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, 2005

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 18 th Street, Suite 2300

Denver, Colorado

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

(303) 293-9100

(Registrant’s telephone number, including area code)

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

 

Title of each class

 

Name of each exchange on which registered

Common Stock, $.001 par value

  New York Stock Exchange

Series A Junior Participating Preferred Stock Purchase Rights

  New York Stock Exchange

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

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

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

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

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

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

 

Large accelerated filer   x

   Accelerated filer   ¨    Non-accelerated filer   ¨

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. $838,408,450*


* Without assuming that any of the issuer’s directors or executive officers, or the entities affiliated with directors that currently beneficially own 10,081,278 or 2,768,665 shares of common stock, respectively, is an affiliate, the shares of which they are beneficial owners have been deemed to be owned by affiliates solely for this calculation.

As of February 28, 2006, the registrant had outstanding 43,837,395 shares of $.001 par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE

List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: (1) Any annual report to security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933. The listed documents should be clearly described for identification purposes (e.g., annual report to security holders for fiscal year ended December 24, 1980).

 



CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

    business strategy;

 

    identified drilling locations;

 

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

 

    natural gas and oil reserves;

 

    ability to obtain permits and governmental approvals;

 

    technology;

 

    financial strategy;

 

    realized oil and natural gas prices;

 

    production;

 

    lease operating expenses, general and administrative costs and finding and development costs;

 

    availability and costs of drilling rigs and field services;

 

    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”, “hope”, “estimate”, “predict”, “potential”, “pursue”, “target”, “seek”, “objective”, or “continue”, the negative of such terms or other comparable terminology.

The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in “Item 1A. Risk Factors” section 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 do not intend 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.

 

2


PART I

Items 1 and 2. Business and Properties

BUSINESS

General

Bill Barrett Corporation (the “Company”, “we” or “us”) is a corporation that was formed in January 2002 and is incorporated in the State of Delaware. We explore for and develop oil and natural gas in the Rocky Mountain region of the United States. We have exploration and development projects in nine basins and a regional overthrust belt in the Rocky Mountains. Our management has an extensive track record with expertise in the full spectrum of Rocky Mountain plays. Our strategy is to maximize stockholder value by leveraging our management team’s experience finding and developing oil and gas in the Rocky Mountain region to profitably grow our reserves and production, primarily through the drill-bit.

We began active natural gas and oil operations in March 2002 upon the acquisition of properties in the Wind River Basin. We acquired these properties from a subsidiary of the Williams Companies, which acquired these properties in connection with the Williams Companies’ acquisition of Barrett Resources Corporation in August 2001. Since inception, we substantially increased our activity level and the number of properties that we operate. Our operating results reflect this growth. Also in 2002, we completed two additional acquisitions of properties in the Uinta, Wind River, Powder River and Williston Basins. In early 2003, we completed an acquisition of largely undeveloped coalbed methane properties located in the Powder River Basin. In September 2004, we acquired interests in properties in the Piceance Basin consisting of 17,581 net acres and 79 net producing wells in or around the Gibson Gulch field (the “Piceance Basin Acquisition Properties”). A summary of our significant property acquisitions is as follows:

 

Primary Locations of Acquired Properties

   Date Acquired    Purchase Price
          (in millions)

Wind River Basin

   March 2002    $ 74

Uinta Basin

   April 2002      8

Wind River, Powder River and Williston Basins

   December 2002      62

Powder River Basin

   March 2003      35

Piceance Basin

   September 2004      137

The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the United States. Consequently, the Company currently reports a single industry segment. See “Financial Statements” and the notes to our consolidated financial statements.

 

3


The following table provides information regarding our operations by basin.

 

     At December 31, 2005

Basin

  

Estimated Net

Proved

Reserves (1)

  

Net

Producing

Wells

  

Net

Undeveloped

Acreage

   

December
2005

Average Daily

Net Production

     (Bcfe)               (MMcfe/d)

Piceance

   114.5    143    14,302     26.5

Wind River

   85.8    160    159,426     45.6

Uinta

   83.1    40    137,764 (2)   40.3

Powder River

   25.9    358    53,040     19.9

Williston

   31.6    36    126,807     7.2

Green River

   —      —      7,716     —  

Denver-Julesburg

   —      —      182,856     —  

Paradox

   —      —      63,986     —  

Big Horn

   .1    1    140,959     —  

Montana Overthrust

   —      —      159,127     —  

Utah Hingeline

   —      —      17,346     —  

Other

   —      —      15,902     .4
                    

Total

   341.0    738    1,079,231 (2)   139.9
                    

(1) Our reserves were determined using the market prices for natural gas and oil at December 31, 2005, which were $7.72 per MMBtu of natural gas and $61.04 per barrel of oil, without giving effect to hedging transactions. Our reserve estimates are based on a reserve report prepared by us and reviewed by our independent petroleum engineers. See “—Oil and Gas Data—Proved Reserves”.
(2) An additional 130,346 net undeveloped acres that are subject to drill-to-earn agreements are not included.

