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Bill Barrett Corp · 10-K · For 12/31/09

Filed On 2/23/10, 8:22am ET   ·   Accession Number 1193125-10-37005   ·   SEC File 1-32367

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  As Of                Filer                Filing    For/On/As Docs:Size              Issuer               Agent

 2/23/10  Bill Barrett Corp                 10-K       12/31/09    9:2.2M                                   RR Donnelley/FA

Annual Report   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report                                       HTML   1.49M 
 2: EX-12.1     Computation of Ratio of Earnings to Fixed Charges   HTML     30K 
 3: EX-21.1     Subsidiaries of the Registrant                      HTML      7K 
 4: EX-23.1     Consent of Deloitte & Touche LLP                    HTML      7K 
 5: EX-23.2     Consent of Netherland, Sewell & Associates, Inc.,   HTML      8K 
                          Independent Petroleum Engineer                         
 6: EX-31.1     Certification of the CEO Pursuant to Section 302    HTML     14K 
 7: EX-31.2     Certification of the CFO Pursuant to Section 302    HTML     14K 
 8: EX-32       Certification of the Ceo/CFO Pursuant to Section    HTML      9K 
                          906                                                    
 9: EX-99.1     Report of Netherland, Sewell & Associates, Inc.     HTML     26K 
                          Dated February 2, 2010                                 


10-K   —   Annual Report
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
"Report of Independent Registered Public Accounting Firm
"Consolidated Balance Sheets, December 31, 2009 and 2008
"Consolidated Statements of Operations, for the years ended December 31, 2009, 2008 and 2007
"Consolidated Statements of Stockholders' Equity and Comprehensive Income, for the years ended December 31, 2009, 2008 and 2007
"Consolidated Statements of Cash Flows, for the years ended December 31, 2009, 2008 and 2007
"Notes to Consolidated Financial Statements

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  Form 10-K  

 

 

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, 2009

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 whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    ¨  Yes    ¨  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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨ (Do not check if a smaller reporting company)    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, 2009 based on the $27.46 closing price of our common stock was $925,176,130.*

 

* Calculated based on beneficial ownership of our common stock on January 29, 2010 without assuming that any of the registrant’s directors, executive officers, or 10 percent or greater beneficial owners 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 January 29, 2010, the registrant had 45,491,639 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 2010 to be filed pursuant to Regulation 14A no later than 120 days after the end of the registrant’s fiscal year ended December 31, 2009.

 

 

 


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;

 

   

natural gas and oil reserves;

 

   

realized oil and natural gas prices;

 

   

production;

 

   

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

 

   

ability to obtain permits and governmental approvals;

 

   

identified drilling locations;

 

   

changing regulatory environment;

 

   

transportation and access to pipelines;

 

   

the ability of our hedge counterparties to fulfill their obligations;

 

   

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;

 

   

the ability to obtain and the cost of financing;

 

   

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

 

   

technology;

 

   

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 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 (“BBC,” the “Company,” “we,” “us” or “our”) was formed in January 2002 and is incorporated in the State of Delaware. We explore for and develop natural gas and oil 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 natural gas and oil in the Rocky Mountain region to profitably grow our reserves and production. In addition to development drilling, we plan to continue evaluating our delineation and exploration prospects on our extensive acreage position of approximately 1.3 million net undeveloped acres. Our operating results reflect our development growth and exploration success on our properties.

We began active natural gas and oil operations in March 2002 with the acquisition of properties in the Wind River Basin. 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 also acquired producing properties that had large undeveloped acreage positions associated with them. For example, in 2002, we completed two additional acquisitions that included 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 and around the Gibson Gulch field; and in May 2006, we added to our coalbed methane position in the Powder River Basin. In June 2007, we sold our Williston Basin properties. In June 2009, we acquired Cottonwood Gulch, an undeveloped property in the Piceance Basin.

We operate in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of our operations are conducted in the United States. Consequently, we currently report 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.”

The following table provides information regarding our operations by basin as of December 31, 2009:

 

Basin/Area

   State    Estimated Net
Proved
Reserves(1)
(Bcfe)
   December 2009
Average Daily
Net Production
(MMcfe/d)
   Net
Producing
Wells
   Net
Undeveloped
Acreage
 

Uinta

   UT    338.6    74.2    179.8    182,217 (2) 

Piceance

   CO    532.0    106.0    490.4    46,653 (4) 

Powder River

   WY    63.5    39.3    446.5    62,025   

Wind River

   WY    29.7    24.8    116.2    198,800   

Paradox

   CO/UT    1.0    1.5    2.2    295,276   

Montana Overthrust

   MT    —      —      —      165,667   

Big Horn(3)

   WY    —      —      1.0    58,367   

Other

   Various    —      —      —      241,971   
                        

Total

      964.8    245.8    1,236.1    1,250,976 (2) 
                        

 

(1)

Our proved reserves were determined in accordance with Securities and Exchange Commission, or SEC, guidelines, using the average price on the first of the month for natural gas (CIGRM price) and oil (WTI price), which averaged $3.04 per MMBtu of natural gas and $57.65 per barrel of oil in 2009, without giving

 

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effect to hedging transactions. CIGRM refers to Colorado Interstate Gas Rocky Mountains price as quoted in Platt’s Gas Daily on the first flow day of each month. WTI refers to West Texas Intermediate price as quoted by Plains All American Pipeline, L.P. using crude oil price bulletins for the first day of each month. Our reserves estimates are based on a reserve report prepared by us and audited by our independent third party petroleum engineers. See “—Oil and Gas Data—Proved Reserves.”

(2) An additional 104,683 net undeveloped acres that are subject to drill-to-earn agreements are not included.
(3) The Big Horn Basin has two gross non-operated wells with insignificant proven reserves.
(4) Includes 36,281 net acreage associated with the Cottonwood Gulch property.

Our Offices

We were founded in 2002 and are 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 and Strategy

The following are the key components of our business strengths and strategy:

 

   

Generating reserves and production growth through development drilling. We have increased our production and proved reserves by double-digit percentage growth rates each year that we have been in existence. Production grew from 6.6 Bcfe in 2002 to 89.7 Bcfe in 2009. Proved reserves grew from 119.1 Bcfe at year-end 2002 to 964.8 Bcfe at year-end 2009. Over the past three years, we replaced 351% of production through drilling and 353% of production in total, including acquisitions. We expect to generate profitable, long-term reserves and production growth predominantly through repeatable, lower-risk drilling on our development assets. For 2010, we currently plan to allocate approximately 95% of our capital budget to our development projects while in the past we have allocated up to 25% of our capital budget to exploration prospects. Our four core development areas have approximately 5,700 identified drilling locations as of December 31, 2009, with approximately 539 of these locations being associated with proved undeveloped reserves. In 2010, we plan to participate in the drilling of up to 240 gross wells across our operations.

 

   

Maximizing operational control. We seek to operate our properties and maintain a high working interest. During the month of December 2009, we operated approximately 98% 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.

 

   

Experienced management team. We believe our management team’s experience and expertise in the Rocky Mountains provides a distinct competitive advantage. Our 14 corporate officers average approximately 25.5 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. A majority of our properties are classified as unconventional resources, including basin-centered tight gas, CBM and fractured oil and shale gas plays. According to the U.S. Department of Energy’s Information Administration (“EIA”) 2010 Annual Energy Outlook, the EIA estimates that the lower 48 states unconventional natural gas production will increase at a compounded annual growth rate of 7.8% from 2008-2015.

 

   

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 a natural gas region in North America with significant remaining growth potential.

 

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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 2009, 95% consisted of natural gas. The Rockies Express pipeline, which began operations in January 2008, provides Rocky Mountain producers additional takeaway capacity and access to markets with historically higher pricing for selling natural gas. There is 2 Bcf/d of additional take-away capacity proposed from the region by means of new pipelines and added compression to existing pipelines over the next several years. The proposed Ruby pipeline will provide Rocky Mountain producers access to the West Coast market, further diversifying and improving our ability to market our natural gas.

 

   

Maintaining financial flexibility and strong financial position. We recently have funded our capital program with operating cash flow. We currently plan to align our 2010 capital expenditures with our anticipated cash flow from operations, but may increase activities if warranted by regulatory approvals, exploration success, new opportunities and/or continued commodity price improvement. We continually monitor our debt levels and available liquidity to maintain a strong financial position. As of December 31, 2009, we had an outstanding balance of $5.0 million under our $592.8 million credit facility. 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 development projects, we believe our management team’s experience and expertise enable us to identify, evaluate and develop new natural gas and oil reservoirs through exploration and acquisitions. We have assembled an asset base of 1.3 million net undeveloped leasehold acres as of December 31, 2009. These properties include several exploration projects that we believe may provide exposure to future potential resource plays.

Areas of Operation

LOGO

 

5


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, 2009—532.0 Bcfe.

 

   

Producing wells—We held interests in 532 gross producing wells as of December 31, 2009.

 

   

2009 net production—36.5 Bcfe.

 

   

Acreage—We held 46,653 net undeveloped acres, including the Cottonwood Gulch acquisition, as of December 31, 2009.

 

   

Capital expenditures—Our capital expenditures for 2009 were $254.8 million for participation in the drilling of 119 gross wells and to expand our compression and gathering facilities in the Piceance Basin.

 

   

As of December 31, 2009, we were in the process of drilling 2 gross (2.0 net) wells and waiting to complete 58 gross (58.0 net) wells within the Piceance Basin.

The Gibson Gulch area is a basin-centered gas play along the north end of the Divide Creek anticline near the eastern limits of the Piceance Basin’s productive Mesaverde (Williams Fork) trend at depths of approximately 7,500 feet. Through 2006, we drilled on a 20-acre well density. Beginning in 2007, we commenced drilling on 10-acre density and our 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 Oil & Gas Corporation’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, Colorado. We have the option annually to elect to process liquids with Enterprise Products Partners L.P. and receive the value of natural gas liquids (“NGL”) for a portion of our production. In 2009 and 2010, we have elected the liquids option and are receiving OPIS (“Oil Price Information Service”) Mt. Belvieu prices for our NGL, which are currently priced at a premium to natural gas.

Uinta Basin

The Uinta Basin is located in northeastern Utah. Our development operations are conducted in the West Tavaputs area, and we are currently testing offsets and increased density locations 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, 2009—338.6 Bcfe.

 

   

Producing wells—We held interests in 198 gross producing wells as of December 31, 2009.

 

   

2009 net production—32.2 Bcfe.

 

   

Acreage—We held 182,217 net undeveloped acres as of December 31, 2009, along with 104,683 net acres that are subject to drill-to-earn agreements.

 

   

Capital expenditures—In 2009, our capital expenditures were $93.7 million in the Uinta Basin area to drill 20 gross wells and install compression and gathering facilities.

 

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West Tavaputs

We serve as operator of our interests in the West Tavaputs area. As of December 31, 2009, we had 706 drilling locations and 324 Bcfe of estimated proved reserves with a weighted average working interest of 97%. We are actively drilling our shallow program, which targets the gas-productive sands of the Wasatch and Mesaverde formations at depths down to 7,600 feet on average. We drilled 17 shallow wells in 2009 and completed 31 wells. In 2010, we plan to drill up to eight shallow wells and complete 19 wells. The Wasatch and Mesaverde formations are currently being developed on 40-acre density in the Peter’s Point Unit on the eastern side of the field, following testing and analysis of 40-acre pilots in 2007 and 2008. In 2008, we conducted 20-acre density pilots in the Prickly Pear unit on the western side of the field. The results of these pilots have proved encouraging and activity in 2010 will be on 20-acre density. As of December 31, 2009, we were in the process of drilling one gross (0.9 net) well and were waiting to complete 10 gross (9.5 net) wells in the West Tavaputs area.

With 3-D seismic, we also have 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 seven of eight wells drilled as of December 31, 2009. There was no activity in 2009 on the deeper structures and no activity is planned in 2010. We plan to re-visit the deep program following completion of the pending Environmental Impact Statement, or EIS.

Full development of the West Tavaputs area requires the completion of an EIS by the U.S. Bureau of Land Management, or BLM, which we initiated in February 2005. The Record of Decision, or ROD, approving the EIS that would authorize full development is still pending. In order to reduce litigation risk, we are working to resolve controversial aspects of the project prior to authorization. We expect the ROD to be obtained in the first half of 2010.

Blacktail Ridge/Lake Canyon

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 for a 50% working interest in wells drilled pursuant to the agreement. The Ute Tribe is subject to working interest adjustments in any infill drilling, pending its participation in previous acreage earning wells. By the end of 2008, we had drilled and commenced the drilling of 14 wells with an average working interest of 60.7%, thus fulfilling both our 2007 and 2008 drilling obligations.

In 2009, we negotiated with the Ute Tribe a suspension of the eight well drilling obligation for that year. One well of the 2009 obligation was drilled in 2008 and the remaining seven wells will now be drilled in 2012. In 2010 and 2011, we are obligated to drill eight wells in each year, with the first well of the 2010 obligation spud in late 2009. Also in the fourth quarter of 2009, we began completion operations on three wells remaining from the 2008 drilling program. Two of the wells were successfully completed and are currently being set up for production. The third well is now being analyzed to test shallower horizons or for use for water disposal. Completion results to date indicate we can successfully extend the known limits of the field as well as increase the well density inside the current field boundaries. As of December 31, 2009, we were in the process of drilling 1 gross (0.5 net) well within the Blacktail Ridge area.

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 had

 

7


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 the shallower Green River formations. The 2004 exploration and development agreement was amended in October of 2009 to allow for the suspension of the 2009 drilling schedule due to our inability to secure easements and permits to access the property. We are awaiting final approval of a further amendment of the 2004 exploration and development agreement that will provide for combined interests of the partners in all depths. When approved, this will allow the drilling of a single wellbore and commingling of production rather than have us and our industry partner drill separate wells, which should improve the economics of new wells. The Ute Tribe has an option to participate in a 25% working interest in wells drilled pursuant to the agreement. The amended agreement also will provide for us and our industry partner to drill at least four wells each in 2010 and two wells each from 2011 through 2015. As of December 31, 2009, we were not in the process of drilling any wells in the Lake Canyon area.

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, 2009—63.5 Bcfe.

 

   

Producing wells—We held interests in 722 gross producing wells as of December 31, 2009.

 

   

2009 net production—12.1 Bcfe.

 

   

Acreage—We held 62,025 net undeveloped acres as of December 31, 2009.

 

   

Capital expenditures—In 2009, our capital expenditures for the Powder River Basin were $13.9 million, which included participating in drilling 40 wells and acquisitions.

 

   

As of December 31, 2009, we were waiting to complete 6 gross (2.6 net) wells and waiting to hook up 11 gross (4.9 net) wells within the Powder River Basin.

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 coalbed well can range from five to 11 years depending on the coal seam.

Our natural gas production in this basin is gathered through 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 that 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, 2009—29.7 Bcfe.

 

   

Producing wells—We held interests in 127 gross producing wells as of December 31, 2009.

 

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2009 net production—8.4 Bcfe.

 

   

Acreage—We held 198,800 net undeveloped acres as of December 31, 2009.

 

   

Capital expenditures—For 2009, our operations in the Wind River Basin included recompletions and exploration drilling, and capital expenditures were $5.1 million.

 

   

As of December 31, 2009, we were not in the process of drilling or completing wells within the Wind River Basin.

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 Colorado Interstate Gas (“CIG”).

Cave Gulch

The Cave Gulch field is a combination structural play and 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 existing wellbores, owned and operated by us, out of the shallower Lance and Fort Union formations.

In January 2008, we signed a joint exploration agreement with two industry partners that provided for the drilling of at least two deep wells in 2008 on a partially promoted basis. The Cave Gulch 31-32 was drilled to 18,731 feet and tested approximately 1,000 Mcf/d from the Lakota and Muddy formations. The East Bullfrog 23-6 well was recently completed in the Muddy and Lakota formations. Outside this joint exploration area, we recompleted the Bullfrog 33-19 in the Frontier formation for an initial flow rate of approximately 7,000 Mcf/d.

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

 

   

Estimated proved reserves as of December 31, 2009—1.0 Bcfe.

 

   

Acreage—We held 295,276 net undeveloped acres as of December 31, 2009.

 

   

Producing wells—We held interests in seven gross producing, or capable of producing, wells as of December 31, 2009.

 

   

Capital expenditures—Our capital expenditures for 2009 for the Paradox Basin were $25.2 million for participation in the drilling of five gross wells.

 

   

As of December 31, 2009, we were not in the process of drilling or completing wells within the Paradox Basin.

Yellow Jacket

This prospect targets natural gas from the Gothic shale at depths of 4,500 to 6,500 feet. Through 2009, we had drilled four exploratory vertical science wells to gather rock property data, and eight horizontal well bores. Seven of these wells were on production at various times in 2009 with one well plugged due to the impact on completion of a cross-cutting fault that encountered hydrogen sulfide (“H2S”), a circumstance unique to this well. An impairment charge was taken at the end of 2009 due to the result of sub-economic performing wells that were completed using a less optimal fracture stimulation technique. In 2010, we intend to drill at least one horizontal exploratory test wells in an attempt to further delineate this prospect. We serve as operator in this area and have an average working interest of 55%.

 

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Green Jacket

This prospect targets natural gas from the Hovenweep shale at depths of 4,500 to 6,500 feet and is directly adjacent to our Yellow Jacket prospect. We drilled one vertical science well in 2008, which was immediately converted into a horizontal wellbore. This well was production tested in early 2009 and is now waiting on pipeline connection. We plan no drilling activity in this project in 2010 as we refine our completion techniques at our Yellow Jacket prospect. We serve as operator in this area where we have a working interest of 100%.

Other Exploration Prospects

In addition to the exploration prospects described above, the following is a description of activities that occurred during 2009 and that are planned for 2010 for the following plays. Historically we have assembled large acreage positions and recovered our costs by selling an interest to industry partners. We typically retained at least a 50% interest and operatorship. As of December 31, 2009, we were not in the process of drilling within any of these prospects.

Uinta Basin

Hook

Hook is a shale gas prospect in the southwestern portion of the Uinta Basin in which we have a 50% working interest in 29,531 net acres in the deep Manning Canyon. Although evaluation continues, in 2009, we recorded dry hole expenses with respect to four wells drilled to various formations in this area. Evaluation also continues on the Moenkopi formation, which is oil productive in an adjacent field. In 2010, we plan to reduce our working interest in this prospect in exchange for additional non-budgetary work activity by a third party.

Paradox Basin

Salt Flank

We have an 80% working interest in our Salt Flank exploration prospect where we are targeting gas fields in stratigraphic and structural traps located on the flanks of salt diapirs. Our first exploration well was tested in 2009 and declared a dry hole due to insufficient gas volumes. We are marketing part of our working interest in this project and further drilling activity in 2010 will be dependent on the outcome of this sell down effort.

Montana Overthrust

We serve as operator and have a 50% working interest in this prospect in southwestern Montana that targets the Cody shale. We held 165,667 net undeveloped acres as of December 31, 2009. Six exploration wells have been drilled, none of which tested commercial levels of hydrocarbons. These wells were expensed in 2009. We are marketing part of our working interest in this project and any further testing or drilling activity will be dependent on the outcome of this sell down effort.

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. Our working interest in this project is 50%. We held 58,367 net undeveloped acres at December 31, 2009. In 2009, we spent $1.5 million for exploration drilling in the Big Horn Basin. In 2008, we drilled and ran casing on one well to a depth of 10,705 feet in order to test the Fort Union formation. This well was tested in 2009 and declared a dry hole due to insufficient gas volumes. We are marketing part of our working interest in this project, and any further drilling activity will depend on the outcome of this sell down effort.

 

10


Laramie Basin

We participated in the drilling and testing of a 7,678 foot vertical well in the Niobrara oil prospect in southeastern Wyoming during the fourth quarter of 2009. Flow rates from the well were not significant and the well was declared a dry hole. Because of the nature of the earning arrangement for this project there was no associated acreage. We have no further plans for this prospect.

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, 2009, 2008 and 2007 based on reserve reports prepared by us and audited in their entirety by outside independent third party petroleum engineers. While we are not required by the SEC or accounting regulations or pronouncements to have our estimates independently audited, we are required by our revolving credit agreement with our lenders to have an independent third party engineering firm perform an annual audit of our estimated reserves. All of our proved reserves included in our reserve reports are located in North America. Netherland, Sewell & Associates, Inc., or NSAI, audited all of our reserves estimates at December 31, 2009, 2008 and 2007. 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 third party petroleum engineers. However, in the aggregate, the independent third party 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,
     2009    2008    2007

Proved Reserves:

        

Proved Developed Reserves:

        

Natural gas (Bcf)

   455.3    416.6    317.3

Oil (MMBbls)

   4.1    3.1    2.1
              

Total proved developed reserves (Bcfe)(1)

   480.2    435.1    329.8

Proved Undeveloped Reserves:

        

Natural gas (Bcf)

   462.7    367.8    221.0

Oil (MMBbls)

   3.6    2.6    1.1
              

Total proved undeveloped reserves (Bcfe)(1)

   484.6    383.2    227.8
              

Total Proved Reserves (Bcfe)(1)

   964.8    818.3    557.6
              

 

(1) Total does not add because of rounding.

