 31, 2006 and 2007 is $2.66 and $2.81, respectively. However, the DD&A rates per Mcfe for the years ended December 31, 2006 and 2007 of $2.69 and $2.87, as presented, exclude production of 473 MMcfe and 1,198 MMcfe, respectively, associated with our properties that were classified as held for sale in the Powder River and Williston Basins and the properties that remain held for sale in the DJ Basin, as these were not depleted during portions of 2006 and all of 2007.

 

(4) Excludes non-cash stock-based compensation as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation, as presented in the Consolidated Statements of Operations, were $0.70, $0.66 and $0.69 for the years ended December 31, 2005, 2006 and 2007, respectively.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Production Revenues. Production revenues increased from $344.1 million for the year ended December 31, 2006 to $375.0 million for the year ended December 31, 2007 due to a 17% increase in production, offset by a decrease in natural gas prices after the effect of realized hedges. The 2007 average CIGRM first-of-market price was 29% lower than in 2006. The net decrease in prices on a per Mcfe basis lowered production revenues by approximately $24.9 million, while production increases added approximately $55.8 million of production revenues, after natural production declines, so that new production from our drilling program more than offset natural production declines. Significant decreases in product prices significantly reduce our revenues from existing properties. See “—Quantitative and Qualitative Disclosure about Market Risk.”

Total production volumes for the 2007 calendar year of 61.2 Bcfe increased 17% from 2006 with increases in production from the Uinta and Piceance Basins, which increased 57% and 43%, respectively. The increase in production was partially offset by decreases in the Williston Basin of 52% (which we sold on June 22, 2007), the Wind River Basin of 36% and the Powder River Basins of 17%. Unscheduled third party plant downtime, pipeline curtailments, compressor maintenance and intentional well shut-ins due to low gas daily prices in the Rocky Mountain region resulted in production volumes being approximately 3.0 Bcf lower than well capacity for the year ended December 31, 2007. Additional information concerning production is in the following table.

 

    Year Ended December 31, 2006   Year Ended December 31, 2007   % Increase/(Decrease)  
    Oil   Natural Gas   Total   Oil   Natural Gas   Total   Oil     Natural Gas     Total  
    (MBbls)   (MMcf)   (MMcfe)   (MBbls)   (MMcf)   (MMcfe)   (MBbls)     (MMcf)     (MMcfe)  

Uinta Basin

  43   16,195   16,453   49   25,536   25,830   14 %   58 %   57 %

Piceance Basin

  193   13,377   14,535   292   19,031   20,783   51 %   42 %   43 %

Wind River Basin

  46   11,156   11,432   36   7,156   7,372   (22 )%   (36 )%   (36 )%

Powder River Basin

    7,002   7,002     5,828   5,828       (17 )%   (17 )%

Williston Basin(1)

  389   145   2,479   184   74   1,178   (53 )%   (49 )%   (52 )%

Other

  25   53   203   25   53   203            
                             

Total

  696   47,928   52,104   586   57,678   61,194   (16 )%   20 %   17 %
                             

 

(1) Includes production from Williston Basin properties through the closing date of the sale on June 22, 2007.

 

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The production increase in the Uinta Basin reflects our continued exploration and development activities in the West Tavaputs and Blacktail Ridge fields. During the year ended December 31, 2007, we had initial sales on 36 new gross wells. The production increase in the Piceance Basin is the result of our continued development activities, with initial sales on 81 new gross wells. The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields that occurred throughout 2007, with no significant drilling or recompletion activities to offset these declines. The production decrease in the Powder River Basin is due to natural production declines in our existing mature fields and the lag time between drilling of coal bed methane well and production of natural gas while dewatering occurs. This was partially offset by initial sales on 123 new gross wells for the year ended December 31, 2007. As of December 31, 2007, we had 121 net operated coal bed methane wells in the dewatering stage.

Hedging Activities. In 2007, we hedged approximately 63% of our natural gas volumes and 53% of our oil volumes, resulting in gas revenues of $87.7 million, offset by a reduction in oil revenues of $0.8 million. In 2006, approximately 43% of our natural gas volumes and 39% of our oil volumes were hedged, resulting in an increase in gas revenues of $22.2 million, offset by a reduction in oil revenues of $4.1 million.

Other Operating Revenues. Other operating revenues decreased from $31.2 million for the year ended December 31, 2006 to $15.3 million for the year ended December 31, 2007. Other operating revenues for 2006 consisted of gains realized from joint exploration agreements entered into and other property sales in the Powder River, Wind River and DJ Basins. Other operating revenues for 2007 primarily consisted of a gain realized on the sale of the Williston Basin properties, along with gains realized from joint exploration agreements entered into in the Paradox and Uinta Basins.

Lease Operating Expense. The increase in lease operating expense from $0.57 per Mcfe in 2006 compared to $0.68 in 2007, is primarily the result of increased expenses in the Powder River, Wind River and Piceance Basins. Lease operating expense increased in the Powder River Basin from $1.05 per Mcfe in 2006 to $1.65 per Mcfe in 2007 due to substantially higher water handling charges on dewatering wells in new pilot areas that have no offsetting gas production as yet. Lease operating expenses, on a per-unit basis, in the Powder River Basin were also adversely affected by the basin-wide pipeline curtailments. As of December 31, 2007, we had 121 net operated coal bed methane wells in the dewatering stage. Lease operating expense increased in the Wind River Basin from $0.60 per Mcfe in 2006 to $0.97 per Mcfe in 2007 due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields, while actual lease operating expenses have remained relatively stable. Lease operating expense increased in the Piceance Basin from $0.36 per Mcfe in 2006 to $0.51 per Mcfe in 2007 as a result of higher than expected water transportation and disposal costs. The following table displays the lease operating expense per Mcfe by basin:

 

     Year Ended December 31, 2006    Year Ended December 31, 2007    % Increase/(Decrease)  
     ($ in thousands)    ($ per Mcfe)    ($ in thousands)    ($ per Mcfe)    (% per Mcfe)  

Uinta Basin

   $ 5,805    $ 0.35    $ 10,715    $ 0.41    17 %

Piceance Basin

     5,172      0.36      10,680      0.51    42 %

Powder River Basin

     7,363      1.05      9,614      1.65    57 %

Wind River Basin

     6,861      0.60      7,131      0.97    62 %

Williston Basin

     3,730      1.50      2,732      2.32    55 %

Other

     837      4.12      771      3.80    (8 )%
                      

Total

   $ 29,768      0.57    $ 41,643      0.68    19 %
                      

Lease operating expense declined from $0.79 per Mcfe in the first half of 2007 to $0.58 per Mcfe in the second half of 2007 as a result of efficiencies gained after the installation of a water management system in the Piceance Basin, an overall reduction in field overtime, fewer workovers in all fields, as well as increased production.