 

4


LOGO

We operate in nine basins and a regional overthrust belt in the Rocky Mountain region of the United States. The basins consist of the Piceance, the Wind River, the Uinta, the Powder River, the Williston, the Green River, the Denver-Julesburg, the Paradox and the Big Horn.

Piceance Basin . The Piceance Basin, located in northwestern Colorado, is a focus area for our development activities and expected production growth in 2006. We are in the early stages of this development project. We currently are testing a number of different drilling and completion techniques in an effort to optimize production and recoveries. Key statistics for our position in this basin include:

 

    26.5 MMcfe/d of average net production for December 2005, compared to 6.0 MMcfe/d for December 2004

 

    114.5 Bcfe of estimated net proved reserves at December 31, 2005

 

    143 net producing wells at December 31, 2005

 

    16,377 total net acres, including 14,302 net undeveloped acres, at December 31, 2005

 

    $129.5 million of net capital expenditures spent during 2005 to participate in the drilling of 86 wells

 

    $126.5 million estimated net capital expenditures in 2006, including an 81 gross well drilling program

Wind River Basin . The Wind River Basin, located in central Wyoming, was our largest producing area for the year ended December 31, 2005. Our operations in the basin include active infill and field expansion development programs, as well as eight exploration projects that make this basin an important exploratory area. Our development operations are conducted in four general project areas. Key statistics for our position in this basin include:

 

    45.6 MMcfe/d of average net production for December 2005, compared to 41.1 MMcfe/d for December 2004

 

5


    85.8 Bcfe of estimated net proved reserves at December 31, 2005

 

    160 net producing wells at December 31, 2005

 

    165,590 total net acres, including 159,426 net undeveloped acres at December 31, 2005

 

    $57.8 million of net capital expenditures spent during 2005 to participate in the drilling of 19 wells and 19 recompletions
    $48 million estimated net capital expenditures in 2006, including a six gross well drilling program and three recompletions

Uinta Basin . The Uinta Basin, located in northeastern Utah, represents a substantial part of our development and exploration activities and expected production growth in 2006. Our development operations are conducted primarily in two areas. We also have a position in four exploratory projects in the basin. Key statistics for our position in this basin include:

 

    40.3 MMcfe/d of average net production for December 2005, compared to 16.9 MMcfe/d for December 2004

 

    83.1 Bcfe of estimated net proved reserves at December 31, 2005

 

    40.2 net producing wells at December 31, 2005

 

    146,026 total net acres, including 137,764 net undeveloped acres, at December 31, 2005

 

    an additional 130,346 net undeveloped acres that are subject to drill-to-earn agreements

 

    $82.2 million of net capital expenditures spent during 2005 to participate in the drilling of 22 wells and four recompletions

 

    $99.7 million estimated total capital expenditures in 2006, including a 34 gross well drilling program

Powder River Basin . The Powder River Basin is located in northeastern Wyoming. Substantially all of our operations in this basin are in coalbed methane plays targeting the Wyodak and Big George coals. Our coalbed methane activities have resulted in high drilling success and lower drilling costs than our other drilling programs; however, the average coalbed methane well in the Powder River Basin produces at a much lower rate with fewer reserves attributed to it than conventional natural gas wells in the Rockies. Our development activities are conducted in seven project areas in the basin. Many of our leases in this basin are in areas that have been partially depleted or drained by earlier offset drilling. Key statistics for our position in this basin include:

 

    19.9 MMcfe/d of average net production for December 2005, compared to 21.0 MMcfe/d for December 2004

 

    25.9 Bcfe of estimated net proved reserves at December 31, 2005

 

    357.8 net producing wells at December 31, 2005

 

    79,088 total net acres, including 53,040 net undeveloped acres, at December 31, 2005

 

    $28.7 million of net capital expenditures spent during 2005 to participate in the drilling of 181 wells

 

    $21.5 million estimated total capital expenditures in 2006, including a 220 gross well drilling program

Williston Basin . The Williston Basin is located in western North Dakota, northwestern South Dakota and eastern Montana. It is a predominantly oil prone basin and represents our only oil focused project area. Our activities in this basin include both development and exploration drilling programs concentrated in three areas. We use horizontal drilling technology and 3-D seismic surveys in the Williston to expand existing fields, target exploration projects and increase our recoveries. Key statistics for our position in this basin include:

 

    7.2 MMcfe/d of average net production for December 2005, compared to 6.3 MMcfe/d for December 2004

 

    31.6 Bcfe of estimated net proved reserves at December 31, 2005

 

    35.8 net producing wells at December 31, 2005

 

6


    135,997 total net acres, including 126,807 net undeveloped acres, at December 31, 2005

 

    $14.3 million of net capital expenditures spent during 2005 to participate in the drilling of 12 wells

 

    $28.8 million estimated total capital expenditures in 2006, including a 14 gross well drilling program, all of which are horizontal wells

Denver-Julesburg Basin . Our operations in the DJ Basin are concentrated in the Tri-State exploration project, which extends into Colorado, Kansas and Nebraska. These operations are exploratory and involve the extensive use of 3-D seismic technology to target shallow biogenic gas and deeper conventional oil plays. Key statistics for our position in this basin include:

 

    182,856 net undeveloped acres at December 31, 2005

 

    Capital expenditures in 2005 included leasehold acquisitions, 3-D seismic and seven gross wells

 

    $7.7 million estimated total capital expenditures in 2006, including a 48 gross well drilling program

Big Horn Basin . The Big Horn Basin is located in north central Wyoming. We are in the initial phases of an exploration project targeting both structural-stratigraphic and basin-centered tight gas plays. Key statistics for our position in this basin include:

 

    140,959 net undeveloped acres at December 31, 2005

 

    Capital expenditures in 2005 included seismic and leasehold acquisitions

 

    Capital expenditures in 2006 are planned to include participating in the drilling of one gross well, one well recompletion, and 3-D seismic

Overthrust Belt . The overthrust belt is a broad structural feature that runs from southern Utah through Alberta and British Columbia. We acquired leasehold interests in two exploration projects in Montana and Utah along this feature. Key statistics for our position in this area include:

 

    176,473 net undeveloped acres at December 31, 2005

 

    Capital expenditures in 2005 included leasehold acreage acquisitions and 3-D seismic surveys

 

    Capital expenditures in 2006 are planned to include two exploration wells

Paradox Basin . The Paradox Basin is located in southwestern Colorado and southeastern Utah. We are in the initial stages of two exploration projects in the basin focusing on natural gas. Key statistics for our position in this basin include:

 

    63,986 net undeveloped acres at December 31, 2005

 

    Capital expenditures in 2005 included various exploratory activities

 

    Capital expenditures in 2006 are planned to include a four well exploration program

Green River Basin . The Green River Basin is located in southwestern Wyoming and adjacent areas of northeastern Utah. In 2004, we acquired leasehold interests in an exploration project in the basin. Together with a partner, we tested an unsuccessful exploration prospect in February 2005. We continue to evaluate opportunities in the basin. Key statistics for our position in this basin include:

 

    7,716 net undeveloped acres at December 31, 2005

 

    Net capital expenditures spent during 2005 funded leasehold acreage acquisitions and various exploratory activities

 

7


Summary of Development Areas

The following table summarizes the information regarding our key development areas:

 

Development Area

   Basin   

Average

Working

Interest (1)

   

2006

Drilling

Locations (2)

  

2006

Area

Budget (3)

                     (in millions)

Gibson Gulch

   Piceance    78 %   81    $ 126.5

Cave Gulch

   Wind River    87     1      31.6

Cooper Reservoir

   Wind River    98     1      —  

Talon

   Wind River    61     1      2.7

Wallace Creek/Stone Cabin

   Wind River    87     2      2.5

West Tavaputs

   Uinta    100     24      73.4

Powder River

   Powder River    81     220      21.5

Williston

   Williston    45 (4)   14      28.8
                    

Total

      65     344    $ 287.0

(1) Average working interest is based on our working interests in producing wells as of December 31, 2005, including operated and non-operated properties.
(2) For each development area, 2006 drilling locations represent total gross locations specifically identified and scheduled by management as of December 31, 2005 as an estimate of our 2006 drilling activities on existing acreage. Of the 2006 drilling locations, 47 are classified as PUDs. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal conditions, natural gas and oil prices, rig and services availability, costs, drilling results and other factors. For a more complete description of our proposed activities, see the basin descriptions below.
(3) Includes budgeted drilling expenditures as well as exploration and facilities costs for the area and excludes property acquisition costs and exploration costs for other areas.
(4) We operated 78% of our December 2005 production in the Williston Basin, with an average working interest of 87% per operated well. Our average working interest in our non-operated wells is 16%.

 

8


Summary of Exploration Activities

The following table summarizes certain of our exploration activities that are discussed in more detail below.