The data in the above table represent 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 reserves estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserves estimates may vary from the quantities of oil and natural gas that are ultimately recovered. See “Item 1A. Risk Factors.”

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

 

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those locations on development spacing areas that are directly offsetting economic producers that are reasonably certain of economic production when drilled. Proved undeveloped reserves for other undrilled development spacing areas can be claimed only where it can be demonstrated with reasonable certainty that there is continuity of economic production from the existing productive formation.

At December 31, 2009, our proved undeveloped reserves were 484.6 Bcfe. At December 31, 2008, our proved undeveloped reserves were 383.1 Bcfe. During 2009, 82.5 Bcfe or 22% of our December 31, 2008 proved undeveloped reserves (71 wells) were converted into proved developed reserves requiring $81.7 million of drilling and completion capital and $9.5 million of facilities capital. An additional 7 Bcfe were removed from the proved undeveloped reserves category because they exceeded the five year limit for proved undeveloped reserves, 29.3 Bcfe were added to the proved undeveloped reserves category due to engineering revisions primarily resulting from increased performance in Gibson Gulch and 28.5 Bcfe were sub-economic and were removed from the proved undeveloped reserves category due to the pricing change from $4.60 per MMBtu CIG at December 31, 2008 to $3.04 per MMBtu at December 31, 2009. The proved undeveloped reserves from December 31, 2008 that remain in the proved undeveloped reserves category at December 31, 2009 are 294.4 Bcfe. The December 31, 2009 proved undeveloped reserves of 484.6 Bcfe result from adding the December 31, 2008 remaining proved undeveloped reserves (294.4 Bcfe) to the proved undeveloped reserves generated in 2009 (190 Bcfe).

The majority of production from the Gibson Gulch area of the Piceance Basin is from the discontinuous fluvial sands of the Williams Fork formation. This is a very large, basin-centered gas accumulation containing reservoirs with no apparent downdip water. The resource is consistent across the Gibson Gulch area and results in low variability of estimated ultimate recoveries. Reasonable certainty for economic undeveloped reserves located one and two development spacing areas from economic producers is supported by geologic, engineering and economic data in addition to well productivity across the area and across the basin. New technologies were not used to support these reserves. The opportunity to use this data to prove more than one direct offset from economic producers is the result of a change in definition for undeveloped oil and gas reserves included in the SEC’s “Modernization of Oil and Gas Reporting” and applied in our December 31, 2009 reserve report. The proved undeveloped reserves added in Gibson Gulch at December 31, 2009 were 170.0 Bcfe, of which 86.3 Bcfe are attributed to the addition of a second offsetting proved undeveloped spacing areas from economic producers.

At December 31, 2009, we revised our proved reserves upward by 101.5 Bcfe, excluding pricing revision, due to improved production performance in Gibson Gulch, West Tavaputs and Blacktail Ridge and the increased revenue associated with the recovery of NGL and reduced drilling and completion costs in Gibson Gulch area. Also included in the engineering revisions is the addition of 64 Bcfe from second proved undeveloped spacing areas added in Gibson Gulch. The total reserves from the second spacing areas in Gibson Gulch is 86.3 Bcfe, of which 64 Bcfe is in the engineering revision category and 22.3 Bcfe is in the extension and discoveries category resulting from drilling and completion operations in 2009.

At December 31, 2008, we revised our 2008 year-end proved reserves upward by 146.4 Bcfe, excluding pricing revisions, primarily as a result of adding increased density proved undeveloped locations in the Piceance Basin and West Tavaputs area and improved production performance by wells located in each of our major producing basins: Wind River, Uinta, Powder River and Piceance.

At 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 area and continued improved performance of wells drilled in the West Tavaputs area and Piceance Basin.

We use our internal reserves estimates rather than the estimates from independent third party 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 third party engineers. We use our internal reserves estimates on all properties regardless of the

 

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positive or negative variance to the independent third party 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 third party engineers. These differences are investigated by us and the independent third party engineers and discussed with the independent third party 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.

The internal review process of our wells and the related reserves estimates, and the related internal controls we utilize, includes but is not limited to the following:

 

   

A comparison is made and documented of actual and historical data from our production system to the data in the reserve database. This ensures the accuracy of the production data, which supplies the basis for forecasting.

 

   

A comparison is made and documented of land and lease record to interest data in the reserve database. This ensures that the costs and revenues will be properly determined in the reserves estimation.

 

   

A comparison is made of the historical costs (capital and expenses) to the capital and lease operating costs in the reserve database. Documentation lists reasons for deviation from direct use of historical data. This ensures that all costs are properly included in the reserve database.

 

   

A comparison is made of input data to data in the reserve database of all property acquisitions, disposals, retirements or transfers to verify that all are accounted for accurately.

 

   

Pricing for the first flow day of every month is collected from Platts Gas Daily and Plains All American Pipeline, L.P. At the end of the fiscal year, the 12-month average prices are determined. A similar collection process occurs with pricing deductions supplied by our internal marketing group, and a 12-month average is calculated at the fiscal year end. A comparison is made of our determination of SEC pricing requirements to that supplied by the third party independent engineering firm. This provides verification of the pricing calculations.

 

   

A final check is made of all economic data inputs in the reserve database by comparing them to documentation provided by our internal marketing, land, accounting, production and operations groups. This provides a second check to ensure accuracy of input data in the reserve database.

 

   

Accurate classification of reserves is verified by comparing independent classification analyses by our internal reservoir engineers and the third party independent engineers. Discrepancies are discussed and differences are jointly resolved.

 

   

Internal reserves estimates are reviewed by well and by area by the Senior Vice President—Planning and Reserves. A variance by well to the previous year-end reserve report is used as a tool in this process. This review is independent of the reserves estimation process.

 

   

Reserves variances are discussed among the internal reservoir engineers and the Senior Vice President—Planning and Reserves. The reservoir engineers do not report to the Senior Vice President—Planning and Reserves, which lessens any incentive to over estimate reserves because the reservoir engineer’s annual evaluations are not conducted by the Senior Vice President—Planning and Reserves.

 

   

Our internal reserves estimates are reviewed by senior management prior to publication.

Within our Company, the technical person primarily responsible for overseeing the preparation of the reserves estimates is Ms. Lynn Boone Henry. Ms. Henry is our Senior Vice President—Planning and Reserves and has been responsible for the reserves since 2003. Ms. Henry attended the Colorado School of Mines and graduated in 1982 with a Bachelor of Science degree in Chemical and Petroleum Refining Engineering. She attended the University of Oklahoma and graduated in 1985 with a Master of Science degree in Petroleum Engineering. Ms. Henry has been involved in evaluations and the estimation of reserves and resources for 23 years. She has managed the technical reserve process at a company level for nine years.

 

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The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the technical person primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein is Mr. Dan Paul Smith. Mr. Smith has been practicing consulting petroleum engineering at NSAI since 1980. He is a Registered Professional Engineer in the State of Texas (License No. 49093) and has over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering.

NSAI performed a well-by-well audit of all of our properties and of our estimates of proved reserves and then provided us with its audit report concerning our estimates. The audit completed by NSAI, at our request, is a collective application of a series of procedures performed by NSAI. These audit procedures may be the same or different from audit procedures performed by other independent third party engineering firms for other oil and gas companies. NSAI’s audit report does not state the degree of its 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, 2009, the total proved reserves estimate provided by NSAI was 1.2% below our reserves estimate. At the field level, NSAI’s reserves estimates ranged between 2.6% above our internal reserves estimates to 9.6% below our estimates. NSAI arrived at reserves estimates that were greater than 10% above or 10% below our internal estimates for approximately 59% of our wells. This represents approximately 63% of the total proved reserves covered in the audit report. At the material property level, NSAI’s reserves estimates ranged between 8.8% above our internal reserves estimates to 6.4% below our estimates in the year-end 2009 report. For the year ended December 31, 2008, the estimate provided by NSAI was 6.3% below our internal reserves estimate. For the year ended December 31, 2007, the estimate provided by NSAI’s was 4.5% above our internal reserves estimate.

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

 

   

For the reserves 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.

 

14


   

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

 

   

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

 

   

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

The reserves audit 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. The audit letter also includes a statement of dates pertaining to the NSAI work performed, the methodology used, the assumptions made and a discussion of uncertainties that they believe are inherent in reserves estimates.

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 to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. NSAI and its respective employees have no interest in those properties, and the compensation for these engagements is not contingent on NSAI’s estimates of reserves and future cash inflows for the subject properties. During 2009 and 2008, we paid NSAI approximately $215,000 and $220,000, respectively, for auditing our reserves estimates. We did not employ NSAI for other consulting services during either year.

On December 31, 2008, the SEC published final rules and interpretations updating its oil and gas reserves reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management system, which is a widely accepted set of evaluation guidelines that are designed to support assessment processes throughout the resource asset lifecycle. These guidelines were prepared by the Society of Petroleum Engineers, or SPE, Oil and Gas Reserves Committee with cooperation from many industry organizations. One of the key changes to the previous SEC rules relates to using a 12-month average commodity price to calculate the value of proved reserves versus the former method of using year-end prices. Other key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, the opportunity to establish proved undeveloped reserves without the requirement of an adjacent producing well and permitting disclosure of probable and possible reserves. Companies were required to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009. Early adoption was not permitted. The new disclosure requirements were effective for this filing. Changes in our reserves estimates, compared with the methodology used in 2008 based on the prior SEC rules, include:

 

   

Commodity prices used to calculate reserves apply the simple 12-month average of the 2009 first day of the month CIG natural gas price, or $3.04 per MMBtu, and 12-month average WTI oil price, or $57.65 per barrel, rather than the year-end prices prescribed by the prior method. Under the prior method, commodity prices used to calculate reserves would have been $5.54 per MMBtu for CIG natural gas and $76.00 per barrel for WTI oil. The effect of the new methodology on the reserves at December 31, 2009 was a reduction of 62 Bcfe and a reduction in present value (at a 10% annual discount) of future net cash flows of $1.7 billion compared to the prior SEC methodology.

 

   

The new guidelines have expanded the definition of proved undeveloped reserves that can be booked from an economic producer. The opportunity to prove reasonable certainty for spacing areas located

 

15


 

more than one direct development spacing area from economic producers allowed for 86.3 Bcfe of additional proved reserves for our Gibson Gulch property. These reserves are supported by geologic, engineering and economic data in addition to well productivity across our property and across the basin.

 

   

The new guidelines limit the recording of proved undeveloped reserves to those reserves that are scheduled to be developed within five years, which had a nominal impact of reducing our reserves by 7 Bcfe.

Production and Price History

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

 

     Year Ended December 31,
     2009    2008    2007

Production Data:

        

Natural gas (MMcf)

     85,485      73,623      57,678

Oil (MBbls)

     710      661      586

Combined volumes (MMcfe)

     89,745      77,589      61,194

Daily combined volumes (MMcfe/d)

     245.9      212.0      167.7

Average Prices(1):

        

Natural gas (per Mcf)

   $ 6.96    $ 7.61    $ 5.89

Oil (per Bbl)

     59.03      69.55      59.87

Combined (per Mcfe)

     7.10      7.81      6.13

Average Costs ($ per Mcfe):

        

Lease operating expense

   $ 0.52    $ 0.57    $ 0.68

Gathering, transportation and processing expense

     0.63      0.51      0.38
                    

Total Production costs excluding production taxes

   $ 1.15    $ 1.08    $ 1.06

Production tax expense

     0.15      0.57      0.37

Depreciation, depletion and amortization(2)

     2.83      2.66      2.87

General and administrative(3)

     0.42      0.52      0.52

 

(1) Includes the effects of hedging transactions, which increased average natural gas prices by $3.10, $0.56 and $1.52 per Mcf in 2009, 2008 and 2007, respectively, and increased average oil price by $9.47 per Bbl in 2009, while reducing average oil prices by $13.72, and $1.31 per Bbl in 2008 and 2007, respectively.
(2) The depreciation, depletion and amortization, or DD&A, per Mcfe for the years ended December 31, 2009 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.
(3) General and administrative expense presented herein excludes non-cash stock-based compensation of $16.5 million, $16.8 million and $10.2 million for the years ended December 31, 2009, 2008 and 2007, respectively, which equates to a reduction to general and administrative expense of $0.18 per Mcfe, $0.22 per Mcfe and $0.17 per Mcfe, respectively. General and administrative expense excluding non-cash stock-based compensation is a non-GAAP measure. Non-cash stock-based compensation is combined with general and administrative expense for a total of $54.4 million, $57.2 million and $42.2 million for the years ended December 31, 2009, 2008 and 2007, respectively, in the Consolidated Statements 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, which 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, 2009 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

   182.0    168.1    16.0    11.7

Piceance

   532.0    490.4    —      —  

Powder River

   677.0    437.2    45.0    9.3

Wind River

   127.0    116.2    —      —  

Other

   6.0    3.2    —      —  
                   

Total

   1,524.0    1,215.1    61.0    21.0
                   

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2009 relating to our leasehold acreage.

 

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

Basin/Area

          

Uinta

   31,067    25,505    265,157      182,217 (3) 

Piceance

   8,322    6,901    52,725 (4)    46,653 (4) 

Powder River

   81,904    52,708    106,548      62,025   

Wind River

   7,197    5,613    261,432      198,800   

Big Horn

   801    374    125,671      58,367   

Paradox

   8,892    4,983    519,652      295,276   

Green River

   —      —      49,802      49,483   

Montana Overthrust

   —      —      388,652      165,667   

Utah Hingeline

   —      —      26,378      18,411   

Other

   1,361    1,045    196,190      174,077   
                      

Total

   139,544    97,129    1,992,207      1,250,976 (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 104,683 net undeveloped acres that are subject to drill-to-earn agreements are not included.
(4) Includes 40,132 gross and 36,281 net acreage associated with the Cottonwood Gulch property.

 

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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 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, EIS or related legal challenge. The following table sets forth, as of December 31, 2009, 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, 2010

   271,176    125,717

December 31, 2011

   254,311    123,308

December 31, 2012

   191,462    116,684

December 31, 2013

   210,970    124,886

December 31, 2014 and later(1)

   1,064,288    760,381
         

Total

   1,992,207    1,250,976
         

 

(1) Includes 285,811 gross and 196,254 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,
2009
(1)
   Year Ended
December 31,
2008
(1)
   Year Ended
December 31,
2007
(1)
     Gross    Net    Gross    Net    Gross    Net

Development

                 

Productive

   265.0    236.1    196.0    176.6    227.0    180.4

Dry

   —      —      —      —      1.0    0.5

Exploratory

                 

Productive

   6.0    3.0    17.0    12.0    4.0    2.6

Dry(2)

   14.0    9.5    —      —      6.0    2.5
                             

Total

                 

Productive

   271.0    239.1    213.0    188.6    231.0    183.0

Dry

   14.0    9.5    —      —      7.0    3.0

 

(1) The table reflects the revised SEC oil and gas disclosure rules.
(2) The exploratory dry hole category for the period ended December 31, 2008 excludes two scientific wells that were drilled for data gathering purposes that are included in exploration expense in the Consolidated Statement of Operations.

Operations

General

In general, we serve as operator of wells in which we have a greater than 50% working interest. In addition, we seek to be operator of wells in which we have lesser interests. As operator, we obtain regulatory authorizations,

 

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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 the majority of the other oil field service equipment used for drilling or maintaining wells on the properties we operate. Independent contractors engaged by us provide the majority 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 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.

During 2009, Sempra Energy Trading Corporation, Enterprise Gas Processing, LLC and Encana Oil & Gas accounted for 14.9%, 10.4% and 9.6%, respectively, of our oil and gas production revenues. During 2008, EnCana Oil & Gas and Sempra Energy Trading Corporation accounted for 16.7% and 16.6%, respectively, of the our oil and gas production revenues. During 2007, Sempra Energy Trading Corporation, EnCana Oil & Gas and United Energy Trading accounted for 20.6%, 15.7% and 8.7%, respectively, of the our oil and gas production revenues.

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

Our natural gas is 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, Uinta, Powder and Paradox Basins to process our natural gas. We also may enter into firm sales agreements to ensure that we are selling to a purchaser that has contracted for pipeline capacity. These agreements are subject to the limitations discussed above in this paragraph.

Our oil production is collected in tanks and sold to third parties that collect the oil in trucks and transport it to refiners. We sell our oil production to a variety of purchasers under monthly, annual or multi-year terms. Our oil contracts are priced either off of NYMEX or area oil posting with location or transportation differentials. We contract only for volumes that have been produced.

 

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The following table sets forth information about material long-term firm transportation contracts for pipeline capacity and firm processing contracts, both of which typically require a demand charge and firm sales contracts. We have met all established commitments during the three year period ended December 31, 2009. We source the gas to meet these commitments from our producing properties. At the time we entered into these commitments, we estimated that our production, and the production of joint interest owners that we market, would be sufficient to meet these commitments.

 

Type of Arrangement

  

Pipeline System / Location

   Gross Deliveries
(MMBtu/d)
    Term

Firm Sales

   White River Hub    15,000      04/10 – 03/12

Firm Sales

   White River Hub    15,000      02/10 – 03/12

Firm Sales

   Rockies Express    15,000      01/10 – 03/12

Firm Sales

   Rockies Express    25,000      11/09 – 10/10

Firm Sales

   Meeker    15,000      12/09 – 10/10

Firm Sales

   Questar Pipeline    5,000      04/09 – 03/11

Firm Sales

   Rockies Express    10,000      04/09 – 03/11

Firm Sales

   Cheyenne Hub    7,500      11/08 – 08/11

Firm Sales

   Cheyenne Hub    7,000      11/08 – 10/11

Firm Transport

   WIC Medicine Bow    5,000      06/08 – 03/14

Firm Transport

   WIC Medicine Bow    30,000      11/07 – 03/15

Firm Transport

   WIC Medicine Bow    25,000      07/09 – 06/19

Firm Transport

   WIC Medicine Bow    8,300 (1)    12/08 – 06/13

Firm Transport

   WIC Kanda    15,000      12/08 – 11/23

Firm Transport

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

Firm Transport

   Questar Pipeline    25,000      01/07 – 12/16

Firm Transport

   Cheyenne Plains    9,000      02/05 – 04/17

Firm Transport

   Cheyenne Plains    5,000      05/17 – 04/18

Firm Transport

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

Firm Transport

   Rockies Express    25,000      01/08 – 11/19

Firm Transport

   Questar Gas    70,000      06/09 – 05/20

Firm Processing

   Questar Gas    70,000      06/09 – 05/20

Firm Processing

   Questar Pipeline    50,000      08/06 – 08/16

 

(1) As the required deliveries vary by month, amount presented represents the annual average over the term of the contract.

Hedging Activities

We have an active commodity hedging program to mitigate the risks of the volatile prices of natural gas, NGL and oil. Typically, we intend to hedge approximately 50-70% of our oil and natural gas production on a forward 12-month basis using a combination of swaps, cashless collars and other financial derivative instruments with counterparties that we believe are creditworthy. For additional information on our hedging activities, see “Item 7A. 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 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

 

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burden of existing, and any changes to, federal, state, local and Native American tribal laws and regulations more easily than we can, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will depend on 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 that 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 cool summers sometime lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during lower demand periods. 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;

 

   

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.

 

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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 permitting, 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, 2009, 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 that could have a material impact on the oil and natural gas exploration and production industry and our business 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 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 EIS that is 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 such as we are incurring at our West Tavaputs area. 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 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, or 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

 

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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, could 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. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development.

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. EPA has recently deemed carbon dioxide (“CO2”) to be a public danger which presumably will lead to regulation in a manner similar to other pollutants. EPA has recently initiated rulemaking for inventory of CO2 and other greenhouse gases. 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.

Climate Change. 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 not passed 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 currently adversely impacted by current state and local climate 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. However, future laws or regulations could result in substantial expenditures or reduced demand for oil or natural gas.

Homeland Security. 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

 

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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, federal, state, local, 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;

 

   

wildlife management and protection;

 

   

property mitigation measures;

 

   

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 that 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 NGL 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 or 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 that 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 transporting 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 enact and 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 January 29, 2010, we had 262 full time equivalent employees of whom 149 work in our Denver office and 113 work in our 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 are 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, 2009, 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 we lease field offices in Gillette, Wyoming and Cortez, Colorado. 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 or deemed to be part of this Annual Report on Form 10-K.

Annual CEO Certification

As required by New York Stock Exchange rules, on June 1, 2009 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 or CBM. Natural gas formed as a byproduct of the coal formation process, which is trapped in coal seams and produced by nontraditional means.

Completion. Installation of permanent equipment for production of oil and gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

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

Delineation. The process of drilling wells away from, or that is removed from, a known point of well control.

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.