 

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Gathering and Transportation Expense. Gathering and transportation expense increased from $0.30 per Mcfe in 2006 to $0.38 per Mcfe in 2007 due to additional long-term firm transportation and firm processing contracts entered into throughout 2007. We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to avoid possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production from the Piceance and Uinta Basins where we expect to spend a significant portion of our capital expenditure program in future years. In addition, we have entered into long-term firm processing contracts on a portion of our production in the Uinta and Piceance Basins to avoid possible production curtailments that may arise due to limited processing capacity. Included in the above gathering and transportation expense is $0.07 and $0.09 per Mcfe of transportation expense along with $0.01 and $0.06 per Mcfe of processing expense from long-term contracts for the years ended December 31, 2006 and 2007, respectively.

Production Tax Expense. Total production taxes decreased from $25.9 million in 2006 to $22.7 million in 2007. Although our production volumes and production revenues increased, our overall production taxes decreased, because a larger portion of our revenues came from areas with lower tax rates, such as the Piceance and Uinta Basins as compared to the Wind River and Powder River Basins. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 7.9% for 2006 and for 2007. Production taxes are primarily based on the wellhead values of production and the tax rates that vary across the different areas in which we operate. As the proportion of our production changes from area to area, our production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect.

Exploration Expense. Exploration costs decreased from $9.4 million in 2006 to $8.8 million in 2007. Exploration costs for 2006 consisted of $8.1 million for seismic programs, principally in the Montana Overthrust, Wind River, Paradox and DJ Basins, and $1.3 million for delay rentals and other costs. Exploration costs for 2007 consisted of $7.3 million for seismic programs, principally in the Montana Overthrust, Paradox and Big Horn Basins, along with $1.5 million for delay rentals and other exploration costs.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased from $12.8 million in 2006 to $25.3 million in 2007. During 2006, impairment expense was $1.2 million, abandonment expenses were $1.6 million and dry hole costs were $10.0 million for wells drilled primarily in the Uinta and Williston Basins. During 2007, impairment expense was $2.3 million, abandonment expenses were $2.7 million and dry holes and partial dry holes in the Wind River (non-operated), Paradox and Uinta Basins were $12.6 million. In addition, we also expensed $7.7 million related to two wells in the Montana Overthrust area that were tested and determined to be non-commercial in the zones below the Cody Shale; thus, a proportionate share of the well costs were expensed.

We evaluated the impairment of our oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. If the carrying amount exceeds the properties’ estimated fair value, we will adjust the carrying amount of the properties to fair value through a charge to impairment expense. For our Tri-State properties within the DJ Basin, based upon our fair value analysis, we recognized a $2.3 million non-cash impairment charge in 2007. We sold these properties in early 2008.

 

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We account for oil and gas exploration and production activities using the successful efforts method under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense. Otherwise, the costs remain capitalized and are depleted as production occurs. The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of December 31, 2007 pending determination of whether the wells will be assigned proved reserves. The following table does not include $8.6 million related to exploratory wells in progress for which drilling had not been completed at December 31, 2007:

 

     Time Elapsed Since Drilling Completed
     0-3
Months
   4-6
Months
   7-12
Months
   > 12
Months
   Total
     (in thousands)

Wells for which drilling has been completed

   $ 29,315    $ 19,317    $ 12,523    $ 12,421    $ 73,576

The majority of the $12.4 million of exploratory well costs that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, we drill wells into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting from a few to 24 months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering and to classify the reserves as proved.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) was $172.1 million in 2007 compared to $138.5 million in 2006. Of the increase, $22.6 million is due to an increase in production, excluding the properties held for sale in the Williston and DJ Basins, and $11.0 million is due to an increased DD&A rate for 2007. During 2006, the weighted average depletion rate was $2.69 per Mcfe. During 2007, the weighted average depletion rate was $2.87 per Mcfe. The DD&A rates for 2006 and 2007 exclude production of 473 MMcfe and 1,198 MMcfe, respectively, associated with our properties held for sale in the Powder River and Williston Basins and the properties that remain held for sale in the DJ Basin, as these were not depleted during portions of 2006 and all of 2007. Under successful efforts accounting, depletion expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average depletion rate for current production. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased from $27.8 million in 2006 to $32.1 million in 2007. This increase is primarily due to increased personnel required for our capital program and production levels. As of December 31, 2007, we had 155 full-time employees in our corporate office compared to 138 as of December 31, 2006. However, on a per Mcfe basis, general and administrative expense, excluding non-cash stock based compensation, decreased from $0.53 per Mcfe in 2006 to $0.52 per Mcfe in 2007 due to increased production.

Non-cash charges for stock-based compensation were $10.2 million in 2007 compared to $6.5 million in 2006. Non-cash stock-based compensation for 2006 and 2007 is related to vesting of our stock option plans and nonvested equity shares of common stock issued to employees. The increase in charges for non-cash stock-based compensation is primarily due to the additional equity awards that were granted during the later part of 2006 and in 2007, including a new performance-based share program that was approved on May 9, 2007.

 

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The components of non-cash stock-based compensation for 2006 and 2007 are shown in the following table.

 

     Year Ended
December 31,
     2006    2007
     (in thousands)

Restricted common stock

   $ 38    $ —  

Stock options and nonvested equity shares of common stock

     5,938      9,372

Shares issued for 401(k) plan

     515      619

Shares issued for directors’ fees

     —        163
             

Total

   $ 6,491    $ 10,154
             

Interest Expense. Interest expense increased to $12.8 million in 2007 from $10.3 million in 2006. The increase is due to higher average outstanding balances under our credit facility during 2007 to fund exploration and development activities. The weighted average outstanding balance under our credit facility for the year ended December 31, 2007 was $196.0 million compared to $158.9 million in 2006.

Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use and, as a result, we had not capitalized any interest expense until the third quarter of 2006. The weighted average interest rates, including interest and commitment fees paid on the unused portion of our credit facility, amortization of deferred financing costs and the effects of interest rate hedges, used to capitalize interest for the years ended December 31, 2006 and 2007 was 7.1%. We capitalized interest costs of $1.0 million and $1.6 million for the years ended December 31, 2006 and 2007, respectively.

Income Tax Expense. Our effective tax rates were 38.7% and 39.2% in 2006 and 2007, respectively. For both the 2006 and 2007 periods, our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense under Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123R”), that is not deductible for income tax purposes. Due to the tax deductions being created by our drilling activities, we expect that we will incur cash income tax liabilities relating only to the alternative minimum tax (“AMT”) in the next year. We have a significant deferred tax asset associated with net operating loss carryforwards (“NOLs”). It is more likely than not that we will use these NOLs to offset and minimize current tax liabilities, including AMT, in future years.

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

Production Revenues. Production revenues increased from $284.4 million for the year ended December 31, 2005 to $344.1 million for the year ended December 31, 2006 due to an increase in production, offset by decreases in natural gas prices. Production increases from the development of existing properties added approximately $83.7 million of production revenues, which were partially offset by lower natural gas prices that decreased revenues by $24.0 million. Significant decreases in product prices significantly reduce our revenues from existing properties. See “— Quantitative and Qualitative Disclosure about Market Risk”.

 

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Total production volumes for the 2006 calendar year increased 32% from 2005 with increases in production from the Uinta, Williston and Piceance Basins, which increased 115%, 3% and 179% respectively. The increase in production was partially offset by decreases in the Wind River and Powder River Basins, which decreased 27% and 17%, respectively, from 2005. Additional information concerning production is in the following table.