 

Exploration Project

  Basin  

Project Net

Acreage (1)

   

Average

Working

Interest (2)

   

2006 Planned Exploratory

Activities (3)

Cave Gulch/Waltman (4)

  Wind River   13,541     79 %   3-D seismic; drill one deep well

Cooper Reservoir (4)(5)

  Wind River   12,732     85 %   Drill one deep well

East Madden

  Wind River   20,112     60 %   Assess drilled well

Pommard(5)

  Wind River   2,200     100 %   Assessing deep potential

Stone Cabin(4)

  Wind River   12,342     82 %   Assessing deep potential

Talon(5)

  Wind River   67,675     35 %   Drill one well

Wallace Creek(4)(5)

  Wind River   18,403     88 %   Assessing shallow exploration

Windjammer-Coal Bank Hills Unit

  Wind River   7,934     35 %   Assessing potential using 3-D seismic

Garmesa

  Uinta   8,217     42 %   Hook up to pipeline

Lake Canyon

  Uinta   28,425 (6)   51 %   Drill six wells

West Tavaputs Deep(4)(6)

  Uinta   40,101     91 %   Drill two wells

Hook(5)

  Uinta   44,133     96 %   Drill three wells

Woodside(5)

  Uinta   17,625     100 %   Drill one well

Wyodak/Big George

  Powder River   67,087     62 %   Three pilot programs

Grand River

  Williston   11,829     45 %   Participate in one well

Red Bank Extension

  Williston   28,499     43 %   Participate in three wells

Red Water

  Williston   11,299     53 %   Assess drilled well

Mondak

  Williston   6,380     53 %   Participate in three wells

Madison(4)

  Williston   34,158     80 %   Drill one well

Antelope Hollow

  Green River   5,846     38 %   Assess for 3D seismic

Tri-State

  DJ   182,856     48 %   3-D seismic; drill six wells

Pine Ridge(5)

  Paradox   3,494     97 %   Acreage acquisitions

Yellow Jacket(5)

  Paradox   59,852     70 %   Acreage acquisitions; drill four wells

Big Horn(5)

  Big Horn   141,660     74 %   3-D seismic; acreage acquisitions; recomplete one well; drill one well

Montana Overthrust(5)

  Overthrust
Belt
  159,127     81 %   3-D seismic; drill two wells

Utah Hingeline(5)

  Overthrust
Belt
  17,346     79 %   Acreage acquisitions

(1) Project net acreage is the amount of our net leasehold acreage at December 31, 2005 that we have associated with each of our exploration projects.
(2) Average working interest is based on leasehold acreage at December 31, 2005. Also, the working interest numbers are subject to selling of working interests to industry partners in connection with our joint exploration strategy.
(3) Of the exploration activities planned for 2006 that are included in this table, some have already occurred. With respect to those that have not occurred, our actual activities may change depending on regulatory approvals, seasonal conditions and other factors, including our ability to enter into joint exploration agreements with joint drilling obligations with industry partners. For a more detailed description of proposed activities, see the description of each project in the Basin sections below.
(4) Represents an exploration project that extends an existing development project.
(5) Portions of the exploration program currently are not included in our 2006 capital expenditure budget as these activities are contingent upon obtaining an industry partner pursuant to a joint exploration agreement for the prospect or revising our capital expenditure budget.
(6) Does not include an additional 130,346 net undeveloped acres that are subject to drill-to-earn agreements.

 

9


With respect to certain of our exploration projects, we seek industry partners to enter into joint exploration agreements, which involve the sale of portions of our interests in these projects. The primary objective of this strategy is to increase our exposure to potential reserves and production, accelerate the testing of our exploration project inventory, and mitigate the capital risk of high impact exploration projects, while recouping a portion of our initial investment. We have executed these joint exploration agreements with partners in our East Madden, Lake Canyon/Brundage Canyon, Grand River, Red Bank Extension, Red Water, Tri-State, and Waltman Arch exploration projects. We expect to pursue additional joint exploration projects at Hook, Woodside, Yellow Jacket, Pine Ridge, Circus, Big Horn, other Wind River areas and several other exploration areas. In connection with these anticipated joint exploration agreements, we expect to sell approximately 30% to 60% of our working interests and have our partner fund a significant portion of our share of early drilling costs, depending on the project.

Risk Factors

Investing in our securities involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile oil and natural gas prices and other material factors. You should read carefully the section entitled “Item 1A. Risk Factors” for an explanation of these risks before investing in our securities. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy as well as on activities on our properties, which could cause a decrease in the price of our common stock and a loss on your investment:

 

    Limited Operating History . We are a relatively new company. As such, we have made major expenditures to acquire and develop our property base and substantially increase production. This resulted in significant losses in certain periods since our inception. We can give no assurance that we will not incur losses in the future.