 

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Dry hole or Dry well. An exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Environmental Assessment or EA. A study that can be required pursuant to federal law prior to drilling a well.

Environmental Impact Statement or EIS. 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 a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

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.

H2S. Hydrogen sulfide.

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.

 

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

NGL. Natural Gas Liquids.

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. An exploratory, development, or extension well that is not a dry well.

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 or PDP. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from know reservoirs, and under existing economic conditions, operating methods, and government regulations.

Proved undeveloped reserves or PUD. Reserves of any category 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.

Record of Decision or ROD. A document that authorizes or denies the activity analyzed by an Environmental Impact Statement and provides the basis for this decision.

Resource Management Plan or RMP. A document that describes the Bureau of Land Management’s intended uses of lands that are under its jurisdiction.

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.

Shale gas. Considered to be an unconventional accumulation of natural gas where the gas is recovered from extremely low permeability shales, generally through the use of horizontal drilling and massive hydraulic fracturing.

 

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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.

Structural Play. An accumulation of oil and gas in rock strata that has been folded or faulted.

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.

 

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;

 

   

economic conditions in the United States, and the level of consumer product demand;

 

   

weather conditions;

 

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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.

The recent U.S. and global economic recession could have a material adverse effect on our business and operations.

Any or all of the following may occur as a result if the recent crisis in the global financial and securities markets returns:

 

   

We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. This would lead to lower growth in our production and reserves than if we were able to spend more than our cash flow. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.

 

   

The economic slowdown has led and could continue to lead to lower demand for oil and natural gas by individuals and industries, which in turn has resulted and could continue to result in lower prices for the oil and natural gas sold by us, lower revenues and possibly losses.

 

   

The lenders under our revolving credit facility may become more restrictive in their lending practices or unable or unwilling 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 reserves growth, leading to declining production and possibly losses.

 

   

The losses incurred by financial institutions as well as the bankruptcy of some financial institutions heightens the risk that a counterparty to our hedge arrangements could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially adversely affected.

 

   

Our credit facility bears floating interest rates based on the London Interbank Offer Rate, or LIBOR. As banks were reluctant to lend to each other to avoid risk, LIBOR increased to unprecedented spread levels in 2008. This causes higher interest expense for unhedged levels of LIBOR-based borrowings.

 

   

Our credit facility requires the lenders to redetermine our borrowing base semi-annually. The redeterminations are based on our proved reserves and hedge position based on price assumptions that our lenders require us to calculate reserves pursuant to the credit facility. It is feasible that the lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base and our borrowing base could be reduced. This would reduce our funds available to borrow.

 

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Pipeline companies may be unable to obtain funding for new pipelines, leading to an increased inability to transport gas out of our operating areas in the Rocky Mountains to markets with higher demand and higher prices. As a result, we could be faced with lower prices in the Rocky Mountain region due to increasing supplies and lower demand in the region compared to more populated and more heavily industrialized areas with higher demand. This would result in lower revenues for us and possibly losses.

 

   

Bankruptcies of financial institutions or illiquidity of money market funds may limit or delay our access to our cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis that were previously funded from our money market deposits.

 

   

Bankruptcies of purchasers of our natural gas and oil could lead to the delay or failure of us to receive the revenues from those sales.

Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, 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 and debt 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, natural gas and NGL are sold;

 

   

our ability to acquire, locate and produce new reserves;

 

   

global credit and securities markets; and

 

   

the ability and willingness of lenders and investors to provide capital and the cost of that capital.

If our revenues or the borrowing base under our 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 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 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.

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

Our drilling activities subject us 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 or other features;

 

   

pressures;

 

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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, 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 coalbeds 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. Coalbeds, 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 life of a coalbed well typically can range from five to 11 years depending on the coal seam compared to up to 30 years for a non-coalbed 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.

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.

Underground accumulations of oil and natural gas cannot be measured 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.

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

 

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revision based on average first of month prices of $3.04 per MMBtu of gas and $57.65 per barrel of oil as required under new SEC oil and gas disclosure rules, relative to year-end 2008 prices of $4.61 per MMBtu and $41.00 per barrel of oil required under former SEC rules, was downward 42.8 Bcfe.

We prepare our own estimates of proved reserves, which are audited by independent third party petroleum engineers. Over time, our internal engineers may make material changes to reserves 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—15. 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. 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 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. 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 or impacted by nearby coal mining activities.

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. In addition, activities related to the mining of coal near our operations, including core-hole drilling to determine the aerial extent of coal deposits and the mining of coal, may introduce oxygen into our producing wells and compressors, causing production to be shut-in, or allow hydrocarbons to escape before they can be recovered. This would lead to a loss of reserves and revenues.

 

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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.

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 and the amount of hydrocarbons. 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 choose 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.

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.

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 and the recording of proved reserves.

Our exploration, development, production and marketing operations are subject to extensive environmental regulation at the federal, state and local levels including those governing emissions to air, wastewater discharge, hazardous and disposable wastes, remediation of soil and groundwater contamination and protection of natural resources. 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

 

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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 produced groundwater into adjacent lands and waterways. 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 requirements for 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 pollution control and/or remediation, all of which could have a material adverse effect on our financial condition or results of operations.

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, such as our delayed EIS in the West Tavaputs area and delays related to the lawsuit challenging the BLM’s issuance of the leases in our Cottonwood Gulch prospect in the Piceance Basin, 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. In addition, if we do not reasonably believe that we can obtain the drilling permits covering locations for which we recorded proved undeveloped reserves in a timely fashion, we may be required to write down the level of our proved reserves. 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, larger operating areas and other aspects of their businesses. 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 regulatory changes could limit our Colorado operations and adversely affect our cost of doing business.

Our future Rocky Mountain operations and cost of doing business may be affected by changes in regulations and the ability to obtain drilling permits. Our properties located in Colorado are subject to the authority of the Colorado Oil and Gas Conservation Commission, or COGCC. The COGCC recently approved new rules governing oil and gas activity. The costs of these and the other proposed rules could add substantial increases in incremental well costs in our Colorado operations. The rules could also impact the ability and extend the time necessary to obtain drilling permits, which creates substantial uncertainty about our ability to meet future drilling plans and thus production and capital expenditure targets. It is also possible that similar rules will be proposed in the other states in which we operate, further impacting our operations.

 

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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 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, weather, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells.

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.

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 remaining properties for reserve potential. 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.

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 our 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.

 

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

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of commodities, we currently, and will likely in the future, enter into hedging arrangements for a portion of our production revenues. Hedging arrangements for a portion of our production revenues expose us to the risk of financial loss in some circumstances, including when:

 

   

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

 

   

the counterparty to the hedging contract defaults on its contractual obligations.

In addition, these types of hedging arrangements limit the benefit we would receive from increases in commodities prices and may expose us to cash margin requirements if we hedge with counterparties who are not parties to our credit facility.

Our counterparties are typically financial institutions, who are lenders under our credit facility. The risk that a counterparty may default on its obligations is heightened by the recent financial sector crisis and other 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 production revenues, 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. Recent economic circumstances may further increase these risks.

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.

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

Our revolving credit facility has commitments from 17 lenders. With the recent turbulent credit markets, the lenders may become more restrictive in their lending practices or unable to fund their commitments, which

 

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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 reserves growth, leading to declining production and potentially losses.

We face risks related to rating agency downgrades.

If one or more rating agencies downgrades our outstanding debt, raising capital will become more difficult and more costly and we may be required to provide collateral or other credit support to pipeline companies or other parties. Providing credit support increases our costs and can limit our liquidity.

Possible additional 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” including carbon dioxide and methane, may be contributing to warming of the Earth’s 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. EPA has initiated rulemaking pertaining to 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.

Various proposed Federal legislation initiatives may decrease our ability, and increase the cost, to enter into hedge transactions.

Various measures are being proposed by Congress that would further regulate hedging transactions. This legislation could make it more difficult and costly for us to enter into hedging transactions by requiring that we post collateral to a central clearing exchange. Because we currently enter into hedges with counterparties that are affiliated with lenders under our Amended Credit Facility, we are not required to post collateral for those transactions. If we are required to post collateral, we would have to do so by utilizing cash or letters of credit, which would reduce our liquidity position and increase costs. Decreasing our ability to enter into hedging transactions would expose us to additional risks related to commodity price volatility and impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and therefore decreases in future production and reserves. Proposed legislation may also limit the ability of the lenders under our Amended Credit Facility to engage in the derivative transactions that we use for our hedge program.

Risks Relating to Taxes

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and gas exploration and development are eliminated as a result of future legislation.

There are various proposals to eliminate certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. These changes include (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling

 

39


and development costs, (iii) the elimination of the deduction for certain U.S. production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. The passage of any legislation as a result of the budget proposal, the Senate bill or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development. Any such change could negatively impact our financial condition and results of operations by increasing the costs we incur which would in turn make it uneconomic to drill some prospects if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

Risks Related to Our Common Stock

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. and Warburg Pincus Private Equity X, L.P. collectively own approximately 13.6% of our outstanding common stock. Accordingly, these related stockholders may be able to influence 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.

Furthermore, conflicts of interest could arise in the future between us and Warburg Pincus concerning, among other things, potential competitive business activities or business opportunities. None of our 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.

 

40


Risks Relating to our Senior Notes and Convertible Notes

We may not be able to generate enough cash flow to meet our debt obligations, including our obligations and commitments under our senior notes, our convertible notes and our revolving credit facility.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may be insufficient to meet our debt obligations and commitments, including our notes, our convertible notes and our revolving credit facility. Any insufficiency could negatively impact our business. A range of economic, competitive, business, and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to repay our debt, including the notes. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

As of December 31, 2009, the total outstanding principal amount of our long term indebtedness was approximately $402 million, and we had approximately $588 million in additional borrowing capacity under our revolving credit facility, which, if borrowed, would be secured debt effectively senior to the notes and convertible notes to the extent of the value of the collateral securing that indebtedness. The revolving credit facility has $592.8 million in commitments. The borrowing base is dependent on our proved reserves and was, as of December 31, 2009, $630 million based on our June 30, 2009 proved reserves and hedge position.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

 

   

refinancing or restructuring our debt;

 

   

selling assets;

 

   

reducing or delaying capital investments; or

 

   

seeking to raise additional capital.

However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

Our debt could have important consequences. For example, it could:

 

   

increase our vulnerability to general adverse economic and industry conditions;

 

   

limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt;

 

   

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

 

   

impair our ability to obtain additional financing in the future; and

 

   

place us at a competitive disadvantage compared to our competitors that have less debt.

In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders and holders of our existing convertible notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.

 

41


Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions.

Our revolving credit facility contains a number of significant covenants in addition to covenants restricting the incurrence of additional debt. Our revolving credit facility requires us, among other things, to maintain certain financial ratios or reduce our debt. These restrictions also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indenture governing the notes and our revolving credit facility impose on us.

Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine 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 currently 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 mandatory principal prepayments required under the credit facility.

A breach of any covenant in our revolving credit facility or the agreements and indentures governing our other indebtedness would result in a default under that agreement or indenture after any applicable grace periods. A default, if not waived, could result in acceleration of the debt outstanding under the agreement and in a default with respect to, and an acceleration of, the debt outstanding under other debt agreements. The accelerated debt would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such debt. Even if new financing were available at that time, it may not be on terms that are acceptable 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 EPA that was settled during the quarter ended December 31, 2009. 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. In September 2008, we entered into a consent decree with the EPA pursuant to which we and our industry partner agreed to pay a fine of $240,000, of which we agreed to pay $140,000. The consent decree was approved by the United States federal court for the District of Utah on November 13, 2009.

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.

 

42


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

2009

     

First Quarter

   $ 25.40    $ 17.08

Second Quarter

     36.27      21.51

Third Quarter

     34.41      24.40

Fourth Quarter

     37.81      26.78

2008

     

First Quarter

   $ 51.20    $ 36.26

Second Quarter

     60.43      47.02

Third Quarter

     60.87      29.43

Fourth Quarter

     32.11      14.93

On January 29, 2010, the closing sales price for our common stock as reported by the NYSE was $31.00 per share.

Holders. On January 29, 2010, the number of holders of record of common stock was 407.

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 Amended 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. We did not have any issuer purchases of equity securities in the quarter ended December 31, 2009.

 

43


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 31, 2004, and $100 was invested in each of the Standard & Poors 500 Index and the Standard & Poors MidCap 400 Index-Energy Sector at the closing price on December 31, 2004.

 

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

LOGO

 

     December 31,
2004
   December 31,
2005
   December 31,
2006
   December 31,
2007
   December 31,
2008
   December 31,
2009

BBG

   $ 100.00    $ 120.69    $ 85.06    $ 130.88    $ 66.05    $ 97.25

S&P MidCap 400- Energy

   $ 100.00    $ 152.01    $ 154.97    $ 218.90    $ 93.27    $ 170.97

S&P 500

   $ 100.00    $ 103.00    $ 117.03    $ 121.16    $ 74.53    $ 92.01

 

Item 6. Selected Financial Data

The following table presents our selected historical financial data for the years ended December 31, 2009, 2008, 2007, 2006 and 2005. 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 consolidated 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.

 

44


Selected Historical Financial Information

The consolidated income statement information for the years ended December 31, 2009, 2008 and 2007 and the balance sheet information as of December 31, 2009 and 2008 are derived from our audited financial statements included elsewhere in this report. The income statement information for the years ended December 31, 2006 and 2005 and the balance sheet information at December 31, 2007, 2006 and 2005 are 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,  
     2009     2008     2007     2006     2005  
     (in thousands, except per share data)  

Statement of Operations Data:

          

Production revenues(1)

   $ 647,839      $ 605,881      $ 374,956      $ 344,127      $ 284,406   

Commodity derivative gain (loss)

     (54,567     7,920        —          —          —     

Other revenues

     4,891        4,110        15,314        31,202        4,353   
                                        

Total operating and other revenues

     598,163        617,911        390,270        375,329        288,759   

Operating expenses:

          

Lease operating expense

     46,492        44,318        41,643        29,768        19,585   

Gathering, transportation and processing expense

     56,608        39,342        23,163        15,721        11,950   

Production tax expense

     13,197        44,410        22,744        25,886        33,465   

Exploration expense

     3,227        8,139        8,755        9,390        10,930   

Impairment, dry hole costs and abandonment expense

     52,285        32,065        25,322        12,824        55,353   

Depreciation, depletion and amortization

     253,573        206,316        172,054        138,549        89,499   

General and administrative expense

     37,940        40,454        32,074        27,752        24,540   

Non-cash stock-based compensation expense(2)

     16,458        16,752        10,154        6,491        3,212   
                                        

Total operating expenses

     479,780        431,796        335,909        266,381        248,534   
                                        

Operating income

     118,383        186,115        54,361        108,948        40,225   

Other income (expense):

          

Interest and other income

     438        2,036        2,391        2,527        1,977   

Interest expense

     (30,647     (19,717     (12,754     (10,339     (3,175
                                        

Total other income and expense

     (30,209     (17,681     (10,363     (7,812     (1,198
                                        

Income before income taxes

     88,174        168,434        43,998        101,136        39,027   

Provision for income taxes

     37,956        63,175        17,244        39,125        15,222   
                                        

Net income

   $ 50,218      $ 105,259      $ 26,754      $ 62,011      $ 23,805   
                                        

Income per common share:

          

Basic

   $ 1.12      $ 2.37      $ 0.61      $ 1.42      $ 0.55   

Diluted

   $ 1.12      $ 2.34      $ 0.60      $ 1.40      $ 0.55   

Weighted average number of common shares outstanding, basic

     44,723.1        44,432.4        44,049.7        43,694.8        43,238.3   

Weighted average number of common shares outstanding, diluted

     45,036.0        45,036.5        44,677.5        44,269.4        43,439.6   

 

45


     Year Ended December 31,  
     2009    2008     2007    2006     2005  
     (in thousands)  

Selected Cash Flow and Other Financial Data:

            

Net income

   $ 50,218    $ 105,259      $ 26,754    $ 62,011      $ 23,805   

Depreciation, depletion, impairment and amortization

     273,227      206,316        172,054      138,549        89,499   

Other non-cash items

     132,885      109,376        40,938      37,765        71,168   

Change in assets and liabilities

     24,414      (18,004     11,707      (1,427     (202
                                      

Net cash provided by operating activities

   $ 480,744    $ 402,947      $ 251,453    $ 236,898      $ 184,270   
                                      

Capital expenditures(3)(4)

   $ 406,420    $ 601,115      $ 443,678    $ 501,161      $ 347,427   
                                      

 

(1) Revenues include the effects of cash flow hedging transactions.
(2) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense in the Consolidated Statements of Operations for a total of $54.4 million, $57.2 million, $42.2 million, $34.2 million and $27.8 million for the years ended December 31, 2009, 2008, 2007, 2006 and 2005, respectively. 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, which may have higher or lower costs associated with stock-based grants.
(3) Excludes future reclamation liability accruals of a negative $1.2 million and a positive $8.2 million, $1.3 million, $6.3 million and $10.7 million in 2009, 2008, 2007, 2006 and 2005, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $35.9 million, $14.9 million, $29.0 million, $21.0 million and $23.6 million in 2009, 2008, 2007, 2006 and 2005, respectively. Also includes furniture, fixtures and equipment costs of $2.1 million, $4.9 million, $4.6 million, $2.4 million and $2.6 million in 2009, 2008, 2007, 2006 and 2005, respectively.
(4) Not deducted from the amount is $3.7 million, $2.4 million, $96.5 million, $92.3 million and $13.8 million of proceeds received principally from the sale of interests in oil and gas properties during the years ended December 31, 2009, 2008, 2007, 2006 and 2005, respectively.

 

    As of December 31,
    2009   2008   2007   2006   2005
    (in thousands)

Balance Sheet Data:

         

Cash and cash equivalents

  $ 54,405   $ 43,063   $ 60,285   $ 41,322   $ 68,282

Other current assets

    125,634     270,311     71,142     97,185     73,036

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

    1,639,212     1,548,633     1,182,664     951,132     737,992

Other property and equipment, net of depreciation

    14,444     13,186     10,865     11,967     7,956

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

    5,604     —       2,303     75,496     —  

Other assets

    26,824     119,300     2,428     10,299     1,679
                             

Total assets

  $ 1,866,123   $ 1,994,493   $ 1,329,687   $ 1,187,401   $ 888,945
                             

Current liabilities

  $ 153,292   $ 225,794   $ 139,568   $ 119,795   $ 132,798

Long-term debt

    402,250     407,411     274,000     188,000     86,000

Other long-term liabilities

    282,026     262,055     142,608     123,209     39,364

Stockholders’ equity

    1,028,555     1,099,233     773,511     756,397     630,783
                             

Total liabilities and stockholders’ equity

  $ 1,866,123   $ 1,994,493   $ 1,329,687   $ 1,187,401   $ 888,945
                             

 

46


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 in this Annual Report on Form 10-K. 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 approvals, 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 our development properties. 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, NGL, and oil production at market prices and the settlement of commodity hedges. Approximately 95% of our December 2009 production volume was natural gas.

We were formed in January 2002. Since inception, we substantially increased our activity level and the number of properties that we operate. Our operating results reflect this growth. We began active natural gas and oil operations in March 2002 with the acquisition of properties in the Wind River Basin. 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 in or around the Gibson Gulch Field (the “Piceance Basin Acquisition Properties”). In May 2006, we acquired additional coalbed methane properties in the Powder River Basin of Wyoming. In June 2007, we sold our Williston Basin properties. In June 2009, we acquired Cottonwood Gulch, an undeveloped property in the Piceance Basin. 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

Piceance Basin

   June 2009      60

 

47


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 our Company, debt financing, our credit facility, cash flow from operations and, in the case of the Piceance Basin Acquisition 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, 2009, we had 964.8 Bcfe of estimated net proved reserves with a Standardized Measure of $590.8 million (based on average prices of $3.04 CIGRM and $57.65 WTI using the new SEC requirements). As of December 31, 2008, we had 818 Bcfe of estimated net proved reserves with a Standardized Measure of $858.1 million (at year-end prices of $4.61 CIGRM and $41.00 WTI under the former SEC requirements), while at December 31, 2007, we had 558 Bcfe of estimated net proved reserves with a Standardized Measure of $941 million (at year-end prices of $6.04 CIGRM and $92.50 WTI under the former SEC requirements).

The average sales prices received for natural gas, before the effects of hedging contracts, for the years ended December 31, 2009, 2008 and 2007 were $3.86 per Mcf, $7.05 per Mcf and $4.37 per Mcf, respectively, and for oil $49.56 per Bbl, $83.27 per Bbl and $61.18 per Bbl, respectively. After the effects of all hedging contracts, the average sales prices received for natural gas for the years ended December 31, 2009, 2008 and 2007 were $6.96 per Mcf, $7.61 per Mcf and $5.89 per Mcf, respectively, and for oil $59.03 per Bbl, $69.55 per Bbl and $59.87 per Bbl, respectively.