 

     Year Ended December 31,
     2005    2006
     Oil    Natural
Gas
   Total    Oil    Natural
Gas
   Total
     (MBbls)    (MMcf)    (MMcfe)    (MBbls)    (MMcf)    (MMcfe)

Wind River Basin

   68    15,157    15,565    46    11,156    11,432

Uinta Basin

   8    7,612    7,660    43    16,195    16,453

Powder River Basin

   —      8,405    8,405    —      7,002    7,002

Williston Basin

   376    149    2,405    389    145    2,479

Piceance Basin

   45    4,937    5,207    193    13,377    14,535

Other

   26    27    183    25    53    203
                             

Total

   523    36,287    39,425    696    47,928    52,104
                             

The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields that occurred throughout 2006. This decrease in production is partially offset by our new deep Lakota discovery well, the Bullfrog 33-19, which had first production in June 2006. The production increase in the Uinta Basin is due to development activities in West Tavaputs, including the exploration success of the Peters Point 4-12D-13-16 Deep well, which was put on production in November 2006, along with first production from our initial Lake Canyon discovery wells. Furthermore, the completion of a third party gas processing facility in mid-August 2006 increased our gross takeaway capacity in the West Tavaputs field by approximately 20 MMcf/d. The production decrease in the Powder River Basin is due to natural production declines in our existing mature fields and the lag time between drilling of coal bed methane well and production of natural gas while dewatering occurs, which are partially offset by the production from the properties we acquired from CH4 in early May 2006. In late August 2006, we sold the majority of the then producing properties acquired in the CH4 acquisition. As of December 31, 2006, we had 127 net operated coal bed methane wells in the dewatering stage. The production increase in the Piceance Basin is the result of our continued development activities.

Hedging Activities. In 2006, we hedged approximately 43% of our natural gas volumes and 39% of our oil volumes, resulting in an increase in gas revenues of $22.2 million, offset by a reduction in oil revenues of $4.1 million. In 2005, we hedged approximately 50% of our natural gas volumes and 49% of our oil volumes, resulting in a reduction in both natural gas and oil revenues of $20.7 million and $3.6 million respectively.

Other Operating Revenues. Other operating revenues increased from $4.4 million for the year ended December 31, 2005 to $31.2 million for the year ended December 31, 2006. The increase is primarily due to gains realized on joint exploration agreements and other property sales in the Powder River, Paradox, Williston, Wind River, Big Horn, Montana Overthrust, Uinta and DJ Basins.

Lease Operating Expense and Gathering and Transportation Expense. Our lease operating expense increased to $0.57 per Mcfe in 2006 compared to $0.50 in 2005, while our gathering and transportation expense remained consistent at $0.30 per Mcfe in 2006. The increase in lease operating expense is primarily due to an increase in the Powder River Basin from $0.60 per Mcfe in 2005 to $1.05 per Mcfe in 2006. This increase on a per Mcfe basis in the Powder River Basin is due to natural production declines in our mature fields and the higher water handling charges on dewatering wells in new pilot areas that have no offsetting gas production as yet. As of December 31, 2006, we had 127 net operated coal bed methane wells in the dewatering stage. Lease operating expense also increased in the Williston Basin from $1.10 per Mcfe in 2005 to $1.50 per Mcfe in 2006 as a result of the high volumes of water being produced from wells put onto production in 2006.

 

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We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to avoid possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production from the Piceance and Uinta Basins where we expect to spend a significant portion of our capital budget in future years. Included in the above gathering and transportation expense per Mcfe is $0.05 and $0.07 of transportation expense from long-term contracts for the years ended December 31, 2005 and 2006, respectively.

Production Tax Expense. Total production taxes decreased from $33.5 million in 2005 to $25.9 million in 2006. Although we realized higher production revenues from the increase in our production volumes, our overall production taxes decreased as a larger portion of our revenues were generated from areas with lower tax rates. Production taxes as a percentage of natural gas and oil sales before hedging adjustments decreased from 10.8% in 2005 to 7.9% in 2006. Production taxes are primarily based on the wellhead values of production and tax rates that vary across the different areas that we operate. As the ratio of our production changes from area to area, our production rate will either increase or decrease depending on the quantities produced from each area and the production tax rates in effect in each individual area.

Exploration Expense. Exploration expense decreased from $10.9 million in 2005 to $9.4 million in 2006. Exploration expense for 2005 includes $9.4 million for seismic programs principally in the Uinta, Wind River and Big Horn Basins and Montana Overthrust, and $1.5 million for delay rentals and other costs. Exploration expense for 2006 included $8.1 million for seismic programs, principally in the Montana Overthrust, Wind River, Paradox, and DJ Basins, and $1.3 million for delay rentals and other costs.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense decreased from $55.3 million in 2005 to $12.8 million in 2006. During 2005, impairment expense was $42.7 million, dry hole costs were $11.1 million for dry holes in the Wind River, Green River, Uinta and Williston Basins, and abandonment expense was $1.5 million. The impairment expense is the result of a $29.5 million impairment charge in the Cooper Reservoir field, an $11.3 million impairment charge in the Talon field, and a $1.9 million impairment charge in the East Madden field, all of which are located in the Wind River Basin. During the quarter ended June 30, 2005, production from existing and recently drilled infill wells in the Cooper Reservoir field declined more rapidly than anticipated, indicating well interference and limited opportunities to increase well density. In the Talon and East Madden fields, production from exploratory wells was at a rate that was not economic based on the capital investment. During 2006, impairment expense was $1.2 million, dry hole costs were $10.0 million for dry holes primarily in the Uinta and Williston Basins, and abandonment expense was $1.6 million. The impairment expense in 2006 related to our Cedar Camp and Tumbleweed properties within the Uinta Basin based upon our fair value analysis. We sold these properties in December 2006. Included in $10.0 million of dry hole costs for 2006 is $3.5 million related to the #1DLB, an exploration well located in the Lake Canyon area of the Uinta Basin. This well, which was completed in April 2006, was tested and determined to be commercial in the Wasatch formation and non-commercial in the zones below the Wasatch; thus, a proportionate share of the well cost is being expensed.

The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of December 31, 2006 pending determination of whether the wells will be assigned proved reserves. The following table does not include $18.6 million related to exploratory wells in progress for which drilling had not been completed at December 31, 2006:

 

     Time Elapsed Since Drilling Completed
     0-3
Months
   4-6
Months
   7-12
Months
   > 12
Months
   Total
     (in thousands)

Wells for which drilling has completed

   $ 11,453    $ 11,501    $ 6,821    $ 21,179    $ 50,954

Depreciation, Depletion and Amortization. DD&A expense was $138.5 million in 2006 compared to $89.5 million in 2005. In 2006, $27.7 million of the increase was due to the 32% increase in production and $21.3

 

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million was due to an increased DD&A rate for 2006. In 2005, the weighted average DD&A rate was $2.27 per Mcfe compared to $2.69 per Mcfe in 2006. Under successful efforts accounting, depletion expense is separately computed for each producing area. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a depletion rate for current production. In 2006, the relationship of capital expenditures, proved reserves and production from certain producing areas yielded a higher depletion rate than 2005. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased $3.2 million from $24.5 million in 2005 to $27.8 million in 2006. This increase was primarily due to increased personnel required to support our capital program and production levels. As of December 31, 2006, we had 138 full-time employees in our corporate office compared to 127 as of December 31, 2005. We also incurred $0.4 million of nonrecurring expenses during the year ended December 31, 2006 as a result of exploring financing options. On a per unit of production basis, general and administrative expense, excluding non-cash stock based compensation, decreased from $0.62 per Mcfe in 2005 to $0.53 per Mcfe in 2006.