Commodity prices, particularly in the Rocky Mountain Region, are inherently volatile and are influenced by many factors outside of our control. We plan our activities and capital budget using what we believe to be conservative sales price assumptions and our existing hedge position. Our strategic objective is to hedge at least 50%-70% of our anticipated 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. See below, “—Trends and Uncertainties—Regulatory Trends.” The permitting and approval process has been more difficult in recent years than in the past due to more stringent rules, such as those recently enacted by the COGCC, increased activism from environmental and other groups, which 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.

 

48


Results of Operations

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

 

    Year Ended
December 31,
2009
    2008 to 2009
Increase
(Decrease)
    Year Ended
December 31,
2008
  2007 to 2008
Increase
(Decrease)
    Year Ended
December 31,
2007
      Amount     Percent       Amount     Percent    
    (in thousands, except per unit data)

Operating Results:

             

Operating Revenues

             

Oil and gas production

  $ 647,839      $ 41,958      7   $ 605,881   $ 230,925      62   $ 374,956

Commodity derivative gain (loss)

    (54,567     (62,487   (789 )%      7,920     7,920      100     —  

Other

    4,891        781      19     4,110     (11,204   (73 )%      15,314
                                       

Total operating and other revenues

  $ 598,163      $ (19,748   (3 )%    $ 617,911   $ 227,641      58   $ 390,270
                                       

Operating Expenses

             

Lease operating expense

    46,492        2,174      5     44,318     2,675      6     41,643

Gathering, transportation and processing expense

    56,608        17,266      44     39,342     16,179      70     23,163

Production tax expense

    13,197        (31,213   (70 )%      44,410     21,666      95     22,744

Exploration expense

    3,227        (4,912   (60 )%      8,139     (616   (7 )%      8,755

Impairment, dry hole costs and abandonment expense

    52,285        20,220      63     32,065     6,743      27     25,322

Depreciation, depletion and amortization

    253,573        47,257      23     206,316     34,262      20     172,054

General and administrative expense

    37,940        (2,514   (6 )%      40,454     8,380      26     32,074

Non-cash stock-based compensation expense(1)

    16,458        (294   (2 )%      16,752     6,598      65     10,154
                                       

Total operating expenses

  $ 479,780      $ 47,984      11   $ 431,796   $ 95,887      29   $ 335,909
                                       

Production Data:

             

Natural gas (MMcf)

    85,485        11,862      16     73,623     15,945      28     57,678

Oil (MBbls)

    710        49      7     661     75      13     586

Combined volumes (MMcfe)

    89,745        12,156      16     77,589     16,395      27     61,194

Daily combined volumes (MMcfe/d)

    246        34      16     212     44      26     168

Average Prices(2):

             

Natural gas (per Mcf)

  $ 6.96      $ (0.65   (9 )%    $ 7.61   $ 1.72      29   $ 5.89

Oil (per Bbl)

    59.03        (10.52   (15 )%      69.55     9.68      16     59.87

Combined (per Mcfe)

    7.10        (0.71   (9 )%      7.81     1.68      27     6.13

Average Costs (per Mcfe):

             

Lease operating expense

  $ 0.52      $ (0.05   (9 )%    $ 0.57   $ (0.11   (16 )%    $ 0.68

Gathering, transportation and processing expense

    0.63        0.12      24     0.51     0.13      34     0.38

Production tax expense

    0.15        (0.42   (74 )%      0.57     0.20      54     0.37

Depreciation, depletion and amortization(3)

    2.83        0.17      6     2.66     (0.21   (7 )%      2.87

General and administrative
expense
(4)

    0.42        (0.10   (19 )%      0.52     —        0     0.52

 

(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense in the Consolidated Statements of Operations for a total of $54.4 million, $57.2 million and $42.2 million for the years ended December 31, 2009, 2008 and 2007, respectively. 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, which may have higher or lower costs associated with stock-based grants.

 

49


(2) Average prices shown in the table are net of the effects of all of our realized commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting. As a result of our realized hedging transactions, natural gas production revenues increased by $265.1 million, $41.0 million and $87.7 million for the years ended December 31, 2009, 2008 and 2007, respectively. Oil production revenues were increased by $6.7 million for year ended December 31, 2009 and decreased by $9.1 million and $0.8 million for the years ended December 31, 2008 and 2007, respectively. The average price we received for natural gas before the effects of hedging contracts in 2009 was $3.86 per Mcf compared with $7.05 per Mcf in 2008 and $4.37 per Mcf in 2007. The average price we received for oil before the effects of hedging contracts in 2009 was $49.56 per Bbl compared to $83.27 per Bbl in 2008 and $61.18 per Bbl in 2007.
(3) The DD&A per Mcfe as calculated based on the DD&A expense and MMcfe production data presented in the table for the year ended December 31, 2007 is $2.81. However, the DD&A rate per Mcfe for the year ended December 31, 2007 of $2.87, as presented in the table above, excludes production of 1,198 MMcfe, associated with our properties that were classified as held for sale in the Williston Basin, as the Williston property was not depleted throughout 2007.
(4) Excludes non-cash stock-based compensation expense as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Consolidated Statements of Operations, were $0.61, $0.74 and $0.69 for the years ended December 31, 2009, 2008 and 2007, respectively.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Production Revenues. Production revenues increased to $647.8 million for the year ended December 31, 2009 from $605.9 million for the year ended December 31, 2008 due to a 16% increase in production offset by an 8% decrease in natural gas and oil prices after the effects of realized hedges on a per Mcfe basis. The increase in production added approximately $87.7 million of production revenues and the decrease in price reduced production revenues by approximately $45.8 million.

Beginning in January 2009, we elected to process a portion of our natural gas in the Piceance Basin and receive the value of the resulting NGL. Given the strength of NGL market prices relative to natural gas during the period, we realized an increase in production revenues of approximately $28.8 million, or $0.32 per Mcfe, for the year ended December 31, 2009, which helped to reduce the negative impact of declining natural gas prices during the year.

Total production volumes for the year ended December 31, 2009 of 89.7 Bcfe increased from 77.6 Bcfe for the year ended December 31, 2008 due to increased production in the Piceance, Uinta and Powder River Basins. The increased production was partially offset by a decrease in production in the Wind River Basin. Additional information concerning production is in the following table:

 

    Year Ended December 31, 2009   Year Ended December 31, 2008   % Increase (Decrease)  
    Oil   Natural Gas   Total   Oil   Natural Gas   Total   Oil     Natural Gas     Total  
    (MBbls)   (MMcf)   (MMcfe)   (MBbls)   (MMcf)   (MMcfe)   (MBbls)     (MMcf)     (MMcfe)  

Piceance Basin

  425   33,904   36,454   402   29,075   31,487   6   17   16

Uinta Basin

  227   30,849   32,211   201   26,999   28,205   13   14   14

Wind River Basin

  26   8,240   8,396   28   9,395   9,563   (7 )%    (12 )%    (12 )% 

Powder River Basin

    12,081   12,081     8,111   8,111        49   49

Paradox Basin

  2   340   352     17   17   nm   nm   nm

Other

  30   71   251   30   26   206   0   173   22
                             

Total

  710   85,485   89,745   661   73,623   77,589   7   16   16
                             

 

* Not meaningful

 

50


The production increase in the Piceance Basin was the result of our continued development activities, with initial sales on 105 new gross wells throughout 2009. The production increase in the Uinta Basin was the result of our continued development activities, with initial sales from 33 new gross wells throughout 2009. The production increase in the Powder River Basin was the result of our continued development activities, with initial sales from 172 new gross wells throughout 2009. Although we reduced our 2009 development activities in the Powder River Basin as the result of lower natural gas prices, our production in that basin has benefited from prior years’ development programs due to the extended dewatering process of the coal bed methane 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 with no significant drilling or recompletion activities to offset these declines.

Hedging Activities. In 2009, approximately 79% of our natural gas volumes and 52% of our oil volumes were hedged, which resulted in an increase in gas and oil revenues of $265.1 million and $6.7 million, respectively, after cash settlements for all commodity derivatives. In 2008, we hedged approximately 73% of our natural gas volumes and 64% of our oil volumes, which resulted in an increase in gas revenues of $41.0 million, offset by a reduction in oil revenues of $9.1 million after cash settlements for all commodity derivatives.

Commodity Derivative Gain (Loss). The “Commodity derivative gain (loss)” line item on the Consolidated Statements of Operations is comprised of ineffectiveness on cash flow hedges and realized and unrealized gains and losses on hedges that do not qualify for cash flow hedge accounting or were not designated as a cash flow hedge. Ineffectiveness on cash flow hedges relates to slight differences between the contracted location and the actual delivery location. Unrealized gains and losses represent the change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting, which includes our basis only swaps and NGL swaps. As those instruments settle, their settlement will be presented as realized gains and losses within this same line item. In addition to the basis only and NGL swaps, we elected to prospectively de-designate certain cash flow hedges in the Rocky Mountain region for a portion of our natural gas production during the year ended December 31, 2009 and enter into physical fixed-price sales contracts. All of the de-designated hedges settled by December 31, 2009, and as a result, their settlements, from the date of de-designation, are also reflected in realized gains and losses.

The overall decrease in commodity derivative gain (loss) from a gain of $7.9 million for the year ended December 31, 2008 to a loss of $54.6 million for the year ended December 31, 2009 is primarily due to the unrealized losses resulting from the change in fair value of our basis only swaps as of December 31, 2009, as well as the cash settlements of those basis only swaps during 2009. The loss on the basis only swaps is a result of the narrowing basis between NYMEX and pricing points in the Rocky Mountain region throughout 2009.

The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative gain (loss) for the periods indicated:

 

     Year Ended December 31,
             2009                    2008        
     (in thousands)

Realized gains (losses) on derivatives not designated as cash flow hedges

   $ (10,902)    $ 62

Unrealized ineffectiveness gains (losses) recognized on derivatives designated as cash flow hedges

     (5,572)      6,803

Unrealized gains (losses) on derivatives not designated as cash flow hedges

     (38,093)      1,055
             

Total commodity derivative gain (loss)

   $ (54,567)    $ 7,920
             

Other Operating Revenues. Other operating revenues increased to $4.9 million for the year ended December 31, 2009 from $4.1 million for the year ended December 31, 2008. Other operating revenues for 2009 primarily consisted of $1.4 million in gains realized from the sale of our Talon properties in the Wind River Basin as well as $3.5 million in gathering and compression fees on third party gas and salt-water disposal fees

 

51


received from the use of our facilities. Other operating revenues for 2008 primarily consisted of gains realized from the sale of properties of $1.1 million, gathering and rental fees of $2.0 million and the sale of seismic data of $1.0 million.

Lease Operating Expense. Lease operating expense decreased to $0.52 per Mcfe in 2009 from $0.57 per Mcfe in 2008. The following table displays the lease operating expense per Mcfe by basin:

 

     Year Ended December 31, 2009    Year Ended December 31, 2008    %Increase/(Decrease)  
     ($ in thousands)    ($ per Mcfe)    ($ in thousands)    ($ per Mcfe)    ($ per Mcfe)  

Piceance Basin

   $ 14,814    $ 0.41    $ 10,525    $ 0.33    24

Uinta Basin

     11,241      0.35      15,762      0.56    (38 )% 

Wind River Basin

     4,935      0.59      6,831      0.71    (17 )% 

Powder River Basin

     14,463      1.20      10,554      1.30    (8 )% 

Paradox Basin

     441      1.25      6      0.31    303

Other

     598      2.38      640      3.14    (24 )% 
                      

Total

   $ 46,492      0.52    $ 44,318      0.57    (9 )% 
                      

Lease operating expense in the Piceance Basin increased to $0.41 per Mcfe for the year ended December 31, 2009 from $0.33 per Mcfe for the year ended December 31, 2008 primarily due to increased compression costs. The decrease in the Uinta Basin to $0.35 per Mcfe for the year ended December 31, 2009 from $0.56 per Mcfe for the year ended December 31, 2008 was the result of decreased water disposal costs due to the utilization of a salt water disposal well, as well as a decrease in compressor overhaul activity in our West Tavaputs field. In addition, for the first half of 2009 we shut in a majority of our Lake Canyon and Blacktail Ridge fields due to gas gathering constraints, which reduced our lease operating expense in the Uinta Basin. Lease operating expense decreased in the Wind River Basin to $0.59 per Mcfe for the year ended December 31, 2009 from $0.71 per Mcfe for the year ended December 31, 2008 as a result of reduced workover activity as well as decreased compression expenses. Lease operating expense decreased in the Powder River Basin to $1.20 per Mcfe for the year ended December 31, 2009 from $1.30 per Mcfe for the year ended December 31, 2008. Actual lease operating expense incurred in the Powder River Basin increased by $3.9 million from the prior year; however, the corresponding production increase from new wells and wells that were previously in the dewatering stage more than compensated for the additional lease operating expense incurred, thereby reducing lease operating expense on a per Mcfe basis.

Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $0.63 per Mcfe in 2009 from $0.51 per Mcfe in 2008. The following table displays the gathering, transportation and processing expense by basin:

 

     Year Ended December 31, 2009    Year Ended December 31, 2008     %Increase/(Decrease)  
     ($ in thousands)    ($ per Mcfe)    ($ in thousands)     ($ per Mcfe)     ($ per Mcfe)  

Piceance Basin

   $ 22,752    $ 0.62    $ 15,034      $0.48      29

Uinta Basin

     20,487      0.64      14,497      0.51      25

Wind River Basin

     61      0.01      268      0.03      (67 )% 

Powder River Basin

     12,995      1.08      9,556      1.18      (8 )% 

Paradox Basin

     283      0.80                nm

Other

     30      0.12      (13   (0.06   nm
                      

Total

   $ 56,608      0.63    $ 39,342      0.51      24
                      

 

* Not meaningful

 

52


Gathering, transportation and processing expense increased in the Piceance Basin to $0.62 per Mcfe for the year ended December 31, 2009 from $0.48 per Mcfe for the year ended December 31, 2008. The increase is due in part to our election to process our gas in order to market the resulting NGL. Beginning in January 2009, we incurred additional fees to process our natural gas and received additional revenue from the sale of NGL. Although sales revenue for NGL can fluctuate, for the year ended December 31, 2009, the revenues received from NGL sales resulted in a Company-wide increase of approximately $0.32 per Mcfe to our average realized price while incurring additional gathering and processing costs of approximately $0.06 per Mcfe. Gathering, transportation and processing expense in the Uinta Basin increased to $0.64 per Mcfe for the year ended December 31, 2009 from $0.51 per Mcfe for the year ended December 31, 2008. This increase is a result of additional contracts to gather, transport and process our West Tavaputs gas from the Uinta Basin. Also contributing to the increase in both basins were higher fees associated with the Rockies Express Pipeline (“REX”) due to the completion of the final two segments of the pipeline, which gave us access to delivery points farther east.

We have entered into long-term firm transportation contracts for a portion of our production to guarantee capacity on major pipelines and reduce the risk and impact related to possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production in the Piceance, Uinta and Powder River Basins where we expect to allocate a significant portion of our capital expenditure programs in future years. In addition, we have entered into long-term firm processing contracts on a portion of our production in the Piceance and Uinta Basins. Included in the above gathering, transportation and processing expense are $0.17 and $0.12 per Mcfe of firm transportation expense and $0.05 and $0.04 per Mcfe of firm processing expense from long-term contracts for the years ended December 31, 2009 and 2008, respectively.

The increase in firm transportation expense to $0.17 per Mcfe for the year ended December 31, 2009 from $0.12 per Mcfe for the year ended December 31, 2008 was the result of additional long-term contracts executed with various pipelines for our natural gas production in the Powder River Basin and Uinta Basins. Also contributing to the increase were higher fees on REX as mentioned above.

Production Tax Expense. Total production taxes decreased to $13.2 million in 2009 from $44.4 million in 2008. The decrease in production taxes is primarily related to decreased natural gas and oil prices during the year ended December 31, 2009. Production taxes are primarily based on the wellhead values of production. In addition to the decrease in natural gas and oil prices, we reduced our current year production tax by $5.0 million based upon amended Colorado severance tax returns for the years 2004 through 2008. These nonrecurring adjustments were based on a settlement agreement with the State of Colorado relating to the severance tax computation. Our 2009 production tax expense also includes a decrease of $3.4 million primarily related to a surplus of ad valorem taxes withheld from 2008 based on the estimated mill levy rates compared to the actual rates. Because these items are nonrecurring, if the reductions associated with the Colorado severance and ad valorem taxes are excluded in order to provide a more accurate comparison to the prior year, production taxes as a percentage of natural gas and oil sales before hedging adjustments were 5.9% for the year ended December 31, 2009 and 7.7% for the year ended December 31, 2008. Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas.

Exploration Expense. Exploration expense decreased to $3.2 million in 2009 from $8.1 million in 2008. Exploration expense for 2009 consisted of $1.7 million for seismic programs, principally in the Deseret and Paradox Basins, $1.1 million for delay rentals and $0.4 million related to the evaluation of non-acquired assets. Exploration expense for 2008 consisted of $3.9 million for seismic programs, principally in the Big Horn, Uinta and Paradox Basins, $1.0 million for delay rentals and $3.2 million for two scientific wells drilled for data gathering purposes.

 

53


Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased to $52.3 million in 2009 from $32.1 million in 2008. For the year ended December 31, 2009, impairment expense was $19.7 million, abandonment expense was $1.9 million and dry hole costs were $30.7 million. For the year ended December 31, 2008, impairment expense was $25.3 million, abandonment expense was $2.0 million and dry hole costs were $4.8 million.

We evaluate the impairment of our proved oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate a property’s carrying amount may not be recoverable. If the carrying amount exceeds the property’s estimated fair value, we will adjust the carrying amount of the property to fair value through a charge to impairment expense. For 2009, our impairment analysis required us to take a non-cash impairment charge of $2.8 million to our proved oil and gas properties in the North Hill Creek field, located in the Uinta Basin based upon our fair value analysis, which are currently held for sale. Further, for 2009, we also recorded a non-cash impairment charge of $16.9 million to our proved oil and gas properties in the Yellow Jacket prospect, located in the Paradox Basin. This impairment expense is primarily the result of sub-economic performing wells in the Yellow Jacket prospect that were completed using a less optimal fracture technology. In 2008, we recognized a non-cash impairment charge to our proved oil and gas properties in the Cooper Reservoir field, located in the Wind River Basin, of $21.0 million.

Unevaluated oil and gas properties are also assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop existing acreage. During the year ended December 31, 2009, no impairment charges on unevaluated oil and gas properties were recognized. In 2008, we recognized an impairment charge of $4.3 million on the carrying value of unevaluated oil and gas properties in the Talon field, located in the Wind River Basin. We sold the Talon field in 2009.

The $30.7 million for the year ended December 31, 2009 for dry hole costs was associated with six wells within the Montana Overthrust area, four wells within the Uinta Basin, two wells within the Paradox Basin and one well in each of the Big Horn and Laramie Basins. During 2008, dry hole costs included $3.4 million for a well drilled in the Uinta Basin and $1.4 million for additional costs on wells that were deemed to be uneconomic in prior years. The $3.4 million for dry hole costs in the Uinta Basin was associated with the Peters Point 7-1-13-16 Ultra Deep well, which was completed in June 2008 and was tested and determined to be non-commercial in the Pennsylvanian Weber sandstone and Mississippi Leadville zones. Therefore, a proportionate share of the well cost was expensed.

We account for oil and gas exploration and production activities using the successful efforts method of accounting 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, 2009 pending determination of whether the wells will be assigned proved reserves. The following table does not include $7.6 million related to exploratory wells in progress for which drilling had not been completed at December 31, 2009:

 

     Time Elapsed Since Drilling Completed
     0-12
Months
   1-2
Years
   3-5
Years
   Total
     (in thousands)

Costs of wells for which drilling has been completed

   $ 12,176    $ 19,109    $ 12,610    $ 43,895

Number of wells for which drilling has been completed

     29      69      30      128

As of December 31, 2009, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling were $31.7 million, of which $13.4 million was related to exploratory wells located in the Powder River Basin. In this basin, we drill wells into various coal seams. In order to produce gas

 

54


from the coal seams, a period of dewatering lasting up 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.

In addition to our wells in the Powder River Basin, we have six exploratory wells for a total of $18.3 million that have been capitalized for greater than one year. Four wells are located in the Paradox Basin, one well in the Big Horn Basin and one well in the Black Tail Ridge area of the Uinta Basin. The majority of the exploratory wells are suspended pending the completion of an economic evaluation including, but not limited to, results of additional appraisal drilling, facilities, infrastructure, well test analysis, additional geological and geophysical data and approval of a development plan. Management believes these projects with suspended exploratory drilling costs have sufficient quantities of hydrocarbons to justify their potential development and is actively pursuing efforts to assess whether reserves can be attributed to their respective areas. If additional information becomes available that raises substantial doubt regarding the economic or operational viability of any of these projects, the associated costs will be expensed.

Depreciation, Depletion and Amortization. DD&A was $253.6 million in 2009 compared to $206.3 million in 2008. The increase of $47.3 million was a result of increased production for 2009 compared to 2008, along with an increase in the DD&A rate. The increase in production accounted for $32.2 million of additional DD&A expense while $15.1 million related to an overall increase in the DD&A rate.

During 2009, the weighted average DD&A rate was $2.83 per Mcfe. During 2008, the weighted average DD&A rate was $2.66 per Mcfe. Under successful efforts accounting, DD&A 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 DD&A rate for current production. Future DD&A 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, decreased to $37.9 million in 2009 from $40.5 million in 2008. This decrease was in part due to a reduction related to an abatement of penalties previously recorded in prior years related to our 2004-2006 Colorado severance tax audit. In addition, the year ended December 31, 2008 included nonrecurring expenses such as costs incurred in connection with our efforts in the COGCC regulatory rule making process and costs related to the expensing of costs of pursuing a high-yield debt offering that did not apply to the eventual completion of our 5% Convertible Senior Notes (“Convertible Notes”) offering. On a per Mcfe basis, general and administrative expense, excluding non-cash stock based compensation, decreased to $0.42 for the year ended December 31, 2009 compared to $0.52 per Mcfe for the year ended December 31, 2008 due to the reasons mentioned above as well as increased production for the year ended December 31, 2009 as compared to December 31, 2008.

Non-cash stock-based compensation expense was $16.5 million in 2009 compared to $16.8 million in 2008. Non-cash stock-based compensation expense for 2009 and 2008 related primarily to the vesting of our stock option awards and nonvested shares of common stock granted to employees.

The components of non-cash stock-based compensation expense for 2009 and 2008 are shown in the following table:

 

     Year Ended December 31,
         2009            2008    
     (in thousands)

Stock options and nonvested equity shares of common stock

   $ 15,428    $ 15,789

Shares issued for 401(k) plan

     778      733

Shares issued for directors’ fees

     252      230
             

Total

   $ 16,458    $ 16,752
             

 

55


Interest Expense. Interest expense increased to $30.6 million in 2009 from $19.7 million in 2008 due to higher average outstanding debt balances combined with a higher effective interest rate. Our weighted average outstanding debt balance for the year ended December 31, 2009 was $429.8 million (excluding the debt discounts associated with the Convertible Notes and 9.875% Senior Notes (“Senior Notes”)) compared to $308.7 million in 2008. Furthermore, a greater portion of the debt outstanding during 2009 was at higher interest rates. Our outstanding debt balance for 2009 included our Amended Credit Facility, Convertible Notes and Senior Notes issued in July 2009, whereas our 2008 outstanding debt balance only included our Amended Credit Facility and Convertible Notes.

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 weighted average interest rates used to capitalize interest for the years ended December 31, 2009 and 2008 were 8.1% and 5.9%, respectively, which included interest on our Convertible Notes, Senior Notes and Amended Credit Facility, amortization of the discounts associated with the Convertible Notes and Senior Notes, commitment fees paid on the unused portion of our Amended Credit Facility, amortization of deferred financing and debt issuance costs and the effects of interest rate hedges. We capitalized interest costs of $4.6 million and $2.0 million for the years ended December 31, 2009 and 2008, respectively.

Income Tax Expense. Income tax expense totaled $38.0 million for 2009 and $63.2 million for 2008, resulting in effective tax rates of 43.0% and 37.5% in 2009 and 2008, respectively. The effective tax rate increase from 2008 to 2009 was primarily the result of the decrease in operating income having little impact on permanent differences affecting the tax rate calculation. In addition, a greater proportion of our operating revenue was attributable to higher tax rate jurisdictions, thereby increasing the overall effective tax rate. The effect of this rate change on our prior year net deferred tax liability was included in income tax expense for 2009. At December 31, 2009, we had approximately $6.8 million of federal tax net operating loss carryforwards, or (“NOLs”), which expire through 2027. We also have a federal alternative minimum tax credit carryforward of $7.9 million, which has no expiration date. We believe it is more likely than not that we will use these tax attributes to offset and reduce current tax liabilities in future years.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Production Revenues. Production revenues increased to $605.9 million for the year ended December 31, 2008 from $375.0 million for the year ended December 31, 2007 due to a 27% increase in production and a 27% increase in natural gas and oil prices after the effects of realized hedges on a per Mcfe basis. The increase in production added approximately $128.0 million of production revenues, and the increase in prices increased production revenues by approximately $102.9 million.

 

56


Total production volumes for the 2008 calendar year of 77.6 Bcfe increased from 61.2 Bcfe for the 2007 calendar year due to increased production in the Piceance, Uinta, Wind River and Powder River Basins. The increased production was partially offset by the sale of the Williston Basin properties in June 2007. Additional information concerning production is in the following table.

 

    Year Ended December 31, 2008   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)  

Piceance Basin

  402   29,075   31,487   292   19,031   20,783   38   53   52

Uinta Basin

  201   26,999   28,205   49   25,536   25,830   310   6   9

Wind River Basin

  28   9,395   9,563   36   7,156   7,372   (22 )%    31   30

Powder River Basin

    8,111   8,111     5,828   5,828        39   39

Williston Basin(1)

        184   74   1,178   (100 )%    (100 )%    (100 )% 

Other

  30   43   223   25   53   203   20   (19 )%    10
                             

Total

  661   73,623   77,589   586   57,678   61,194   13   28   27
                             

 

(1) The sale of the Williston Basin properties was completed on June 22, 2007.

The production increase in the Piceance Basin was the result of our continued development activities, with initial sales on 108 new gross wells throughout 2008. The production increase in the Uinta Basin reflects our continued exploration and development activities in the West Tavaputs, Blacktail Ridge and Lake Canyon fields. During the year ended December 31, 2008, we had initial sales on 57 new gross wells in the Uinta Basin. The production increase in the Wind River Basin was due to the highly successful recompletion of an existing well in Cave Gulch to a third zone in the Frontier formation in May 2008 that had peak production rates in excess of 29.0 MMcfe/d. This production was partially offset by natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields that occurred throughout 2008. The production increase in the Powder River Basin was the result of our continued development activities with initial sales on 90 new gross wells for the year ended December 31, 2008. As of December 31, 2008, we had 177 net operated coalbed methane wells in the dewatering stage. Also included in “Other” is production from our first two gross wells related to our Paradox Basin shale gas discovery at our Yellow Jacket prospect, which had first sales in late December 2008.

Hedging Activities. In 2008, approximately 73% of our natural gas volumes and 64% of our oil volumes were hedged, which resulted in an increase in gas revenues of $41.0 million, offset by a reduction in oil revenues of $9.1 million after cash settlements for all commodity derivatives. In 2007, we hedged approximately 63% of our natural gas volumes and 53% of our oil volumes, which resulted in an increase in gas revenues of $87.7 million, offset by a reduction in oil revenues of $0.8 million after cash settlements for all commodity derivatives.

Commodity Derivative Gain. During the year ended December 31, 2008, we determined that the forecasted transactions to which certain Mid-continent natural gas hedges had been designated were no longer probable of occurring within the specified time periods. We therefore discontinued hedge accounting for these hedges. In addition, we entered into basis only swaps for natural gas production in the Rocky Mountain region, which do not qualify for cash flow hedge accounting during the period. The change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting is recognized in the line item titled “commodity derivative gain” in the Condensed Consolidated Statements of Operations.

 

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The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative gain for the periods indicated. During the year ended December 31, 2007, all of our hedges were designated as cash flow hedges, and any ineffectiveness was de minimis.

 

     Year Ended December 31,
         2008            2007    
     (in thousands)

Realized gains on derivatives not designated as cash flow hedges

   $ 62    $   —

Unrealized ineffectiveness gains recognized on derivatives designated as cash flow hedges

     6,803     

Unrealized gains on derivatives not designated as cash flow hedges

     1,055     
             

Total commodity derivative gain

   $ 7,920    $
             

Other Operating Revenues. Other operating revenues decreased to $4.1 million for the year ended December 31, 2008 from $15.3 million for the year ended December 31, 2007. Other operating revenues for 2008 primarily consisted of gains realized from the sale of properties, gathering and rental fees and the sale of seismic data. 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 decrease in lease operating expense to $0.57 per Mcfe in 2008 from $0.68 per Mcfe in 2007 was primarily the result of decreased expenses on a Mcfe basis in the Piceance, Powder River and Wind River Basins offset by an increase in the Uinta Basin. The following table displays the lease operating expense per Mcfe by basin:

 

     Year Ended December 31, 2008    Year Ended December 31, 2007    %Increase/(Decrease)  
     ($ in thousands)    ($ per Mcfe)    ($ in thousands)    ($ per Mcfe)    ($ per Mcfe)  

Piceance Basin

   $ 10,525    $ 0.33    $ 10,680    $ 0.51    (35 )% 

Uinta Basin

     15,762      0.56      10,715      0.41    37

Wind River Basin

     6,831      0.71      7,131      0.97    (27 )% 

Powder River Basin

     10,554      1.30      9,614      1.65    (21 )% 

Williston Basin

     —        —        2,732      2.32    (100 )% 

Other

     646      2.90      771      3.80    (24 )% 
                                  

Total

   $ 44,318      0.57    $ 41,643      0.68    (16 )% 
                                  

Lease operating expense in the Piceance Basin decreased to $0.33 per Mcfe for the year ended December 31, 2008 from $0.51 per Mcfe for the year ended December 31, 2007 primarily due to the implementation of a new water disposal pipeline system, which substantially reduced water hauling expenses. The increase in the Uinta Basin to $0.56 per Mcfe for the year ended December 31, 2008 from $0.41 per Mcfe for the year ended December 31, 2007 was the result of three scheduled compressor overhauls that took place in 2008, along with increased workover and lease maintenance costs in the West Tavaputs field. Higher costs related to high pour point oil production in our early development program in the Lake Canyon and Blacktail Ridge fields also contributed to the higher lease operating expense in the Uinta Basin. Lease operating expense decreased in the Powder River Basin to $1.30 per Mcfe for the year ended December 31, 2008 from $1.65 per Mcfe for the year ended December 31, 2007 primarily as a result of lower well service, lease maintenance, fuel, and labor costs as well as initial production on wells that were previously in the dewatering stage, which provided increased production without increasing costs thereby causing the cost per Mcfe to decline. Lease operating expense decreased in the Wind River Basin to $0.71 per Mcfe for the year ended December 31, 2008 from $0.97 per Mcfe for the year ended December 31, 2007 as a result of lower well servicing and workover costs, along with an increase in production from the recompletion of the Bullfrog 14-18 well, which had peak production rates in excess of 29.0 MMcfe/d.

 

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Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $0.51 per Mcfe in 2008 from $0.38 per Mcfe in 2007 primarily due to additional transportation and processing contracts that went into effect throughout 2008 and 2007 along with increased fuel costs. The following table displays the gathering, transportation and processing expense by basin:

 

     Year Ended December 31, 2008     Year Ended December 31, 2007    %Increase/(Decrease)  
     ($ in thousands)     ($ per Mcfe)     ($ in thousands)    ($ per Mcfe)    ($ per Mcfe)  

Piceance Basin

   $ 15,034      $0.48      $ 8,012    $ 0.39    23

Uinta Basin

     14,497      0.51        7,413      0.29    76

Wind River Basin

     268      0.03        155      0.02    50

Powder River Basin

     9,556      1.18        7,542      1.29    (9 )% 

Other

     (13   (0.06     41      0.03    nm
                      

Total

   $ 39,342      0.51      $ 23,163      0.38    34
                      

 

* Not meaningful

Included in the above gathering, transportation and processing expense are $0.12 and $0.09 per Mcfe of firm transportation expense and $0.04 and $0.06 per Mcfe of firm processing expense from long-term contracts for the years ended December 31, 2008 and 2007, respectively.

The increase in firm transportation expense to $0.12 per Mcfe for the year ended December 31, 2008 from $0.09 per Mcfe for the year ended December 31, 2007 was the result of additional long-term contracts with Rockies Express Pipeline and Questar Pipeline to deliver 25,000 gross MMBtu per day to each pipeline. Our transportation commitment with Rockies Express Pipeline, which was effective January 2008, provides us access to sell natural gas to Mid-continent markets. Our commitment with Questar Pipeline, which was effective November 2007, provides us the flexibility to access and sell natural gas to various Rocky Mountain markets.

Production Tax Expense. Total production taxes increased to $44.4 million in 2008 from $22.7 million in 2007. The increase in production tax expense was primarily related to the increase in natural gas and oil revenues before the effects of hedging. Production taxes as a percentage of natural gas and oil revenues before the effects of hedging were 7.7% for 2008 and 7.9% 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 expense decreased to $8.1 million in 2008 from $8.8 million in 2007. Exploration expense for 2008 consisted of $3.9 million for seismic programs, principally in the Big Horn, Uinta and Paradox Basins, $1.0 million for delay rentals and $3.2 million for two scientific wells drilled for data gathering purposes. The expense 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 to $32.1 million in 2008 from $25.3 million in 2007. During 2008, impairment expense was $25.3 million, abandonment expense was $2.0 million, dry hole costs included $3.4 million for a well drilled in the Uinta Basin and $1.4 million for additional costs on wells that were deemed to be uneconomic in prior years. The $3.4 million for dry hole costs were associated with the Peters Point 7-1-13-16 Ultra Deep well, which was completed in June 2008 and was tested and determined to be non-commercial in the Pennsylvanian Weber sandstone and Mississippi Leadville zones. Therefore, a proportionate share of the well cost was expensed. 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

 

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$12.6 million. In 2007, 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 evaluate the impairment of our proved oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate a property’s carrying amount may not be recoverable. If the carrying amount exceeds the property’s estimated fair value, we will adjust the carrying amount of the property to fair value through a charge to impairment expense. For 2008, our impairment analysis required us to take a non-cash impairment charge to our proved oil and gas properties in the Cooper Reservoir field, located in the Wind River Basin, of $21.0 million primarily as the result of geologic and engineering reevaluations, as well as lower oil and gas prices at December 31, 2008.

Unevaluated oil and gas properties are also assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop existing acreage. During the year ended December 31, 2008, we recognized a non-cash impairment charge of $4.3 million primarily on the carrying value of unevaluated oil and gas properties in the Talon field, which is also located in the Wind River Basin. We sold the Talon field in 2009.

In 2007, based upon our fair value analysis, we recognized a $2.3 million non-cash impairment charge associated with our Tri-State properties within the DJ Basin. We subsequently sold these properties in 2008 for an immaterial gain.

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, 2008 pending determination of whether the wells will be assigned proved reserves. The following table does not include $4.7 million related to exploratory wells in progress for which drilling had not been completed at December 31, 2008:

 

     Time Elapsed Since Drilling Completed
     0-12
Months
   1-2
Years
   3-5
Years
   Total
     (in thousands)

Costs of wells for which drilling has been completed

   $ 76,297    $ 27,868    $ 11,269    $ 115,434

Number of wells for which drilling has been completed

     148      124      39      311

The majority of the $39.1 million of exploratory well costs that have been capitalized for a period greater than one year are for wells 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.

In addition to our wells in the Powder River Basin, we have six wells that have been capitalized for greater than one year located in the Montana Overthrust area, and in the Paradox, Big Horn and Uinta Basins. The two wells located in the Montana Overthrust area are under economic evaluation for possible development, as we are assessing and conducting appraisal operations to determine whether economic reserves can be attributed to this area. In the Paradox Basin, we had two wells that were evaluated to be re-entered and converted to horizontal or salt water disposal wells. The well located in the Big Horn Basin is pending upgrades of production gathering and processing facilities. The well located in the Uinta Basin is pending the development of a gas gathering infrastructure.

Depreciation, Depletion and Amortization. DD&A was $206.3 million in 2008 compared to $172.1 million in 2007. The increase of $34.3 million was a result of increased production for 2008 compared to 2007, partially offset by a decrease in the DD&A rate. The decrease in the DD&A rate is primarily attributable to additional

 

60


reserves booked on our year-end reserve report as the result of our ongoing development programs. The increase in production accounted for $50.3 million of additional DD&A expense, offset by $16.0 million related to an overall decrease in the DD&A rate.

During 2008, the weighted average DD&A rate was $2.66 per Mcfe. During 2007, the weighted average DD&A rate was $2.87 per Mcfe. The DD&A rate for 2007 excluded production of 1,198 MMcfe associated with our properties held for sale in the Williston and DJ Basins. Under successful efforts accounting, DD&A 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 DD&A rate for current production.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $40.5 million in 2008 from $32.1 million in 2007. This increase was primarily due to increased costs related to our employees’ compensation and benefit plans and additional personnel required for our capital program and production levels. As of December 31, 2008, we had 162 full-time employees in our corporate office compared to 155 as of December 31, 2007. In addition, we had increased costs in connection to the regulatory rule making process during 2008. On a per Mcfe basis, general and administrative expense, excluding non-cash stock based compensation, did not change and remained at $0.52 per Mcfe for the year ended December 31, 2008.

Non-cash charges for stock-based compensation were $16.8 million in 2008 compared to $10.2 million in 2007. Non-cash stock-based compensation expense for 2008 and 2007 was related to the vesting of our stock option awards and nonvested shares of common stock issued to employees. The increase in charges for non-cash stock-based compensation during 2008 was primarily due to additional equity awards, which were granted during the latter part of 2007 and in 2008.

The components of non-cash stock-based compensation for 2008 and 2007 are shown in the following table.

 

     Year Ended December 31,
         2008            2007    
     (in thousands)

Stock options and nonvested equity shares of common stock

   $ 15,789    $ 9,372

Shares issued for 401(k) plan

     733      619

Shares issued for directors’ fees

     230      163
             

Total

   $ 16,752    $ 10,154
             

Interest Expense. Interest expense increased to $19.7 million in 2008 from $12.8 million in 2007. Interest expense for the year ended December 31, 2008 includes $3.9 million of non-cash interest expense associated with the implementation of new authoritative accounting guidance under Accounting Standards Codification (“ASC”) Topic 470, Debt with Conversion and Other Options (“ASC Topic 470”), which required retrospective application. The additional increase for the year 2008 was due to higher average outstanding debt balances in order to fund exploration and development activities. Our weighted average outstanding debt balance, including our Amended Credit Facility and Convertible Notes issued in March 2008, was $308.7 million (net of the debt discount associated with the Convertible Notes) for the year ended December 31, 2008 compared to $196.0 million in 2007.

The weighted average interest rates used to capitalize interest for the years ended December 31, 2008 and 2007 were 5.9% and 7.1%, respectively, which included interest on both our Convertible Notes and Amended Credit Facility, commitment fees paid on the unused portion of our Amended Credit Facility, amortization of deferred financing and debt issuance costs and the effects of interest rate hedges. We capitalized interest costs of $2.0 million and $1.6 million for the years ended December 31, 2008 and 2007, respectively.

 

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Income Tax Expense. Our effective tax rates were 37.5% and 39.2% in 2008 and 2007, respectively. Our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense, and other operating expenses that are not deductible for income tax purposes. At December 31, 2008, we had approximately $68.0 million of federal tax NOLs, which expire through 2027. We also had a federal AMT credit carryforward of $1.6 million, which has no expiration date. We believe it is more likely than not that we will use these NOLs to offset and reduce current tax liabilities in future years.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been sales and other issuances of equity and debt securities, including our Convertible Notes and Senior Notes, 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 reserves 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. The recent credit market dislocation has improved; however, the costs to raise debt and equity capital have increased. We believe that we have significant liquidity available to us from cash flows from operations and under our Amended Credit Facility for our planned uses of capital. In addition, our strong hedge positions provide relative certainty on a significant portion of our cash flows from operations through 2010 even with a general decline in the prices of natural gas and oil resulting from current oversupply and decreased demand. See below, “—Trends and Uncertainties—Declining Commodity Prices.” 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, which, under current market conditions, we may not be able to obtain on terms acceptable to us. We filed an automatically effective shelf registration statement with the SEC that we used for the offering of our Senior Notes, and we may use for future securities offerings.

At December 31, 2009, our balance sheet reflected a cash and cash equivalents balance of $54.4 million with a balance of $5.0 million of borrowings outstanding under our Amended Credit Facility. Based on our mid-year 2009 proved reserves and hedge positions, the borrowing base under our Amended Credit Facility was increased to $630.0 million with commitments from 17 lenders for a total of $592.8 million effective October 9, 2009.

Cash Flow from Operating Activities

Net cash provided by operating activities was $480.7 million, $402.9 million and $251.5 million in 2009, 2008 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 were offset by increased expenses, as discussed above in “—Results of Operations.” Changes in current assets and liabilities increased cash flow from operations by $24.4 million and $11.7 million in 2009 and 2007, respectively, and decreased cash flow from operations by $18.0 million in 2008.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas, NGL and oil. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity, weather, infrastructure capacity to reach markets, supply levels 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 “Item 7A. 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, NGL and oil prices, we have entered into financial commodity swap and cashless collar contracts (purchased put options and written call options) to receive fixed prices for a portion of our natural gas, NGL and oil revenue. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production. We typically hedge a fixed price for natural gas at our sales points (New York Mercantile Exchange (“NYMEX”) less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. In addition to the swaps and collars, we also have entered into basis only swaps. With a basis only swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. At December 31, 2009, we had in place natural gas, NGL and crude oil financial collars, swaps and basis only swaps covering portions of our 2010, 2011 and 2012 production.