Non-cash stock-based compensation expense included in general and administrative expense increased from $3.2 million in 2005 to $6.5 million in 2006. Non-cash stock-based compensation for 2005 and 2006 is related to vesting of the restricted common stock issued to management and employees upon our formation, our stock option plans and nonvested equity shares of common stock issued to employees. The increase in non-cash stock-based compensation expense is primarily due to the increased number of equity awards that were granted during the later part of 2005 and in 2006. Equity awards to employees generally were made in the first quarter of 2006 and were not made in the first quarter of 2005 because of the awards previously made in connection with our initial public offering in December 2004. The increase is also due to the acceleration of vesting of share-based awards for certain of our officers who left us during 2006. Additionally, we amended our 401(k) Plan on January 1, 2006 to increase our match of the employees’ contribution from 4% up to 6%, of which 50% of the match is made with our common stock.

The components of non-cash stock-based compensation for 2005 and 2006 are shown in the following table.

 

     Year Ended
December 31,
     2005    2006
     (in thousands)

Restricted common stock

   $ 489    $ 38

Stock options and nonvested equity shares of common stock

     2,723      5,938

Shares issued for 401(k) plan

     —        515
             

Total

   $ 3,212    $ 6,491
             

Restricted common stock, which was issued to our founding management and employees of the Company on January 30, 2002, was subject to dual vesting provisions of: (1) one share vesting for every $141.62355 received from investors in Series B Preferred Stock (“dollar vesting”), and (2) 20% vesting upon purchase and an additional 20% vesting each year for four years after purchase (“time vesting”). These restricted shares vest at the later to occur of time vesting and dollar vesting. As of January 31, 2006, the restricted common stock was 100% dollar vested and 100% time vested and the remaining compensation expense was fully recognized.

Interest Expense. Interest expense increased $7.1 million to $10.3 million in 2006 compared to $3.2 million in 2005. The increase was due to higher debt levels during 2006 to fund exploration and development activities and a lack of a need to draw on our credit facility until the third quarter of 2005 due to the availability of the proceeds from our initial public offering in December 2004. As a result, the interest expense during the year of 2005 was primarily comprised of debt commitment fees and amortization of deferred financing costs. The

 

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weighted average outstanding balances under our credit facility for the years ended December 31, 2005 and 2006 were $23.4 million and $158.9 million, respectively.

Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. Until the third quarter of 2006, we had not capitalized any interest expense. The weighted average interest rate used to capitalize interest for the current year was 7.1%, including interest and commitment fees paid on the unused portion of the credit facility and amortization of deferred financing costs. We capitalized interest costs of $1.0 million for the year ended December 31, 2006.

Income Tax Expense. Our effective tax rate was 38.7% in 2006 and 39.0% in 2005. Our effective tax rates for 2006 and 2005 differ from the federal and state statutory rates primarily because of the amount of stock-based compensation expense recorded for financial statement purposes under APB Opinion No. 25 and SFAS No. 123R that is not deductible for income tax purposes. These non-deductible permanent differences caused our effective tax rate to be higher than the rate that would have been effective if the costs would have been deductible. All of our income tax benefits and liabilities to date are deferred. While we have net operating loss carryforwards and deductions from our drilling activities, we are subject to the federal alternative minimum tax (“AMT”) and state income tax. We expect to incur cash payments associated with these taxes within the next year.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been sales and other issuances of equity securities, net cash provided by operating activities, bank credit facilities, proceeds from joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the exploration, development and acquisition of natural gas and oil properties. As we pursue profitable reserve and production growth, we continually monitor the capital resources, including issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we may need to obtain additional equity or debt financing.

At December 31, 2007, our balance sheet reflected a cash and cash equivalents balance of $60.3 million with a balance of $274.0 million outstanding under our credit facility. At December 31, 2007, the borrowing base under our credit facility was $385.0 million. We are in the process of obtaining an increase in our borrowing base and expect a significant increase based on our year-end 2007 proved reserves and hedge position.

Cash Flow from Operating Activities

Net cash provided by operating activities was $184.3 million, $236.9 million and $251.5 million in 2005, 2006 and 2007, respectively. The increases in net cash provided by operating activities were primarily due to an increase in oil and gas revenues, along with the changes in current assets and liabilities, which was offset by increased expenses, as discussed above in “—Results of Operations”. Changes in current assets and liabilities reduced cash flow from operations by $0.02 million and $1.4 million in 2005 and 2006, respectively, and increased cash flow from operations by $11.7 million in 2007.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas and oil produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “—Quantitative and Qualitative Disclosure About Market Risk” below.

 

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To mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices, we have entered into financial commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. We typically hedge a fixed price for natural gas at our sales points (NYMEX less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. At December 31, 2007, we had in place natural gas and crude oil financial collars and swaps covering portions of our 2008, 2009 and 2010 production. Our natural gas and oil derivative financial instruments are accounted in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.

In addition to financial transactions, we are a party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas revenues at the time of settlement, which in turn affects average realized natural gas prices.

All derivative instruments, other than those that meet the normal purchase and sales exceptions as mentioned above, are recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Realized gains and losses on cash flow hedges are transferred from comprehensive income, recognized in earnings and included within oil and gas production revenues in the Consolidated Statements of Operations as the associated production occurs. Unrealized gains and losses from the change in the fair value and realized gains and losses of derivative instruments that do not qualify as cash flow hedges, as well as the ineffective portion of hedge derivatives are reported in earnings in the Consolidated Statements of Operations.

At December 31, 2007, the estimated fair value of all of our derivative instruments was a net asset of $7.9 million comprised of current and noncurrent assets and liabilities. We will reclassify the appropriate amounts to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of December 31, 2007 to be reclassified from other comprehensive income to net income in the next 12 months would be approximately $5.6 million for our cash flow hedges. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. We anticipate that all originally forecasted transactions related to our cash flow hedges will occur by the end of the originally specified time periods. Ineffectiveness related to our derivative instruments was de minimis.

 

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The Company has in place the following swap contracts and cashless collars (purchased put options and written call options) as of December 31, 2007 in order to hedge a portion of our natural gas and oil production for 2008, 2009 and 2010. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production.

 

Contract

   Total
Hedged
Volumes
   Quantity
Type
   Weighted
Average
Floor

Price
   Weighted
Average
Ceiling
Price
   Weighted
Average
Fixed

Price
   Index
Price(1)
   Fair Market
Value
 
                                   (in thousands)  

Cashless Collars:

                    

2008

                    

Natural gas

   12,810,000    MMBtu    $ 6.50    $ 10.00      N/A    CIGRM    $ 8,202  

Oil

   192,150    Bbls    $ 70.48    $ 81.62      N/A    WTI    $ (2,533 )

2009

                    

Oil

   18,250    Bbls    $ 75.00    $ 100.00      N/A    WTI    $ (16 )

Swap Contracts:

                    

2008

                    

Natural gas

   34,325,000    MMBtu      N/A      N/A    $ 6.77    CIGRM    $ 12,282  

Natural gas

   7,160,000    MMBtu      N/A      N/A    $ 6.80    PEPL    $ 1,119  

Oil

   210,450    Bbls      N/A      N/A    $ 73.84    WTI    $ (3,972 )

2009

                    

Natural gas

   21,710,000    MMBtu      N/A      N/A    $ 7.01    CIGRM    $ (2,708 )

Oil

   136,875    Bbls      N/A      N/A    $ 74.41    WTI    $ (1,763 )

2010

                    

Natural gas

   10,360,000    MMBtu      N/A      N/A    $ 6.78    CIGRM    $ (2,672 )

 

(1) CIGRM refers to Colorado Interstate Gas Rocky Mountains and PEPL refers to Panhandle Eastern Pipe Line Company price as quoted in Platt’s Inside FERC on the first business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

The following table includes all hedges entered into subsequent to December 31, 2007 through February 15, 2008.

 

Contract

   Total
Hedged
Volumes
   Quantity
Type
   Weighted
Average
Floor

Price
   Weighted
Average
Ceiling
Price
   Weighted
Average
Fixed

Price
   Index
Price

Swap Contracts:

                 

2008

                 

Natural gas

   610,000    MMBtu    N/A    N/A    $ 7.25    CIGRM

Natural gas

   549,000    MMBtu    N/A    N/A    $ 7.28    PEPL

2009

                 

Natural gas

   5,900,000    MMBtu    N/A    N/A    $ 7.47    CIGRM

Natural gas

   3,285,000    MMBtu    N/A    N/A    $ 7.56    PEPL

2010

                 

Natural gas

   900,000    MMbtu    N/A    N/A    $ 7.76    CIGRM

Natural gas

   2,736,000    MMbtu    N/A    N/A    $ 7.63    PEPL

By removing the price volatility from a portion of our natural gas and oil production for 2008, 2009 and 2010, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers.

 

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Capital Expenditures.

Our capital expenditures are summarized in the following tables:

 

     Year Ended December 31,

Basin/Area

   2005    2006    2007
     (in millions)

Uinta

   $ 82.2    $ 120.0    $ 166.4

Piceance

     129.5      138.2      180.3

Powder River

     28.7      148.0      39.3

Wind River

     58.3      35.3      10.5

Other

     48.7      59.7      47.2
                    

Total

   $ 347.4    $ 501.2    $ 443.7
                    

 

     Year Ended December 31,
     2005    2006     2007
     (in millions)

Acquisitions of proved and unevaluated properties and other real estate

   28.2    159.3 (1)   23.9

Drilling, development, exploration and exploitation of natural gas and oil properties

   293.1    318.5 (2)   383.4

Geologic and geophysical costs and exploratory dry holes and abandonment costs

   23.6    21.0     31.8

Furniture, fixtures and equipment

   2.5    2.4     4.6
               

Total(3)

   347.4    501.2     443.7
               

 

(1) Includes $36.8 million of non-cash deferred tax liability associated with the difference between the tax basis of the properties acquired in the CH4 acquisition and the book basis attributed to the properties under the purchase method of accounting.

 

(2) Includes related gathering and facilities, but excludes exploratory dry holes, which are expensed under successful efforts accounting as exploration expense.

 

(3) For the years ended December 31, 2005, 2006 and 2007, we received $13.8 million, $87.6 million and $96.5 million, respectively, of proceeds principally from the sale of interests in oil and gas properties, which are not deducted from the capital expenditures presented above.

Unevaluated properties increased $15.1 million to $236.3 million at December 31, 2007, including $2.0 million related to unevaluated properties in the DJ Basin and Hingeline Prospect that are currently classified as held for sale at December 31, 2007, from $221.2 million at December 31, 2006, including $18.2 million related to unevaluated properties in the Williston and DJ Basins that were classified as held for sale. The increase is principally from increases in leasehold acquisitions and wells in progress resulting from increased development and exploratory drilling activity during the year ended December 31, 2007.

Excluding material acquisitions, our current capital budget for 2008 is $550-600 million, of which we plan to spend approximately $440-485 million for development drilling and facilities, and up to $110 million on exploration drilling, leasehold acquisitions, geologic and geophysical costs, equipment and other costs. While we may reallocate capital among our areas of activity, our approved budget provides that we plan to spend $230-240 million in the Piceance, $220-240 million in the Uinta, $35-40 million in the Wind River, $35-40 million in the Powder River and up to $75 million in other areas. Based upon our current natural gas and oil price expectations and our hedge position for 2008, we anticipate that our operating cash flow and available borrowing capacity under our credit facility will be sufficient to fund our capital expenditures at current levels for the next twelve months. We also may seek to issue other debt securities to repay amounts outstanding under our credit facility. Currently, credit markets are turbulent, which may limit our access to them or require us to pay higher costs. Also, future cash flows are subject to a number of variables, including our level of natural gas and oil production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts to maintain planned levels of capital expenditures.

 

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The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If natural gas and oil prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow, availability of financing and other factors both within and outside our control.

Financing Activities

Credit Facility. On March 17, 2006, we amended our credit facility (the “Amended Credit Facility”). The Amended Credit Facility, which matures on March 17, 2011, had commitments of $400.0 million, which were expanded to $545.0 million as of November 6, 2007 with the addition of new lenders, and had an initial borrowing base of $280.0 million. Based on mid-year 2007 reserves and our hedge position, the borrowing base was increased to $385.0 million on November 6, 2007. Future borrowing bases will be computed based on proved natural gas and oil reserves, hedge position, and estimated future cash flows from those reserves. We expect that the borrowing base will be increased significantly based on our year-end 2007 proved reserves and hedge position. The Amended Credit Facility matures on March 17, 2011 and bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 1.0% to 1.75% or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.25%. We pay commitment fees ranging from 0.25% to 0.375% of the unused borrowing base. The Amended Credit Facility is secured by natural gas and oil properties representing at least 80% of the value of our proved reserves, and the pledge of all of the stock of our subsidiaries. For information concerning the effect of changes in interest rates on interest payments under this facility, see “—Quantitative and Qualitative Disclosure About Market Risk—Interest Rate Risks” below.

As of December 31, 2006 and 2007, borrowings under the Amended Credit Facility totaled $188.0 and $274.0 million, respectively. The Amended Credit Facility also contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants for all prior periods.