In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. 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 production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. For derivative instruments that qualify and are designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income (“OCI”) until the forecasted transaction occurs. The ineffective portion of hedge derivatives is reported in commodity derivative gain or loss in the Consolidated Statements of Operations. Realized gains and losses on cash flow hedges are transferred from OCI and recognized in earnings and included within oil and gas production revenues in the Consolidated Statements of Operations as the associated production occurs.

If, during the derivative’s term, we determine that the hedge is no longer effective or necessary, hedge accounting is prospectively discontinued. All subsequent changes in the derivative’s fair value are recorded in earnings, and all accumulated gains or losses, based on the effective portion of the derivative at that date, recorded in OCI will remain in OCI and are reclassified to earnings when the underlying transaction occurs. If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time period, the hedging instrument loses cash flow hedge accounting treatment. All current mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in OCI related to the hedging instrument are also reclassified to earnings. During the year ended December 31, 2009, we voluntarily elected to discontinue cash flow hedge accounting for certain hedges in the Rocky Mountain region and instead enter into physical fixed-price sales contracts for a portion of our natural gas production. All of the de-designated hedges settled by December 31, 2009, and as a result, their settlements, from the date of de-designation, which were a loss of $5.9 million, were reflected as realized losses within commodity derivative gain or loss in the Consolidated Statement of Operations. For additional information, see above “—Results of Operations—Year Ended December 31, 2009 Compared to Year Ended December 31, 2008.

Some of our derivatives do not qualify for hedge accounting or are not designated as cash flow hedges but are, to a degree, an economic offset to our commodity price exposure. If a derivative instrument does not qualify or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative gain (loss) in the Consolidated Statements of Operations. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument contract is settled by making or receiving a payment to or from the counterparty. Realized gains and losses of derivative instruments that do not qualify as cash flow hedges are recognized in commodity derivative gain (loss) in the Consolidated Statements of Operations and are reflected in cash flows from operations on the Consolidated Statements of Cash Flows.

 

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During the year ended December 31, 2009, in addition to the swaps and collars discussed above, we entered into basis only swaps to hedge the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. Although we believe this is an appropriate part of a mitigation strategy, the basis only swaps do not qualify for hedge accounting because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments are recorded in earnings. As of December 31, 2009, we had basis only hedges in place for a portion of our anticipated natural gas production in 2010, 2011 and 2012 for a total of 27,560,000 MMBtu. We recognized $38.1 million in unrealized net losses and $5.0 million in realized losses within commodity derivative gain (loss) in the Consolidated Statements of Operations for the year ended December 31, 2009 attributable to these basis only swaps.

During the year ended December 31, 2009, we also entered into swap contracts to hedge the price received for the sale of our NGL. Our NGL hedges were not designated as cash flow hedges, and the fair value of these derivative instruments were recorded in earnings. As of December 31, 2009, we had NGL hedges in place for a portion of our anticipated NGL sales in 2010 for a total of 4,200,000 gallons. We recognized $0.2 million in unrealized loss within commodity derivative gain (loss) in the Consolidated Statements of Operations for the year ended December 31, 2009 attributable to these NGL swaps.

At December 31, 2009, the estimated fair value of all of our commodity derivative instruments was a net asset of $51.5 million, comprised of current and noncurrent assets and liabilities. We will reclassify the appropriate cash flow hedge amounts from OCI to natural gas and oil production operating revenues as the hedged production quantities are produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of December 31, 2009 to be reclassified from OCI to earnings in the next 12 months would be a gain of approximately $45.7 million. 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 derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods.

The hedge instruments designated as cash flow hedges are at liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale, which may result in ineffectiveness. Ineffectiveness related to our cash flow derivative instruments for the year ended December 31, 2009 was a loss of $5.6 million, which was reported in commodity derivative gain (loss) in the Consolidated Statements of Operations. Although those derivatives may not achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

The table below summarizes the realized and unrealized gains and losses we incurred related to our oil, natural gas and NGL derivative instruments for the periods indicated:

 

     Year Ended December 31,
         2009             2008    
     (in thousands)

Realized gains on derivatives designated as cash flow hedges(1)

   $ 282,734      $ 31,900
              

Realized gains (losses) on derivatives not designated as cash flow hedges

   $ (10,902   $ 62

Unrealized ineffectiveness gains (losses) recognized on derivatives designated as cash flow hedges

     (5,572     6,803

Unrealized gains (losses) on derivatives not designated as cash flow hedges

     (38,093     1,055
              

Total commodity derivative gain (loss)(2)

   $ (54,567   $ 7,920
              

 

(1) Included in “Oil and gas production” revenues in the Condensed Consolidated Statements of Operations.
(2) Included in “Commodity derivative gain (loss)” in the Condensed Consolidated Statements of Operations.

 

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The following table summarizes all of our hedges in place as of December 31, 2009:

 

Contract

  Total
Hedged
Volumes
  Quantity
Type
  Weighted
Average
Floor

Price
  Weighted
Average
Ceiling
Price
  Weighted
Average
Fixed

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

Cashless Collars:

               

2010

               

Natural gas

  6,080,000   MMBtu   $ 6.00   $ 10.41     N/A     N/A      NWPL   $ 6,433   

Natural gas

  2,140,000   MMBtu   $ 7.00   $ 11.00     N/A     N/A      TCO   $ 3,234   

Natural gas

  1,982,500   MMBtu   $ 4.87   $ 5.66     N/A     N/A      CIGRM   $ (193

Oil

  146,000   Bbls   $ 80.00   $ 148.13     N/A     N/A      WTI   $ 1,302   

2011

               

Natural gas

  2,140,000   MMBtu   $ 4.75   $ 6.00     N/A     N/A      CIGRM   $ (332

Swap Contracts:

               

2010

               

Natural gas

  41,052,500   MMBtu     N/A     N/A   $ 6.57     N/A      CIGRM   $ 50,250   

Natural gas

  5,175,000   MMBtu     N/A     N/A   $ 6.42     N/A      NWPL   $ 4,136   

Natural gas

  2,590,000   MMBtu     N/A     N/A   $ 8.74     N/A      DA   $ 7,323   

Natural gas

  1,666,000   MMBtu     N/A     N/A   $ 7.74     N/A      PEPL   $ 3,785   

Natural gas

  450,000   MMBtu     N/A     N/A   $ 5.33     N/A      TCO   $ (240

Natural gas liquids

  4,200,000   Gallons     N/A     N/A   $ 0.91     N/A      Mt. Belvieu   $ (215

Oil

  146,000   Bbls     N/A     N/A   $ 76.89     N/A      WTI   $ (776

2011

               

Natural gas

  25,010,000   MMBtu     N/A     N/A   $ 6.20     N/A      CIGRM   $ 10,799   

Natural gas

  10,252,500   MMBtu     N/A     N/A   $ 6.19     N/A      NWPL   $ 3,732   

2012

               

Natural gas

  915,000   MMBtu     N/A     N/A   $ 5.96     N/A      CIGRM   $ 84   

Basis Only Swap Contracts(2):

               

2010

               

Natural gas

  6,690,000   MMBtu     N/A     N/A     N/A   $ (2.49   NWPL   $ (14,069

Natural gas

  6,250,000   MMBtu     N/A     N/A     N/A   $ (2.34   CIGRM   $ (11,863

2011

               

Natural gas

  7,300,000   MMBtu     N/A     N/A     N/A   $ (1.72   NWPL   $ (8,297

2012

               

Natural gas

  3,660,000   MMBtu     N/A     N/A     N/A   $ (1.24   NWPL   $ (1,900

Natural gas

  3,660,000   MMBtu     N/A     N/A     N/A   $ (1.20   CIGRM   $ (1,710

The following table includes all hedges entered into subsequent to December 31, 2009 through January 29, 2010.

 

Contract

  Total
Hedged
Volumes
  Quantity
Type
  Weighted
Average
Floor
Price
  Weighted
Average
Ceiling
Price
  Weighted
Average
Fixed
Price
  Basis
Differential
  Index Price

Swap Contracts:

             

2010

             

Natural gas

  305,000   MMBtu   N/A   N/A   $ 6.04   N/A   NWPL

Natural gas liquids

  7,875,000   Gallons   N/A   N/A   $ 1.01   N/A   Mt. Belvieu

Oil

  69,900   Bbls   N/A   N/A   $ 85.60   N/A   WTI

2011

             

Natural gas

  225,000   MMBtu   N/A   N/A   $ 5,92   N/A   NWPL

 

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(1) CIGRM refers to Colorado Interstate Gas Rocky Mountains, TCO refers to Columbia Gas Transmission Corporation for Appalachia, NWPL refers to Northwest Pipeline Corporation, DA refers to Dominion Transmission Inc. for Appalachia 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. Mt. Belvieu refers to the average daily price as quoted by Oil Price Information Service (“OPIS”) for Mont Belvieu spot gas liquids prices. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.
(2) Represents a swap of the basis differential between the NYMEX price and the spot price of the index listed under Index Price above.

By removing the price volatility from a portion of our natural gas, NGL and oil revenue for 2010 and a portion of our natural gas revenue for 2011 and 2012, 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.

By using derivative instruments that are not traded or settled on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, 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 and that are lenders in our Amended Credit Facility, affiliates of lenders in our Amended Credit Facility or potential lenders in our Amended Credit Facility. The creditworthiness of our counterparties is subject to continual review. Furthermore, our derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). The ISDAs contain set-off provisions that, in the event of counterparty default, allow us to net our receivables with amounts that we owe the counterparties under our Amended Credit Facility or other general obligations.

We believe all of our counterparties currently are acceptable credit risks. We are not required to provide credit support or collateral to any of our counterparties other than cross collateralization with the properties securing our Amended Credit Facility, nor are they required to provide credit support to us. As of January 29, 2010, we have no past due receivables from any of our counterparties.

Capital Expenditures

Our capital expenditures are summarized in the following tables:

 

     Year Ended December 31,
     2009    2008    2007
     (in millions)

Basin/Area

        

Uinta

   $ 93.7    $ 223.7    $ 166.4

Piceance(1)

     254.8      249.8      180.3

Powder River

     13.9      36.9      39.3

Wind River

     5.1      33.0      10.5

Paradox

     25.2      30.6      18.2

Other

     13.7      27.1      29.0
                    

Total

   $ 406.4    $ 601.1    $ 443.7
                    

 

(1) Includes $60.0 million for the acquisition of Cottonwood Gulch during the year ended December 31, 2009.

 

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     Year Ended December 31,
     2009    2008    2007
     (in millions)

Acquisitions of proved and unevaluated properties and other real estate

   $ 71.8    $ 39.4    $ 25.9

Drilling, development, exploration and exploitation of natural gas and oil properties(1)

     329.3      548.7      404.4

Geologic and geophysical costs

     3.2      8.1      8.8

Furniture, fixtures and equipment

     2.1      4.9      4.6
                    

Total(2)

   $ 406.4    $ 601.1    $ 443.7
                    

 

(1) Includes related gathering and facilities costs.
(2) For the years ended December 31, 2009, 2008 and 2007, we received $3.7 million, $2.4 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.

Acquisitions of proved and unevaluated properties and other real estate was $71.8 million for the year ended December 31, 2009. This was primarily related to our acquisition of the Cottonwood Gulch unevaluated properties in the Piceance Basin for $60.0 million. The decrease in drilling development, exploration and exploitation of natural gas and oil properties of $219.4 million from $548.7 million for the year ended December 31, 2008, is related to a decrease in drilling and completion activities due to lower natural gas prices as well as aligning our capital spending with cash flows from operations for the year ended December 31, 2009.

Due to current commodity price forecasts, we plan to align capital spending before acquisitions with cash flow from operations again in 2010. Our current estimate is for a capital expenditure budget of up to $425.0 million in 2010, which may be adjusted throughout the year as business conditions warrant. We believe that we have sufficient available liquidity through 2010 with the Amended Credit Facility, our hedge positions and cash flow from operations to fund our budgeted capital expenditures. 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 of cash flow to maintain planned levels of capital expenditures.

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 generally 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, including acquisitions and divestitures, in response to changes in prices, availability of financing, 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 and other factors both within and outside of our control.

Financing Activities

Credit Facility. On April 15, 2009, we amended our credit facility (the “Amended Credit Facility”). The Amended Credit Facility bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 1.75% to 2.50% (an increase from 1.25% to 2.00% previously) or an alternate base rate, based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.00% plus applicable margins ranging from 0.75% to 1.50% (an increase from 0.25% to 1.00% previously). The average annual interest rates incurred on the Amended Credit Facility were 2.2% and 5.5% for the years ended December 31, 2009 and 2008, respectively. Based on our mid-year 2009 proved reserves and hedge positions, the borrowing base under the Amended Credit Facility was increased to $630.0 million with commitments of $592.8 million effective October 9, 2009. Future borrowing

 

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bases will be computed based on proved natural gas and oil reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt. The borrowing base is required to be redetermined twice per year. We pay commitment fees ranging from 0.35% to 0.50% 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 “Item 7A. Quantitative and Qualitative Disclosure about Market Risk—Interest Rate Risks” below.

As of December 31, 2009 and 2008, borrowings outstanding under the Amended Credit Facility totaled $5.0 and $254.0 million, respectively. The reduction in borrowings resulted from our application of the proceeds from our Senior Notes issued in July 2009, as discussed below. 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.

We had two interest rate derivative contracts to manage our exposure to changes in interest rates. Both contracts were completely settled on December 12, 2009. 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. Under the swap, we made payments to (or received payments from) the contract counterparty when the variable rate of one-month LIBOR fell below (or exceeded) the fixed rate of 4.70%. Under the collar, we made payments to (or received payments from) the contract counterparty when the variable rate fell below the floor rate of 4.50% or exceeded the ceiling rate of 4.95%. Our interest rate derivative instruments were designated as cash flow hedges. Changes in fair value of the interest rate swaps or collars were reported in OCI, to the extent the hedge was effective, until the forecasted transaction occurred, at which time they were recorded as adjustments to interest expense. Ineffectiveness related to such derivative instruments was de minimis for both years ended December 31, 2009 and 2008. During the year ended December 31, 2009, settlement payments on the interest rate derivative contracts, which were included in interest expense, were $0.8 million.

Convertible Notes. On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. The full $172.5 million principal amount of the Convertible Notes is currently outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by us. The conversion price is approximately $66.33 per share of our common stock, equal to the applicable conversion rate of 15.0761 shares of our common stock, subject to adjustment upon certain events. Upon conversion of the Convertible Notes, holders will receive, at our election, cash, shares of common stock or a combination of cash and shares of common stock. The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year, beginning September 15, 2008. There is no established market for the Convertible Notes, and the Convertible Notes are not traded on a public exchange. Therefore, based on market-based parameters of the various components of the Convertible Notes, the estimated fair value was approximately $166.1 million as of December 31, 2009.

On or after March 26, 2012, at our option we may redeem for cash all or a portion of the Convertible Notes at a redemption price equal to 100% of the principal amount of the Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, up to, but excluding, the applicable redemption date. In satisfaction of our obligation upon conversion of the Convertible Notes, we may elect to deliver, at our option, cash, shares of our common stock or a combination of cash and shares of our common stock. We currently intend to net cash settle the Convertible Notes. However, we have not made a formal legal irrevocable election to net cash settle and reserve the right to settle the Convertible Notes in any manner allowed under the indenture for the Convertible Notes as business conditions warrant.

Holders of the Convertible Notes may require us to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2012March 20, 2015March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date.

 

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Holders may convert their Convertible Notes into cash, shares of our common stock, or a combination of cash and shares of our common stock, as elected by us, at any time prior to the close of business on September 20, 2027, if any of the following conditions are satisfied: (1) if the closing price of our common stock reaches specified thresholds or the trading price of the Convertible Notes falls below specified thresholds; (2) if the Convertible Notes have been called for redemption; (3) if we make certain significant distributions to holders of our common stock, or (4) we enter into specified corporate transactions, none of which occurred during 2009 or through the date of the filing of this Form 10-K. After September 20, 2027, holders may surrender their Convertible Notes for conversion at any time prior to the close of business on the business day immediately preceding the maturity date regardless of whether any of the foregoing conditions have been satisfied.

In addition, following certain corporate transactions that constitute a qualifying fundamental change, we are required to increase the applicable conversion rate for a holder who elects to convert its Convertible Notes in connection with such corporate transactions in certain circumstances.

Effective January 1, 2009, we adopted, and retrospectively applied, the new authoritative accounting guidance under ASC Topic 470. Upon adoption, we recorded a debt discount of $23.1 million as of the date of the issuance of the Convertible Notes. The debt discount is amortized as additional non-cash interest expense over the expected term of the Convertible Notes through March 2012. The amount of non-cash interest expense for the year ended December 31, 2009 and 2008 related to the Convertible Notes was $6.5 million and $4.9 million, respectively. The amount of the cash interest expense recognized for the year ended December 31, 2009 and 2008 related to the 5% contractual interest coupon was $8.6 million and $6.9 million, respectively. Including the non-cash interest expense, the effective interest rate on our Convertible Notes is 9.7% per annum.

As of December 31, 2009, the net carrying amount of the Convertible Notes is as follows (amounts in thousands):

 

Principal amount of the Convertible Notes

   $ 172,500   

Unamortized debt discount

     (13,728
        

Carrying amount of the Convertible Notes

   $ 158,772   
        

Senior Notes. On July 8, 2009, we issued $250.0 million in principal amount of 9.875% Senior Notes due 2016 at 95.172% of par. The Senior Notes will mature on July 15, 2016. Interest is payable in arrears semi-annually on January 15 and July 15, beginning January 15, 2010. We received net proceeds of $232.3 million (net of related offering costs), which were used to repay a portion of the borrowings under the Amended Credit Facility. The Senior Notes are our senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes. The Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under our Amended Credit Facility. As a result of the guarantee by the guarantor subsidiaries of the Senior Notes, the terms of the Convertible Notes require the guarantor subsidiaries to also guarantee the Convertible Notes.

The Senior Notes are redeemable, at our option, at 104.938% of the principal amount after July 15, 2013, declining to 100.00% in 2015. Prior to July 15, 2013, we may, at our option, redeem the Senior Notes at a make-whole price comprised of the greater of 100% of the principal amount or the present value of 104.938% of the principal amount plus a make-whole amount. The make-whole amount is the present value of the remaining interest payments due on the Senior Notes as if such notes were redeemed on July 15, 2013 computed using a discount rate equal to the Treasury Rate plus 50 basis points, over the principal amount of the Senior Notes. We may redeem up to 35% of the aggregate principal amount of the Senior Notes at a price of 109.875% of the principal amount plus accrued interest upon the issuance of equity securities until July 15, 2012. If a specified change of control occurs, we must make an offer to purchase the notes at 101% of the principal amount plus any accrued interest. Additionally, certain asset dispositions that are not reinvested in 360 days may require us to offer to purchase the notes at 100% of principal plus accrued interest. The Senior Notes include certain covenants that limit our ability to incur additional indebtedness, pay dividends, make restricted payments, create liens and sell assets. We are in compliance with all covenants for all periods.

 

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The debt discount is amortized as additional non-cash interest expense over the term of the Senior Notes. As of December 31, 2009, the net carrying amount of the Senior Notes is as follows (amounts in thousands):

 

Principal amount of the Senior Notes

   $ 250,000   

Unamortized debt discount

     (11,522
        

Carrying amount of the Senior Notes

   $ 238,478   
        

As a result of the amortization of the debt discount and amortization of the transaction costs through non-cash interest expense, the effective interest rate on the Senior Notes is 11.2% per annum. The amount of the cash interest expense recognized with respect to the 9.875% contractual interest coupon for year ended December 31, 2009 was $11.8 million. The amount of non-cash interest expense related to the amortization of the debt discount and amortization of the transaction costs for the year ended December 31, 2009 was $1.0 million. The aggregate estimated fair value of the Senior Notes was approximately $267.5 million as of December 31, 2009.

Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody’s Investor Services and Standard & Poor’s Rating Services currently rate our Senior Notes and have assigned us a credit rating. We do not have any provisions that are linked to our credit ratings, nor do we have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, Convertible Notes or the Senior Notes. However, our ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.