In December 2006, we entered into two interest rate derivative contracts to manage our exposure to changes in interest rates. The first contract was a floating-to-fixed interest rate swap for a notional amount of $10.0 million and the second was a floating-to-fixed interest rate collar for a notional amount of $10.0 million, both to terminate on December 12, 2009. Under the swap, we will make payments to (or receive payments from) the contract counterparty when the variable rate of one-month LIBOR falls below (or exceeds) the fixed rate of 4.70%. Under the collar, we will make payments to (or receive payments from) the contract counterparty when the variable rate falls below the floor rate of 4.50% or exceeds the ceiling rate of 4.95%. Our interest rate derivative instruments have been designated as cash flow hedges in accordance with SFAS No. 133. Changes in fair value of the interest rate swaps or collars are reported in other comprehensive income, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. Ineffectiveness related to such derivative instruments was de minimis.

During the year ended December 31, 2007, we had received $0.1 million in settlement payments with respect to our interest rate hedges, which were deducted from interest expense during the year. We anticipate that all originally forecasted transactions will occur by the end of the originally specified time periods and as of December 31, 2007, based on current projected interest rates, the net amount to be reclassified from accumulated other comprehensive income to net income during 2008 would be a net, after-tax reduction of approximately $0.1 million. At December 31, 2007, the estimated fair value of the interest rate derivatives was a net liability of $0.3 million.

 

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Contractual Obligations. A summary of our contractual obligations as of and subsequent to December 31, 2007 is provided in the following table.

 

 

     Payments Due By Year
     2008    2009    2010    2011    2012    After
2013
   Total
     (in thousands)

Long-term debt(1)

   $ —      $ —      $ —      $ 274,000    $ —      $ —      $ 274,000

Other commitments for developing oil and gas properties

     17,786      —        —        —        —        —        17,786

Office and office equipment leases and other

     1,873      1,925      1,922      465      —        —        6,185

Firm transportation and processing agreements

     22,514      23,291      23,365      23,479      23,596      131,532      247,777

Asset retirement obligations(2)(3)

     801      5,247      1,401      1,800      1,160      25,440      35,849

Derivative liability(4)

     2,408      4,656      2,672      —        —        —        9,736
                                                

Total

   $ 45,382    $ 35,119    $ 29,360    $ 299,744    $ 24,756    $ 156,972    $ 591,333
                                                

 

(1) Amount does not include future commitment fees, interest expense, or other fees on our credit facility because the credit facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

 

(2) Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See “—Critical Accounting Policies and Estimates,” below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

 

(3) Amount includes asset retirement obligations of $0.05 million associated with the DJ Basin, which is currently classified as held for sale.

 

(4) Derivative liabilities represent the fair value of liabilities for oil and gas commodity derivatives and interest rate derivatives as of December 31, 2007. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market risk. See “Critical Accounting Policies and Estimates,” below for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

We have entered into contracts that provide firm processing rights and firm transportation capacity on pipeline systems. The remaining terms on these contracts range from 1 to 11 years and require us to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by us.

In addition to the commitments above, we have commitments for the purchase of facilities equipment as of and subsequent to December 31, 2007 for a total of $7.3 million.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under

 

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different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 of the Notes to the Consolidated Financial Statements for a discussion of additional accounting policies and estimates made by management.

Oil and Gas Properties

Our natural gas and oil exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the property has proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows pursuant to SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized. If it is determined that these properties will not yield proved reserves, the related costs are expensed in the period in which that determination is made. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unevaluated properties are assessed periodically on a property-by-property basis and any impairment in value is charged to expense. Unevaluated properties whose acquisition costs are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unevaluated properties are subsequently determined to be productive, the related costs are transferred to proved oil and gas properties. Proceeds, up to an amount equal to the total carrying amount, from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain or loss. We will record a gain on the sale of a partial interest in unevaluated leases for amounts equal to the excess of proceeds over our total carrying amount of such leases.

We review our proved natural gas and oil properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our gas and oil properties and compare these future cash flows to the carrying amount of the gas and oil properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the natural gas and oil properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate

 

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commensurate with the risk associated with realizing the expected cash flows projected. In 2005, we recorded impairment expense of $42.7 million related to the evaluated costs of the Talon, East Madden and Cooper Reservoir fields in Wyoming’s Wind River Basin. In 2006, we recorded impairment expense of $1.2 million related to our Cedar Camp and Tumbleweed properties within the Uinta Basin. In 2007, we recorded impairment expense of $2.3 million related to our Tri-State properties within the DJ Basin.

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding a gas and oil field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial, which will result in additional exploration expenses when incurred.

Our investment in natural gas and oil properties includes an estimate of the future costs associated with dismantlement, abandonment and restoration of our properties. These costs are recorded as provided in SFAS No. 143, Accounting for Asset Retirement Obligations. The present value of the future costs are added to the capitalized costs of our oil and gas properties and recorded as a long-term liability. The capitalized cost is included in the natural gas and oil property costs that are depleted over the life of the assets.

The recognition of an asset retirement obligation (“ARO”) requires that management make numerous estimates, assumptions and judgments regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense.

The provision for depletion of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Oil is converted to natural gas equivalents, Mcfe, at the rate of one barrel to six Mcf. Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which incorporate assumptions regarding future development and abandonment costs as well as our level of capital spending. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. This decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.

Oil and Gas Reserve Quantities

Our estimate of proved reserves is based on the quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. Our proved reserves are reviewed on a well-by-well basis by an independent engineering firm.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms described above adhere to the same guidelines when reviewing our reserve reports. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

 

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Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and natural gas liquids eventually recovered.

As of December 31, 2005, we revised our proved reserves downward by 24.7 Bcfe, excluding pricing revisions, primarily as a result of a reduction in proved undeveloped reserves in the Piceance Basin due to the use of completion techniques performed from January through September 2005 that yielded results lower than our expectations as of December 31, 2004. Completion techniques used in subsequent periods have yielded more favorable results, which are reflected in upward revisions in 2006 and 2007 reserve estimates in this area. The downward revision in the Piceance Basin in 2005 was 25.6 Bcfe. In this basin, 31% of the proved wells forecast as of December 31, 2004 were 25% below forecast as of December 31, 2005. The reserve variance between the independent reserve engineers and us as of December 31, 2004 for this basin was 13 Bcfe with the independent engineer at the lower estimate. The downward revision in the Powder River Basin in 2005 was 9.6 Bcfe. In this basin, 36% of the proved wells forecast as of December 31, 2004 were 25% below forecast as of December 31, 2005. The reserve variance between the independent reserve engineers and us as of December 31, 2004 for this basin was 3.8 Bcfe with the independent engineer at the lower estimate. An upward revision of 8.1 Bcfe occurred in the Uinta Basin in the West Tavaputs Field in 2005. In this basin, 31% of the proved wells forecast as of December 31, 2004 were 25% above forecast as of December 31, 2005. The reserve variance between the independent reserve engineers and BBC as of December 31, 2004 was 2.1 Bcfe with the independent engineer at the lower estimate.

During 2005, reviews of proved oil and gas properties in the Wind River Basin indicated a decline in the recoverability of their carrying value and the need for an impairment in the Cooper Reservoir, Talon and East Madden fields in the total amount of $42.7 million. We undertook a drilling program in Cooper Reservoir in 2003 and 2004 with the expectation of a specific economic reserve level. Actual reserve levels were less than our expectations which led to an impairment in the field in 2005. The impairments in the Talon and East Madden fields were the result of unsuccessful exploration programs.

As of December 31, 2006, we revised our proved reserves upward by 12.4 Bcfe, excluding pricing revisions. This revision was primarily the result of increased performance of wells drilled during the last half of 2005 and the first half of 2006. The pricing revision at year-end 2006 at prices of $4.46 per MMBtu of gas and $61.06 per barrel of oil, relative to year-end 2005 prices of $7.72 per MMBtu and $61.04 per barrel of oil, was downward 33.8 Bcfe. These prices were adjusted by lease for quality, transportation fees and regional price differences.

As of December 31, 2007, we revised our proved reserves upward by 34.8 Bcfe, excluding pricing revisions, primarily as a result of adding increased density proved undeveloped locations in the West Tavaputs field and continued improved performance of wells drilled in the West Tavaputs and Piceance fields. We also revised our 2007 year-end proved reserves upward by 19.4 Bcfe, as year-end 2007 pricing was $6.04 per MMBtu and $92.50 per barrel of oil, relative to year-end 2006 at prices of $4.46 per MMBtu of gas and $61.06 per barrel of oil. These prices were adjusted by lease for quality, transportation fees and regional price differences.

Revenue Recognition

We record revenues from the sales of natural gas and oil when in the month that delivery to the customer has occurred and title has transferred. This occurs when natural gas or oil has been delivered to a pipeline or a tank lifting has occurred. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. However, differences have been insignificant.

We may have an interest with other producers in certain properties, in which case we use the sales method to account for natural gas imbalances. Under this method, revenue is recorded on the basis of natural gas actually

 

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sold by the Company. In addition, we record revenue for our share of natural gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. We also reduce revenue for other owners’ natural gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. Our remaining over- and under-produced gas balancing positions are considered in our proved reserves. Gas imbalances as of December 31, 2006 and 2007 were not significant.

Derivative Instruments and Hedging Activities

We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas and oil production by reducing our exposure to price fluctuations. We also enter into derivative contracts to mitigate the risk of interest rate fluctuations. For the year ended December 31, 2007, these transactions included swaps and cashless collars. We account for these activities pursuant to SFAS No. 133, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. SFAS No. 133 requires a company to formally document, at the inception of a hedge, the hedging relationship and the entity’s risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

We have established the fair value of all derivative instruments using estimates determined by our counterparties and subsequently evaluated internally. These values are based upon, among other things, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings.

We may use derivative financial instruments which have not been designated as hedges under SFAS No. 133 because they still protect us from changes in commodity prices. These instruments, if used, will be marked to market with the resulting changes in fair value recorded in earnings.

As of December 31, 2007, the fair value of all of our derivative instruments was a net asset of $7.9 million, comprised of current and noncurrent assets and liabilities. The deferred income tax effect on the fair value of derivatives at December 31, 2007 totaled $3.0 million, which is recorded in current and noncurrent deferred tax liabilities.

Income Taxes and Uncertain Tax Positions

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates to the

 

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differences between financial statement and income tax reporting. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices).

Effective January 1, 2007, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement No. 109 (“FIN No. 48”). In accordance with FIN No. 48, we recognize the benefit of a tax position, if that position is more likely than not of being sustained in an audit, based on the technical merits of the position. As a result of the implementation of FIN No. 48, we recognized a $0.2 million liability for unrecognized tax benefits.

Stock-based Compensation

The Company accounts for stock-based compensation in accordance with SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123R”), which revises SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees. This statement requires us to record expense associated with the fair value of stock-based compensation. However, for awards granted before we were a public company (i.e. those granted prior to April 16, 2004, which is defined by SFAS No. 123R as the date we became a public company as a result of filing our Form S-1 registration statement with the SEC) we continue to use the minimum value method described under APB Opinion No. 25. For awards granted after we were a public company (i.e. those granted subsequent to April 16, 2004), and for new, modified, repurchased, or cancelled awards on or subsequent to our adoption of SFAS No. 123R on October 1, 2004, we recognized share-based employee compensation cost based on the fair value as computed under SFAS No. 123R.

The Company continues to account for certain stock options under the original provisions of APB Opinion No. 25 because those options were issued prior to April 16, 2004. Under APB Opinion No. 25, we recognize compensation expense only to the extent that the exercise price of the options granted exceed the market value of the underlying common stock on the date of grant. In total, we recorded non-cash stock-based compensation of $3.2 million, $6.5 million, and $9.9 million in 2005, 2006 and 2007, respectively, for option grants, option modifications, nonvested equity shares of common stock and nonvested performance-based equity shares of common stock.

Acquisitions

The establishment of our initial asset base since our founding in January 2002 has included material acquisitions of natural gas and oil properties, which have been accounted for using the purchase method of accounting.

Under the purchase method, the acquiring company adds to its balance sheet the estimated fair values of the acquired company’s assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill. Goodwill is assessed for impairment at least annually. In each of our acquisitions to date we have determined that the purchase price did not exceed the fair value of the net assets acquired. Therefore, no goodwill was recorded.

There are various assumptions we made in determining the fair values of acquired assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the natural gas and oil properties acquired. To determine the fair values of these properties, we prepare estimates of natural gas and oil reserves. These estimates are based on work performed by our engineers and that of outside consultants. The fair value of reserves acquired in an acquisition must be based on our estimates of future natural

 

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gas and oil prices and not the prices at the time of the acquisition. Our estimates of future prices are based on our own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics such as economic growth forecasts. They also are based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis. Forecasts of future prices from independent third parties are noted when we make our pricing estimates.

We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a rate determined appropriate at the time of the acquisition based upon our cost of capital.

We also apply these same general principles in arriving at the fair value of unevaluated properties acquired in an acquisition. These unevaluated properties generally represent the value of probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate for the inherent risk of estimating and valuing probable and possible reserves, we apply a risk-weighting factor to probable and possible volumes to reduce the estimated reserve volumes. Additionally, we increase the discount factor, compared to proved reserves, to recognize the additional uncertainties related to determining the value of probable and possible reserves.

New Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement. Where applicable, SFAS No. 157 simplifies and codifies fair value related guidance previously issued within U.S. generally accepted accounting principles. Although SFAS No. 157 does not require any new fair value measurements, its application may, for some entities, change current practice. SFAS No. 157 was effective for the Company beginning January 1, 2008. Although additional disclosure may be required about the information used to develop fair value measurements, the adoption of SFAS No. 157 is not expected to have a material impact on our financial statements.

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 many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair value option. The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. SFAS No. 159 was effective for the Company beginning January 1, 2008; however, the Company does not expect to elect the fair value option for any eligible financial instruments or other items.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS 141R”), which replaces FASB Statement No. 141, Business Combinations. This statement requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified in the statement. This includes the measurement of the acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for pre-acquisition gain and loss contingencies, the recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We expect SFAS No. 141R will have an impact on our consolidated financial statements when effective, but the nature and magnitude of the specific effects will depend upon the nature, terms and size of the acquisitions we consummate after the effective date.