Shelf Registration Statement. We have on file with the SEC an effective universal shelf registration statement to allow us to offer an indeterminate amount of securities in the future. Under the registration statement, we may periodically offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. However, we recognize that the issuance of additional securities in periods of market volatility may be less likely. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

Contractual Obligations. A summary of our contractual obligations as of and subsequent to December 31, 2009 is provided in the following table:

 

    Payments Due By Year
    2010   2011   2012   2013   2014   After 2014   Total
    (in thousands)

Notes payable(1)

  $ —     $ 5,000   $ —     $ —     $ —     $ —     $ 5,000

Senior Notes(2)

    24,688     24,688     24,688     24,688     24,688     288,060     411,500

Convertible Notes(3)

    8,625     8,625     174,536     —       —       —       191,786

Purchase commitments(4)(8)

    5,520     9,419     —       —       —       —       14,939

Drilling rig commitments(5)(8)

    16,894     3,075     —       —       —       —       19,969

Office and office equipment leases and other

    3,580     1,117     275     222     222     505     5,921

Firm transportation and processing agreements(8)

    30,003     47,117     55,281     53,910     53,896     277,647     517,854

Asset retirement obligations(6)

    702     9,480     1,714     1,027     906     35,237     49,066

Derivative liability(7)

    9,354     11,279     3,526     —       —       —       24,159
                                         

Total

  $ 99,366   $ 119,800   $ 260,020   $ 79,847   $ 79,712   $ 601,449   $ 1,240,194
                                         

 

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(1) Included in notes payable is the outstanding principal amount under our Amended Credit Facility. This table does not include future commitment fees, interest expense or other fees on our Amended Credit Facility because the Amended 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) On July 8, 2009, we issued $250.0 million aggregate principal amount of Senior Notes. We are obligated to make annual interest payments equal to $24.7 million.
(3) On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. For purposes of contractual obligations, we assume that the holders of our Convertible Notes will not exercise the conversion feature, and we will therefore repay the $172.5 million in cash. We currently expect the Convertible Notes to be redeemed in 2012. We are also obligated to make annual interest payments equal to $8.6 million.
(4) We have a take-or-pay CO2 purchasing agreement that expires in October 2011 that has a minimum volume commitment to purchase CO2 at a contracted price, subject to annual escalation. The contract provides CO2 used in fracturing operations in our West Tavaputs field. Should we not take delivery of the minimum volume required, we would be obligated to pay for the deficiency. At this time, our planned volumes needed exceed the minimum requirement, and we do not anticipate any deficiency payments.
(5) We currently have three drilling rigs under contract. Two contracts expire in 2010, and one contract expires in 2011. All other rigs currently performing work for us are on a well-by-well basis and, therefore, can be released without penalty at the conclusion of drilling on the current well. These latter types of drilling obligations have not been included in the table above.
(6) 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.
(7) Derivative liabilities represent the fair value for derivatives presented as liabilities in our Condensed Consolidated Balance Sheets as of December 31, 2009. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See “—Critical Accounting Policies and Estimates” below for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.
(8) The values in the table represent the gross amounts that we are financially committed to pay. However, we will record in our financials our proportionate share based on our working interest and net revenue interest, which will vary from basin to basin.

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 one to 14 years and require us to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by us, which are included in the Contractual Obligations table above.

Trends and Uncertainties

Regulatory Trends

Our future Rocky Mountain operations and cost of doing business may be affected by changes in regulations and the ability to obtain drilling permits. The regulatory environment continues to become more restrictive, which limits our ability and increases the cost to conduct our operations. Areas in which we operate are subject to federal, state, local and tribal regulations. All these jurisdictions have imposed additional and more restrictive regulations recently and there are initiatives underway to implement additional regulations and prohibitions on oil and gas activities. New rules may impact the ability and extend the time necessary to obtain drilling permits, which creates substantial uncertainty about our production and capital expenditure targets.

Federal. At the federal level, the policies of the new administration and the Department of Interior suggest a more restrictive regulatory environment for oil and gas activities on public lands. The Secretary of Interior has issued policy directives that will require additional analysis prior to leasing federal lands. These policies are

 

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directed at reducing controversy and improving predictability of the leasing process. Until these policies are implemented and the requisite analyses are completed, the rate of federal leasing will be decreased. The BLM and the U.S. Forest Service also have withdrawn parcels from planned lease sales in areas near our operations. A lawsuit seeks review of federal resource management plans prepared by the BLM for areas of Utah, including areas in which we operate. If this challenge is successful, it could impact our ability to operate and the issuance of the EIS for our West Tavaputs full field development. Additional litigation seeking to halt our and other companies’ exploration and development activities in the West Tavaputs area and throughout the Rocky Mountain Region can be expected. Proposals to cause expiration of undeveloped leases, eliminate funding for processing of Federal drilling permits, and to eliminate categorical exclusions for oil and gas activities have been reintroduced.

The practice of hydraulic fracturing formations to stimulate production of natural gas and oil has come under increased scrutiny by the environmental community. In reaction, moratoria have been imposed and legislation proposed at local, state and federal levels. While these proposals have not materially affected our ability to operate, adaption of certain proposals, in jurisdictions in which we operated, would adversely affect the Company.

State. We also are experiencing increased attempts to more strictly regulate oil and gas activities at the state level. New rules have been imposed by the COGCC. Legislation has been introduced in other states that mimics that passed in Colorado and several states have proposed severance tax increases.

Local. Counties in Colorado and other states regulate oil and gas activities through local land use rules. Garfield County, Colorado, where our Piceance Basin operations are located, has begun requiring special use permits for activities that previously were regulated by the COGCC, adding new requirements and delays over previous operations. We expect additional attempts to regulate activities related to oil and gas operations by counties and local governments.

Tribal. We have experienced delays in obtaining permits to drill wells on tribal property, including our Lake Canyon and Black Tail Ridge projects. The failure to obtain permits has led us to declare a force majeure event in order to protect our rights under our Black Tail Ridge exploration and development agreement. Because of the current staffing of the permitting authority, we believe that delays in obtaining permits will continue for the foreseeable future, which will delay our ability to drill wells in these areas.

Potential Impacts of Regulatory Trends. The increase in regulatory burdens and potential for continued lawsuits seeking to block activities as described above is likely to cause delays to our planned activities and could prevent some of these activities. This is expected to increase our costs and could result in lower production and reserves as our properties naturally decline without replacement production and reserves from new wells as well as a reduction in the value of our accumulated leases, especially federal leases which make up approximately 50% of our leasehold. We currently are unable to estimate the magnitude of these potential losses. Without regulatory approvals to allow full field development in our West Tavaputs area or to commence activities in our Cottonwood Gulch area or the acquisition of additional development properties, our reserves will flatten beginning in 2011 and then decline as production reduces reserves without the addition of reserves from new drilling activity.

Declining Commodity Prices

Over the past year, we have experienced declines in average natural gas and oil prices but prices have rebounded recently. If average prices decline and remain at low levels, it could increase the likelihood of impairments and write-downs of properties, reduce our reserves and thus the borrowing base of our Amended Credit Facility, We have protected approximately 60% of our 2010 production as well as 30-40% of our 2011 production with hedges. However our ability to hedge at price levels similar to those for 2008 and 2009 is unlikely given current future prices, which could result in a decline in our revenues.

 

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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 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. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized. 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. In addition to development on exploratory wells, we may drill scientific wells that are only used for data gathering purposes. The costs associated with these scientific wells are expensed as incurred as geological and geophysical expense. 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 oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unevaluated oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage. During the year ended December 31, 2009, we did not recognize any impairment charges associated with unevaluated oil and gas property costs. In 2008, we recognized a non-cash impairment charge of $4.3 million primarily on the carrying value of unevaluated oil and gas properties in the Talon field located in the Wind River Basin. We sold the Talon field in 2009.

 

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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 undiscounted 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, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the expected cash flows projected. During the year ended December 31, 2009, our impairment analysis required us to take a non-cash impairment charge to our proved oil and gas properties in the North Hill Creek field, located in the Uinta Basin, of $2.8 million and in the Yellow Jacket prospect, located in the Paradox Basin, of $16.9 million. In 2008, our impairment analysis required us to take a non-cash impairment charge to our proved oil and gas properties in the Cooper Reservoir field, located in the Wind River Basin, of $21.0 million, which was primarily the result of geologic and engineering reevaluations, as well as lower oil and gas prices.

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 anticipation 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. The present value of the estimated future costs to dismantle, abandon and restore a well location 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 amounts, future advances in technology, timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. 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, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors and changes to our credit-adjusted risk-free rate as market conditions warrant. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our DD&A expense in future periods.

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 and natural gas, 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 estimates are audited on a well-by-well basis by an independent third party engineering firm.

 

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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 reserves estimates. We prepare our reserves estimates, and the projected cash flows derived from these reserves estimates, in accordance with SEC guidelines. Our independent third party engineering firm adheres to the same guidelines when auditing our reserve reports. The accuracy of our reserves 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 reserves estimates.

The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserves estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in our financial statements. As such, reserves estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.

At December 31, 2009, we revised our proved reserves upward by 101.5 Bcfe, excluding pricing revision, due to improved production performance in Gibson Gulch, West Tavaputs and Blacktail Ridge and the recovery of NGL and reduced drilling and completion costs in Gibson Gulch. Also included in the engineering revisions is the addition of 64 Bcfe from second proved undeveloped offsets added in Gibson Gulch. The pricing revision at year-end 2009 based on prices of $3.04 per MMBtu and $57.65 per barrel of oil required under new SEC rules for estimating reserves, relative to the year-end 2008 prices of $4.61 per MMBtu and $41.00 per barrel of oil required under the former SEC rules, was downward 42.8 Bcfe. Prices were adjusted by lease for quality, transportation fees and regional price differences. See “Items 1 and 2. Business and Properties—Oil and Gas Data—Proved Reserves” for the specific impact on our reserves as a result of the new SEC rules.

As of December 31, 2008, we revised our proved reserves upward by 146.4 Bcfe, excluding pricing revisions, primarily as a result of adding increased density in proved undeveloped locations in the Piceance and West Tavaputs fields and improved production performance by wells located in each of our major producing basins: Wind River, Uinta, Powder River and Piceance. The pricing revision at year-end 2008 at prices of $4.61 per MMBtu and $41.00 per barrel of oil, relative to the year-end 2007 prices of $6.04 per MMBtu and $92.50 per barrel of oil, was downward 7.3 Bcfe. Year-end 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. Year-end prices were adjusted by lease for quality, transportation fees and regional price differences.

Revenue Recognition

We record revenues from the sales of natural gas, NGL and oil in the month that delivery to the purchaser has occurred and title has transferred. 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. Historically, any differences have been insignificant.

 

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Derivative Instruments and Hedging Activities

We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas, NGL, and oil production by reducing our exposure to price fluctuations. For the year ended December 31, 2009, these transactions included swaps, basis only swaps and cashless collars. These derivative instruments are 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. We are required 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.

For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in OCI 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 use financial derivative instruments that have not been designated as hedges, but they still protect us from changes in commodity prices. These instruments are marked to market with the resulting changes in fair value recorded in earnings.

The estimates of the fair values of our derivative instruments require substantial judgment. These values are based upon, among other things, option pricing models, 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.

Changes in estimates of fair value have only a minimal impact on our liquidity, capital resources or results of operations, as long as the derivative instruments qualify for cash flow hedge accounting treatment. Changes in the fair values of derivatives that do not qualify for cash flow hedge accounting treatment can have an impact on our results of operations and could include large non-cash fluctuations, but generally will not impact our liquidity or capital resources. Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative instruments, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments.

As of December 31, 2009, the fair value of all of our derivative instruments, including basis only and NGL swaps that are not designated as cash flow hedges, was a net asset of $51.5 million, comprised of current and noncurrent assets and liabilities. The deferred income tax effect on the fair value of the cash flow hedge derivatives at December 31, 2009 totaled $32.9 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 differences between financial statement and income tax reporting. We routinely assess the realizability of our

 

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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). There can be no assurance that facts and circumstances will not materially change and require us to establish deferred tax asset valuation allowances in a future period.

Stock-based Compensation

We recognize compensation expense for all share-based payment awards made to employees and directors. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite service period, which is generally the vesting period. Judgments and estimates are made regarding, among other things, the appropriate valuation methodology to follow in valuing stock compensation awards and the related inputs required by those valuation methodologies. Assumptions regarding expected volatility of our common stock, the risk-free interest rates, expected term of the awards and other valuation inputs are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized.

We recorded non-cash stock-based compensation expense of $16.9 million, $16.8 million, and $9.9 million for the years ended December 31, 2009, 2008 and 2007, respectively, for option grants, option modifications, nonvested equity shares of common stock and nonvested performance-based equity shares of common stock.

New Accounting Pronouncements. In June 2009, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 168, The FASB Accounting Standards Codification (“ASC”) and the Hierarchy of Generally Accepted Accounting Principle, as codified in FASB ASC Topic 105, Generally Accepted Accounting Principles. This standard establishes only two levels of U.S. GAAP, authoritative and nonauthoritative. The FASB ASC became the source of authoritative, nongovernmental GAAP, except for rules and interpretive releases of the SEC, which are sources of authoritative GAAP for SEC registrants. All other non-grandfathered, non-SEC accounting literature not included in the Codification became nonauthoritative. This standard is effective for financial statements for interim or annual reporting periods ending after September 15, 2009. As the ASC was not intended to change or alter existing GAAP, the adoption of SFAS No. 168 on July 1, 2009 did not have any impact on our financial statements other than to change the numbering system prescribed by the FASB ASC when referring to GAAP

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. (“SFAS No. 157”), as codified in ASC Topic 820, Fair Value Measurements and Disclosures. This standard defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement. As of January 1, 2009, we fully adopted this standard, requiring fair value measurements of nonfinancial assets and nonfinancial liabilities, including nonfinancial long-lived assets measured at fair value for an impairment assessment and asset retirement obligations initially measured at fair value. The full adoption of SFAS No. 157 did not have a material impact on our financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”), as codified in ASC Topic 805, 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’s 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 and was effective for us beginning January 1, 2009 but will only impact us if and when we become party to a business combination.

 

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In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS No. 161”) as codified in ASC Topic 815, Derivatives and Hedging. This statement is intended to improve financial reporting about derivative instruments and hedging activities by requiring companies to enhance disclosure about how these instruments and activities affect their financial position, performance and cash flows. It seeks to achieve these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also seeks to improve the transparency of the location and amounts of derivative instruments in a company’s financial statements and how they are accounted for. This statement was effective for us beginning January 1, 2009. See Note 8 to the financial statements for the applicable disclosures.

In May 2008, the FASB issued FASB Staff Position (“FSP”) Accounting Principles Board (“APB”) 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (including Partial Cash Settlement), as codified in ASC Subtopic 470-20, Debt with Conversion and Other Options. This standard states that the accounting treatment for certain convertible debt instruments that may be settled in cash, shares of common stock or any portion thereof at the election of the issuing company be accounted for utilizing a bifurcation model under which the value of the debt instrument is determined without regard to the conversion feature. The difference between the issuance amount of the debt instrument and the value determined pursuant to FSP APB 14-1 is recorded as an equity contribution. The resulting debt discount is amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. This standard was effective for financial statements issued for fiscal years beginning after December 15, 2008, and early adoption was not permitted. We adopted this standard effective January 1, 2009. FSP APB 14-1 changed the accounting treatment for the Convertible Notes that were issued in March 2008. See Note 5 to the financial statements for additional disclosures associated with the adoption of this standard. FSP APB 14-1 was required to be applied retrospectively for any instrument within the scope of FSP APB 14-1 that was outstanding during any of the periods presented. As a result of the retrospective application, certain amounts in our consolidated financial statements for the year ended December 31, 2008 have been adjusted as was previously reported in our Current Report on Form 8-K filed on June 24, 2009.

On December 31, 2008, the SEC adopted the final rules and interpretations updating its oil and gas reserves reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which is a widely accepted set of evaluation guidelines that are designed to support assessment processes throughout the resource asset lifecycle. These guidelines were prepared by the SPE Oil and Gas Reserves Committee with cooperation from many industry organizations. One of the key changes to the previous SEC rules relates to using a 12-month average commodity price to calculate the value of proved reserves versus the current method of using year-end prices. Other key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, the opportunity to establish proved undeveloped reserves without the requirement of an adjacent producing well and permitting disclosure of probable and possible reserves. The SEC required companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009. Early adoption was not permitted. The new SEC rules were effective for this filing, and all new rules and disclosure requirements have been incorporated herein. See “Items 1 and 2. Business and Properties—Oil and Gas Data—Proved Reserves” for the specific impact on our reserves as a result of the new SEC rules.

In April 2009, the FASB issued staff positions intended to provide additional application guidance and enhance disclosures regarding fair value measurements. FSP SFAS No. 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, intends to provide guidelines for making fair value measurements more consistent with the principles presented in SFAS No. 157. FSP SFAS No. 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, attempt to enhance consistency in financial reporting by increasing the frequency of fair value disclosures. These statements, as codified in ASC Topic 820, Fair Value

 

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Measurements and Disclosures, are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The adoption of these statements did not have a material impact on our financial statements.

In May 2009, the FASB issued SFAS No. 165, Subsequent Events, as codified in ASC Topic 855, Subsequent Events. The intent of this statement is to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Particular importance has been placed on the period after the balance sheet date during which management should evaluate events or transactions that may occur leading to recognition within the financial statements or disclosure in the financial statements. This standard is effective for interim and annual periods ending after June 15, 2009 and was effective for us beginning June 30, 2009. The adoption of this statement did not have a material impact on our financial statements.

In January 2010, the FASB issued Accounting Standards Update 2010-03, Extractive Activities- Oil and Gas (Topic 932), Oil and Gas Reserve Estimation and Disclosures, which aligned the FASB oil and gas reserve estimation and disclosure requirements with the requirements in the SEC’s final rule as discussed above. The new disclosure requirements were effective for this filing. The adoption changed the methodology in which we calculate proved oil and gas reserves. Our fourth quarter DD&A and impairment calculations were based upon proved reserves that were determined using the new reserve guidelines, whereas DD&A and impairment calculations in previous quarters within 2009 were based on the old methodology.

 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market 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 primary market risk exposure is in the price we received for our natural gas, NGL and oil revenue. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas, NGL and oil 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 collar contracts in place during 2009, our annual income before income taxes for the year ended December 31, 2009 would have decreased by approximately $1.8 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.3 million for each $1.00 per barrel decrease in crude oil prices.

We routinely enter into and anticipate entering into financial hedging activities with respect to a portion of our projected natural gas, NGL and oil revenue through various financial transactions which hedge 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, NGL and oil prices at targeted levels and to manage our exposure to natural gas and oil price fluctuations. In addition to the swaps and collars discussed above, we also entered into basis only swaps. With a basis only swap, we have fixed the difference between the NYMEX price and the price received for our natural gas production at the specific

 

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delivery location to protect against the risk of large differences between NYMEX (Henry Hub) and our primary sales points, CIGRM and NWPL. We may consider entering into hedge transactions based on a NYMEX price in the future with a volume equal to the volume for our basis only swaps, thereby effectively fixing a price for CIGRM or NWPL.

As of January 29, 2010, we have hedges in place for 61,441,000 MMBtu of natural gas production, 12,075,000 gallons of NGL production and 361,900 Bbls of oil production for 2010, 37,852,500 MMBtu of natural gas production for 2011 and 915,000 MMBtu of natural gas production for 2012. In addition, we have basis only swaps in place for 12,940,000 MMBtu of natural gas for 2010, 7,300,000 MMBtu of natural gas for 2011 and 7,320,000 MMBtu of natural gas for 2012. These hedges are summarized in the table presented under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Cash Flow from Operating Activities.”

Interest Rate Risks

At December 31, 2009, we had debt outstanding under our Amended Credit Facility of $5.0 million, which bears interest at floating rates in accordance with our Amended Credit Facility. The average annual interest rate incurred on this debt for the years ended December 31, 2009 and 2008 was 2.2% and 5.5%, respectively. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the year ended December 31, 2009 would have resulted in an estimated $1.6 million increase in interest expense for the year ended December 31, 2009. We also had $172.5 million principal amount of Convertible Notes and $250.0 of Senior Notes outstanding at December 31, 2009, which have a fixed cash interest rates of 5.0% and 9.875% per annum, respectively.

 

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 on Accounting 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 were, as of December 31, 2009, effective.

Management’s Report on Internal Control Over Financial Reporting. Internal control over financial reporting is a process designed by, or under the supervision of, our principal executive and principal financial officers, or persons performing similar functions, and effected by our 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 our 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 our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

 

   

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

 

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Management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, our management 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, our management concluded that our internal control over financial reporting was effective as of December 31, 2009.

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

Changes in Internal Controls. There has been no change in our internal control over financial reporting during the fourth fiscal quarter of 2009 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, 2009, 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, 2009, 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, 2009 of the Company and our report dated February 23, 2010, expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company’s adoption of a new accounting standard.

/s/ Deloitte & Touche LLP

Denver, Colorado

February 23, 2010

 

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Item 9B. Other Information

Not applicable.

 

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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 2010 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2009, and is incorporated by reference to this report.

Code of Business Conduct and Ethics

We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer (our principal executive officer), Chief Financial Officer (our principal financial officer) and Vice President—Accounting (our principal accounting officer) as well as other officers and employees. A copy of our Code of Business Conduct and Ethics is located on our website at www.billbarrettcorp.com under Corporate Governance in the Investor Relations sections.