 

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Quantitative and Qualitative Disclosure 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 risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. 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 and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our price swap and collars contracts in place in during 2007, our annual income before income taxes, including hedge settlements, for the year ended December 31, 2007 would have decreased by approximately $3.1 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.3 million for each $1.00 per barrel change in crude oil prices.

We periodically enter into and anticipate entering into financial hedging activities with respect to a portion of our projected natural gas and oil production through various financial transactions which hedge the future prices received. These transactions may include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty and cashless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference. These financial hedging activities are intended to support natural gas and oil prices at targeted levels and to manage our exposure to natural gas and oil price fluctuations. We typically hedge a fixed price for natural gas at our sales points (NYMEX less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. We do not hold or issue derivative instruments for speculative trading purposes.

In addition to financial transactions, we are a party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchases and normal sales exception and therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas revenues at the time of settlement, which in turn affects average realized natural gas prices.

For the calendar year 2008, we currently have financial hedges in place for 55,454,000 MMBtu of natural gas production and 402,600 Bbls of oil production. We also have hedges in place for 30,895,000 MMBtu of natural gas production and 155,125 Bbls of oil production for 2009 and 13,996,000 MMBtu of natural gas production for 2010. These hedges are summarized in the tables presented above under “—Cash Flow from Operating Activities.”

Commodity Hedges

Commodity Swaps

Through a price swap, we have fixed the price we will receive on a portion of our natural gas and oil production in 2008, 2009 and 2010. The weighted average price we will receive in 2008 for natural gas is $6.77 per MMBtu for a CIGRM price and $6.83 for a PEPL price, $7.11 per MMBtu for a CIGRM price and $7.56 for

 

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a PEPL price in 2009, and $6.86 per MMBtu for a CIGRM price and $7.63 for a PEPL price in 2010. The weighted average price we will receive for oil is $73.84 per Bbl for 2008 and $74.41 per Bbl for 2009. The tables presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Flow from Operating Activities,” provide the deliveries associated with these arrangements as of February 15, 2008.

In a swap transaction, the counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price.

Commodity Collars

Through price collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas production in 2008 and 2009. The weighted average minimum, or floor, price we will receive in 2008 is $6.50 per MMBtu for a CIGRM price. The weighted average maximum, or ceiling, price we will receive in 2008 for a CIGRM price is $10.00 per MMBtu, respectively. We have also fixed the minimum price we will receive on a portion of our oil production in 2008 and 2009. We will receive a weighted average floor price of $70.48 and $75.00 per Bbl for a WTI price in 2008 and 2009, respectively, and a weighted average ceiling price of $81.62 and $100.00 per Bbl, respectively. The price collars also allow us to share in upward price movements up to the ceiling prices referenced in the contracts. The table presented above under “—Cash Flow from Operating Activities” provide the deliveries and floor and ceiling prices associated with these various arrangements as of December 31, 2007.

In a collar transaction, the counterparty is required to make a payment to us for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. We are required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the fixed ceiling price is below the settlement price. Neither party is required to make a payment if the settlement price falls between the fixed floor and ceiling price.

Interest Rate Risks

At December 31, 2007, we had debt outstanding of $274.0 million, which bears interest at floating rates in accordance with our revolving credit facility. The average annual interest rate incurred on this debt for the years ended December 31, 2006 and 2007 was 7.1% and 6.3%, respectively. A one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate for the year ended December 31, 2007 would have resulted in an estimated $2.0 million increase in interest expense assuming a similar average debt level to the year ended December 31, 2007.

Interest Rate Hedges

Through interest rate derivative contracts, we have attempted to mitigate exposure to changes in interest rates. We entered into an interest rate swap for a notional amount of $10 million for a fixed LIBOR rate of 4.70%. We also entered into an interest rate collar for a notional amount of $10 million in which the interest rate has fixed minimum and maximum LIBOR rates of 4.50% and 4.95%, respectively.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The information required by this item is included above in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk”.

 

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Item 8. Financial Statements and Supplementary Data

The information required by this item is included below in “Item 15. Exhibits, Financial Statement Schedules”.

Item 9. Changes in and Disagreements with Accountants and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. Based on an evaluation carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures, as defined in Securities Exchange Act Rules 13a-15(d) and 15d-15(e), were, as of December 31, 2007, effective.

Management’s Report on Internal Control Over Financial Reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:

 

   

pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the company’s assets;

 

   

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of the company’s management and directors; and

 

   

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control—Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2007.

Our independent registered public accounting firm has issued an attestation report on our internal controls over financial reporting. That report immediately follows this report.

 

/S/    FREDRICK J. BARRETT             /S/    ROBERT W. HOWARD        

Fredrick J. Barrett

Chairman and Chief Executive Officer

February 26, 2008

   

Robert W. Howard

Chief Financial Officer

February 26, 2008

Changes in Internal Controls. There has been no change in our internal control over financial reporting during the fourth fiscal quarter of 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Bill Barrett Corporation

Denver, Colorado

We have audited the internal control over financial reporting of Bill Barrett Corporation and subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2007 of the Company and our report dated February 26, 2008, expressed an unqualified opinion on those financial statements.

/s/  Deloitte & Touche LLP

Denver, Colorado

February 26, 2008

 

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Item 9B. Other Information

Not applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information regarding our directors and executive officers will be included in an amendment to this Form 10-K or in the “Directors and Executive Officers” section of the proxy statement for the 2008 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2007, and is incorporated by reference to this report.

Item 11. Executive Compensation

Information regarding executive compensation will be included in an amendment to this Form 10-K or in the “Executive Compensation” section of the proxy statement for the 2008 annual meeting of stockholders in either case, to be filed within 120 days after December 31, 2007, and is incorporated by reference to this report.

 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the “Beneficial Owners of Securities” section of the proxy statement for the 2008 annual meeting of stockholders in either case, to be filed within 120 days after December 31, 2007, and is incorporated by reference to this report.

Equity Compensation Plan Information

The following table provides aggregate information presented as of December 31, 2007 with respect to all compensation plans under which equity securities are authorized for issuance.

 

Plan Category

   (a)
Number of Securities
to Be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights
   (b)
Weighted Averaged
Exercise Price of
Outstanding
Options, Warrants
and Rights
    (c)
Number of Securities
Remaining Available
for Future Issuance
(Excluding Securities
Reflected in Column (a))

Equity compensation plans approved by shareholders

   3,481,962    $ 28.25 (1)   1,686,791

Equity compensation plans not approved by

shareholders

   —        —       —  
                 

Total

   3,481,962    $ 28.25     1,686,791
                 

 

(1) The weighted average exercise price relates to the 2,917,862 outstanding options included in column (a). It does not relate to the 564,100 nonvested equity shares of common stock (restricted stock) that also are included in column (a) but that do not contain an exercise price.

Item 13. Certain Relationships and Related Transactions and Director Independence

Information regarding certain relationships and related transactions will be included in an amendment to this Form 10-K or in the “Transactions Between the Company and Related Parties” and “Directors and Executive Officers” section of the proxy statement for the 2008 annual meeting of stockholders in either case, to be filed within 120 days after December 31, 2007, and is incorporated by reference to this report.

 

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Item 14. Principal Accounti