 

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 2010 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2009, 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 2010 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2009, and is incorporated by reference to this report.

Equity Compensation Plan Information

The following table provides aggregate information presented as of December 31, 2009 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

   4,767,698    $ 30.35 (1)    2,705,549

Equity compensation plans not approved by shareholders

   —        —        —  
                 

Total

   4,767,698    $ 30.35      2,705,549
                 

 

(1) The weighted average exercise price relates to the 4,081,277 outstanding options included in column (a) but does not relate to 686,421 nonvested equity shares of common stock (restricted stock) that also are included in column (a) that do not contain an exercise price.

 

84


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” sections of the proxy statement for the 2010 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2009, and is incorporated by reference to this report.

 

Item 14. Principal Accounting Fees and Services

Information regarding principal accounting fees and services will be included in an amendment to this Form 10-K or in the “Fees to Independent Auditors” section of the proxy statement for the 2010 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2009, and is incorporated by reference to this report.

 

85


PART IV

 

Item 15. Exhibits, Financial Statement Schedules

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules

See “Item 8. Financial Statements and Supplementary Data” beginning on page F-1(a).

(a)(3) Exhibits.

 

Exhibit

Number

 

Description of Exhibits

3.1   Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 of our Current Report on Form 8-K filed with the Commission on December 20, 2004.]
3.2   Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.5 of our Current Report on Form 8-K filed with the Commission on December 20, 2004.]
4.1(a)   Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.1(b)   Indenture, dated March 12, 2008, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
4.1(c)   Indenture, dated July 8, 2009, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on July 8, 2009.]
4.2(a)   Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 of Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
4.2(b)   First Supplemental Indenture, dated March 12, 2008, by and between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 5% Convertible Senior Notes due 2028). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
4.2(c)   First Supplemental Indenture, dated July 8, 2009, by Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 9.875% Senior Notes due 2016). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on July 8, 2009.]
4.3(a)   Stockholders’ Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
4.3(b)   Second Supplemental Indenture, dated July 8, 2009, by Bill Barrett Corporation, Bill Barrett CBM Corporation, Bill Barrett CBM LLC, Circle B Land Company LLC and Deutsche Bank Trust Company Americas, as Trustee (including form of 9.875% Senior Notes due 2016). [Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K with the Commission on July 8, 2009.]
4.4   Form of Rights Agreement concerning Shareholder Rights Plan, which includes, as Exhibit A thereto, the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, and, as Exhibit B thereto, the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]

 

86


Exhibit

Number

 

Description of Exhibits

  4.5   Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
  4.6   Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
10.1(a)   Second Amended and Restated Credit Agreement, dated March 17, 2006, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on March 22, 2006.]
10.1(b)   First Amendment to Second Amended and Restated Credit Agreement dated as November 6, 2007 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on November 7, 2007.]
10.1(c)   Second Amendment to Second Amended and Restated Credit Agreement, dated as of March 4, 2008, among Bill Barrett Corporation, as borrower, the Guarantors, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on March 10, 2008.]
10.1(d)   Third Amendment to Second Amended and Restated Credit Agreement, dated as of October 20, 2008, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on October 21, 2008.]
10.1(e)   Fourth Amendment to Second Amendment and Restated Credit Agreement dated as of April 15, 2009, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated April 16, 2009.]
10.2   Stock Purchase Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 10.2 to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.3(a)*   Form of Indemnification Agreement dated April 15, 2004, between Bill Barrett Corporation and each of the directors and certain executive officers of the Company. [Incorporated by reference to Exhibit 10.10(a) to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.3(b)*   Schedule of officers and directors party to Indemnification Agreements dated April 15, 2004 with Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.10(b) to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.4*   Amended and Restated 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.12 to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.5(a)*   Form of Tranche A Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(a) to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.5(b)*   Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(b) to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]

 

87


Exhibit

Number

 

Description of Exhibits

10.6*   2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to Amendment No. 3 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on September 22, 2004.]
10.7*   Form of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.8   Form of Management Rights Agreement between Bill Barrett Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.9   Regulatory Sideletter, dated March 28, 2002, between J.P. Morgan Partners (BHCA), L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.17 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.10*   Form of Change in Control Severance Protection Agreement, revised as of November 16, 2006, for named executive officers. [Incorporated by reference to Exhibit 10.10 to our Annual Report on Form 10-K for the year ended December 31, 2006.]
10.11*   2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.12*   Revised Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.19 to our Annual Report on Form 10-K for the year ended December 31, 2005.]
10.13*   Form of Restricted Common Stock Award Agreement for 2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10-19 to our Annual Report on Form 10-K for the year ended December 31, 2005.]
10.14(a)*   Form of Performance Vesting Restricted Stock Agreement for 2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10-19 to our Annual Report on Form 10-K for the year ended December 31, 2005.]
10.14(b)   Form of Performance Vesting Restricted Stock Agreement for 2004 Stock Incentive Plan (2009 Temporary Supplemental Grant). [Incorporated by reference to Exhibit 10.14(b) to our Quarterly Report on Form 10-Q for the three months ended March 31, 2009.]
10.15*   2008 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on May 16, 2008.]
10.16*   Form of Stock Option Agreement for 2008 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the year ended December 31, 2008.]
10.17*   Severance Plan. [Incorporated by reference to Exhibit 10.23 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
12.1**   Computation of Ratio of Earnings to Fixed Charges
21.1**   Subsidiaries of the Registrant.
23.1**   Consent of Deloitte & Touche LLP.
23.2**   Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers.

 

88


Exhibit

Number

  

Description of Exhibits

31.1**    Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2**    Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32.**      Section 1350 Certification of Chief Executive Officer and Chief Financial Officer.
99.1**    Report of Netherland, Sewell & Associates, Inc. dated February 2, 2010 concerning audit of oil and gas reserve estimates.

 

* Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)(3).
** Filed herewith.

 

89


SIGNATURES

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

 

   BILL BARRETT CORPORATION
Date: February 23, 2010    By:    /s/     FREDRICK J. BARRETT        
     

Fredrick J. Barrett

Chairman and Chief Executive Officer

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

 

Signature

  

Title

 

Date

/S/    FREDRICK J. BARRETT        

Fredrick J. Barrett

  

Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)

  February 23, 2010

/S/    ROBERT W. HOWARD        

Robert W. Howard

  

Chief Financial Officer and Treasurer (Principal Financial Officer)

  February 23, 2010

/S/    JOSEPH N. JAGGERS        

Joseph N. Jaggers

  

Director; Chief Operating Officer and President

  February 23, 2010

/s/    David R. Macosko        

David R. Macosko

  

Vice President—Accounting (Principal Accounting Officer)

  February 23, 2010

/S/    JAMES M. FITZGIBBONS        

James M. Fitzgibbons

   Director   February 23, 2010

/S/    RANDY A. FOUTCH        

Randy A. Foutch

   Director   February 23, 2010

/S/    JIM W. MOGG        

Jim W. Mogg

   Director   February 23, 2010

/S/    EDMUND P. SEGNER, III        

Edmund P. Segner, III

   Director   February 23, 2010

/S/    RANDY STEIN        

Randy Stein

   Director   February 23, 2010

/S/    MICHAEL E. WILEY        

Michael E. Wiley

   Director   February 23, 2010

 

90


FINANCIAL STATEMENTS

INDEX TO FINANCIAL STATEMENTS

 

Bill Barrett Corporation

  

Report of Independent Registered Public Accounting Firm

   F-2

Consolidated Balance Sheets, December 31, 2009 and 2008

   F-3

Consolidated Statements of Operations, for the years ended December 31, 2009, 2008 and 2007

   F-4

Consolidated Statements of Stockholders’ Equity and Comprehensive Income, for the years ended December 31, 2009, 2008 and 2007

   F-5

Consolidated Statements of Cash Flows, for the years ended December 31, 2009, 2008 and 2007

   F-6

Notes to Consolidated Financial Statements

   F-7

 

F-1


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Bill Barrett Corporation

Denver, Colorado

We have audited the accompanying consolidated balance sheets of Bill Barrett Corporation and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits 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 the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Bill Barrett Corporation and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of oil and gas reserve estimation and related required disclosures in 2009 with the implementation of new accounting guidance.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Denver, Colorado

February 23, 2010

 

F-2


BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

 

     As of December 31,  
     2009     2008  
     (in thousands, except share
and per share data)
 

Assets:

    

Current Assets:

    

Cash and cash equivalents

   $ 54,405      $ 43,063   

Accounts receivable, net of allowance for doubtful accounts of $886 and $840 as of December 31, 2009 and 2008, respectively

     62,573        66,427   

Prepayments and other current assets

     4,600        3,924   

Derivative assets

     58,461        199,960   
                

Total current assets

     180,039        313,374   

Property and Equipment—At cost, successful efforts method for oil and gas properties:

    

Proved oil and gas properties

     2,360,200        1,977,535   

Unevaluated oil and gas properties, excluded from amortization

     274,819        315,239   

Oil and gas properties held for sale

     5,604        —     

Furniture, equipment and other

     24,727        20,971   
                
     2,665,350        2,313,745   

Accumulated depreciation, depletion, amortization and impairment

     (1,006,090     (751,926
                

Total property and equipment, net

     1,659,260        1,561,819   

Derivative Assets

     17,181        113,815   

Deferred Financing Costs and Other Noncurrent Assets

     9,643        5,485   
                

Total

   $ 1,866,123      $ 1,994,493   
                

Liabilities and Stockholders’ Equity:

    

Current Liabilities:

    

Accounts payable and accrued liabilities

   $ 71,992      $ 100,552   

Amounts payable to oil and gas property owners

     20,155        17,067   

Production taxes payable

     34,584        36,236   

Derivative liability and other current liabilities

     9,354        511   

Deferred income taxes

     17,207        71,428   
                

Total current liabilities

     153,292        225,794   

Note Payable to Bank

     5,000        254,000   

Senior Notes

     238,478        —     

Convertible Senior Notes

     158,772        153,411   

Asset Retirement Obligations

     46,785        46,687   

Liabilities Associated with Assets Held for Sale

     1,579        —     

Deferred Income Taxes

     218,307        214,481   

Derivatives and Other Noncurrent Liabilities

     15,355        887   

Stockholders’ Equity:

    

Common stock, $0.001 par value; authorized 150,000,000 shares; 45,475,585 and 45,128,431 shares issued and outstanding at December 31, 2009 and 2008, respectively, with 686,421 and 590,098 shares subject to restrictions, respectively

     45        45   

Additional paid-in capital

     792,418        775,652   

Retained earnings

     181,682        131,464   

Treasury stock, at cost: zero shares at December 31, 2009 and December 31, 2008

     —          —     

Accumulated other comprehensive income

     54,410        192,072   
                

Total stockholders’ equity

     1,028,555        1,099,233   
                

Total

   $ 1,866,123      $ 1,994,493   
                

See notes to consolidated financial statements.

 

F-3


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

 

     Year Ended December 31,  
     2009     2008     2007  
     (in thousands, except share and per share amounts)  

Operating and Other Revenues:

      

Oil and gas production

   $ 647,839      $ 605,881      $ 374,956   

Commodity derivative gain (loss)

     (54,567     7,920        —     

Other

     4,891        4,110        15,314   
                        

Total operating and other revenues

     598,163        617,911        390,270   

Operating Expenses:

      

Lease operating expense

     46,492        44,318        41,643   

Gathering, transportation and processing expense

     56,608        39,342        23,163   

Production tax expense

     13,197        44,410        22,744   

Exploration expense

     3,227        8,139        8,755   

Impairment, dry hole costs and abandonment expense

     52,285        32,065        25,322   

Depreciation, depletion and amortization

     253,573        206,316        172,054   

General and administrative expense

     54,398        57,206        42,228   
                        

Total operating expenses

     479,780        431,796        335,909   
                        

Operating Income

     118,383        186,115        54,361   

Other Income and Expense:

      

Interest and other income

     438        2,036        2,391   

Interest expense

     (30,647     (19,717     (12,754
                        

Total other income and expense

     (30,209     (17,681     (10,363
                        

Income before Income Taxes

     88,174        168,434        43,998   

Provision for Income Taxes

     37,956        63,175        17,244   
                        

Net Income

   $ 50,218      $ 105,259      $ 26,754   
                        

Net Income Per Common Share, Basic

   $ 1.12      $ 2.37      $ 0.61   
                        

Net Income Per Common Share, Diluted

   $ 1.12      $ 2.34      $ 0.60   
                        

Weighted Average Common Shares Outstanding, Basic

     44,723,051        44,432,383        44,049,662   
                        

Weighted Average Common Shares Outstanding, Diluted

     45,035,972        45,036,545        44,677,467   
                        

See notes to consolidated financial statements.

 

F-4


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

For the years ended December 31, 2007, 2008, and 2009

 

     Common
Stock
   Additional
Paid-In
Capital
    (Accumulated
Deficit)
Retained
Earnings
    Treasury
Stock
    Accumulated
Other
Comprehensive
Income
    Total
Stockholders’

Equity
    Compre-
hensive

Income
(Loss)
 
     (in thousands)  

Balance—December 31, 2006

   $ 44    $ 727,486      $ (504   $ —        $ 29,371      $ 756,397     

Cumulative effect of adoption of Financial Accounting Standards Board Interpretation No. (FIN) 48, as codified in ASC Topic 740

     —        —          (45     —          —          (45   $ —     

Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding

     —        7,602        —          (3,319     —          4,283        —     

Stock-based compensation

     —        10,723        —          —          —          10,723        —     

Retirement of treasury stock

     —        (3,319     —          3,319        —          —          —     

Comprehensive income:

               

Net income

     —        —          26,754        —          —          26,754        26,754   

Effect of derivative financial instruments, net of $14,604 of taxes

     —        —          —          —          (24,601     (24,601     (24,601
                                                       

Total comprehensive income

                $ 2,153   
                     

Balance—December 31, 2007

   $ 44    $ 742,492      $ 26,205      $ —        $ 4,770      $ 773,511     

Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding

     1      4,615        —          (3,051     —          1,565      $ —     

Stock-based compensation

     —        17,773        —          —          —          17,773        —     

Retirement of treasury stock

     —        (3,051     —          3,051        —          —          —     

Conversion option of the Convertible Senior Notes (net of $8,578 of taxes)

     —        13,823        —          —          —          13,823        —     

Comprehensive income:

               

Net income

     —        —          105,259        —          —          105,259        105,259   

Effect of derivative financial instruments, net of $110,505 of taxes

     —        —          —          —          187,302        187,302        187,302   
                                                       

Total comprehensive income

                $ 292,561   
                     

Balance—December 31, 2008

   $ 45    $ 775,652      $ 131,464      $ —        $ 192,072      $ 1,099,233     

Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding

     —        880        —          (2,065     —          (1,185   $ —     

Excess tax benefit from option exercises

     —        52        —          —          —          52        —     

Stock-based compensation

     —        17,899        —          —          —          17,899        —     

Retirement of treasury stock

     —        (2,065     —          2,065        —          —          —     

Comprehensive income (loss):

               

Net income

     —        —          50,218        —          —          50,218        50,218   

Effect of derivative financial instruments, net of $80,468 of taxes

     —        —          —          —          (137,662     (137,662     (137,662
                                                       

Total comprehensive income (loss)

                $ (87,444
                     

Balance—December 31, 2009

   $ 45    $ 792,418      $ 181,682      $ —        $ 54,410      $ 1,028,555     
                                                 

See notes to consolidated financial statements.

 

F-5


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     Year Ended December 31,  
     2009     2008     2007  
     (in thousands)  

Operating Activities:

      

Net Income

   $ 50,218      $ 105,259      $ 26,754   

Adjustments to reconcile to net cash provided by operations:

      

Depreciation, depletion and amortization

     253,573        206,316        172,054   

Deferred income taxes

     31,867        62,565        17,270   

Impairments, dry hole costs and abandonment expense

     52,285        32,065        25,322   

Unrealized derivative loss (gain)

     43,665        (7,858     —     

Stock compensation and other non-cash charges

     17,750        18,117        11,284   

Amortization of deferred financing costs

     8,410        5,619        482   

Gain on sale of properties

     (1,386     (1,132     (13,420

Excess tax benefit from option exercises

     (52     —          —     

Change in operating assets and liabilities:

      

Accounts receivable

     3,854        (16,047     5,900   

Prepayments and other assets

     (922     (324     (875

Accounts payable, accrued and other liabilities

     20,046        (7,908     (4,065

Amounts payable to oil and gas property owners

     3,088        (5,142     8,276   

Production taxes payable

     (1,652     11,417        2,471   
                        

Net cash provided by operating activities

     480,744        402,947        251,453   

Investing Activities:

      

Additions to oil and gas properties, including acquisitions

     (450,411     (568,445     (414,925

Additions of furniture, equipment and other

     (3,971     (4,752     (4,640

Proceeds from sale of properties

     3,748        2,405        96,450   
                        

Net cash used in investing activities

     (450,634     (570,792     (323,115

Financing Activities:

      

Proceeds from credit facility

     100,000        147,300        164,000   

Principal payments on credit facility

     (349,000     (167,300     (78,000

Proceeds from issuance of senior convertible notes

     —          172,500        —     

Proceeds from issuance of senior notes

     237,930        —          —     

Proceeds from sale of common stock

     880        4,082        5,098   

Deferred financing costs and other

     (8,578     (5,959     (473
                        

Net cash provided by (used in) financing activities

     (18,768     150,623        90,625   
                        

Increase (Decrease) in Cash and Cash Equivalents

     11,342        (17,222     18,963   

Beginning Cash and Cash Equivalents

     43,063        60,285        41,322   
                        

Ending Cash and Cash Equivalents

   $ 54,405      $ 43,063      $ 60,285   
                        

See notes to consolidated financial statements.

 

F-6


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009, 2008 and 2007

1. Organization

Bill Barrett Corporation, a Delaware corporation, is an independent oil and gas company engaged in the exploration, development and production of natural gas and crude oil. Since its inception on January 7, 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States.

2. Summary of Significant Accounting Policies

Basis of Presentation. The accompanying consolidated financial statements include the accounts of Bill Barrett Corporation and its wholly-owned subsidiaries (collectively, the “Company”). These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates. Preparation of the Company’s financial statements in accordance with GAAP requires management to make various assumptions, judgments and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The most significant areas requiring the use of assumptions, judgments and estimates relate to the intended cash settlement of the Company’s 5% Convertible Senior Notes due 2028 (“Convertible Notes”) in computing dilutive earnings per share, volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future asset retirement obligations, impairments of undeveloped properties, valuing deferred tax assets and estimating fair values of derivative instruments and stock-based payment awards.

Cash Equivalents. The Company considers all highly liquid investments with a remaining maturity of three months or less when purchased to be cash equivalents.

Oil and Gas Properties. The Company’s oil and gas 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 well has found 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. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized. 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 weighted average interest rates used to capitalize interest for the years ended December 31, 2009 and 2008 were 8.1% and 5.9%, respectively, which include interest on the Company’s Convertible Notes, its 9.875% Senior Notes due 2016 (“Senior Notes”) and its credit facility, amortization of the discounts associated with the Convertible Notes and Senior Notes, commitment fees paid on the unused portion of its credit facility, amortization of deferred financing and debt issuance costs and the effects of interest rate hedges. The Company capitalized interest costs of $4.6 million and $2.0 million for the years ended December 31, 2009 and 2008, respectively.

 

F-7


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the years ended December 31, 2009, 2008 and 2007

 

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas 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 oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unevaluated oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage.

Materials and supplies consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market value, on a first-in, first-out basis.

The following table sets forth the net capitalized costs and associated accumulated depreciation, depletion and amortization, and non-cash impairments relating to the Company’s natural gas and oil producing activities, including net capitalized costs associated with properties that were held for sale at December 31, 2009 of $5.6 million in total proved properties, which is net of accumulated depreciation, depletion, amortization and non-cash impairment (see Note 4 for further information on properties held for sale):

 

     As of December 31,  
     2009     2008  
     (in thousands)  

Proved properties

   $ 432,286      $ 415,641   

Wells and related equipment and facilities

     1,724,269        1,381,861   

Support equipment and facilities

     199,952        170,058   

Materials and supplies

     9,297        9,975   
                

Total proved oil and gas properties

     2,365,804        1,977,535   

Accumulated depreciation, depletion, amortization and impairment

     (995,807     (744,139
                

Total proved oil and gas properties, net

   $ 1,369,997      $ 1,233,396   
                

Unevaluated properties

   $ 154,837      $ 105,665   

Wells and equipment in progress

     119,982        209,574   
                

Total unevaluated oil and gas properties, excluded from amortization

   $ 274,819      $ 315,239   
                

 

F-8


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the years ended December 31, 2009, 2008 and 2007

 

Net changes in capitalized exploratory well costs for the years ended December 31, 2009, 2008 and 2007, respectively, are reflected in the following table:

 

    Year Ended