 

    Risks Relating to Oil and Gas Reserves . Reserve estimates are based on many assumptions, including concerning commodity prices, and our properties may not produce as we originally forecast. For example, we reduced our reserve estimates by approximately 41 Bcfe at year end 2003, 32 Bcfe at year end 2004, and 25 Bcfe at year end 2005. In addition, our reserve report reflects that, as we produce our proved reserves, they would decline and the decline will only be abated if we are successful in finding or acquiring new reserves.

 

    Concentration and Competition . Our concentration in the Rocky Mountains may make us disproportionately exposed to impacts of weather, government regulation and transportation constraints common to that geographic location. For a description of the government regulation that affects our operations, see “—Operations—Environmental Matters and Regulation”. Competition with other companies in the Rockies is significant and may hinder our ability to pursue reserve and leasehold acquisitions as well as our ability to operate in certain of our core areas.

 

    Risks Related to Rapid Growth . We have grown rapidly through acquisitions and may engage in additional acquisitions in the future. Acquired properties 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.

For a discussion of other considerations that could negatively affect us, see “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors”.

Our Offices

Our company was founded in 2002 and is 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.

 

10


Our Strategy

The principal elements of our strategy to maximize stockholder value are to:

 

    Drive Growth Through the Drill-bit . We expect to generate long-term reserve and production growth predominantly through our drilling activities. We believe our management team’s experience and expertise enable us to identify, evaluate and develop new natural gas and oil reservoirs. Throughout our operations, we apply technology, including advanced drilling and completion techniques and new geologic and seismic applications. From inception through December 31, 2005, we participated in the drilling of 797 gross wells. We plan to participate in the drilling of a total of 411 gross wells in 2006.

 

    Pursue High Potential Projects . We have assembled several projects that we believe provide future long-term drilling inventories. In addition to eight key development areas, as of December 31, 2005 we are involved in 26 exploration projects. Our team of 17 geologists and geophysicists, which includes our current Chief Executive Officer, is dedicated to generating new geologic concepts. Our long-term objective is to allocate between 70% and 80% of our capital budget to development projects, with the balance allocated to higher risk, higher potential exploration projects. We also seek partners to enter into joint exploration agreements in order to increase our exposure to potential reserves and production, mitigate our capital risk and accelerate the evaluation of these high potential projects.

 

    Focus on Natural Gas in the Rocky Mountain Region . We intend to capitalize on the large estimated undeveloped natural gas resource base in the Rocky Mountains, while selectively pursuing attractive oil opportunities in the region. We believe the Rockies represent one of the few natural gas provinces in North America with significant remaining development potential. All of our production is from the Rockies, and for 2005, approximately 92% was natural gas.

 

    Reduce Costs and Maximize Operational Control . Our objective is to generate profitable growth and high returns for our stockholders. We expect that our unit cost structure will benefit from economies of scale as we grow, maintaining high percentage operatorship of our reserves and production, and our continuing cost management initiatives. As we manage our growth, we are actively focusing on managing lease operating expenses, general and administrative costs, and finding and development costs. It is strategically important to us to serve as operator of our properties when possible, as that allows us to exert greater control over costs and timing in our exploration, development and production activities. We operated approximately 92.5% of our December 2005 production and, as of December 31, 2005, we owned an average working interest of approximately 60% in 1,792,808 gross undeveloped acres, as well as an additional 130,346 net undeveloped acres that are subject to drill-to-earn agreements.

 

    Pursue Reserve and Leasehold Acquisitions . Past acquisitions have played an important part in establishing our asset base. We intend to use our experience and regional expertise to supplement our drill-bit growth strategy with complementary acquisitions that have the potential to provide long-term drilling inventories or that have undeveloped leasehold positions. We actively review acquisition opportunities on an ongoing basis.

Competitive Strengths

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

 

   

Experienced Management Team . Although we compete against companies with more financial and human resources than ours, we believe our management team’s experience and expertise in the Rocky Mountains provide a distinct competitive advantage. Our 12 corporate officers average 23 years of experience working in and servicing the industry. Our Chief Executive Officer, Chief Operating Officer and other members of our management team worked together as executives or advisors for many years with Barrett Resources Corporation, a publicly-traded Rocky Mountain oil and gas company that was founded in 1980 and sold in 2001 in a transaction valued at approximately $2.8 billion. Further, members of our team are widely acknowledged as leading explorationists and were involved in finding

 

11


 

or developing several of the largest Rocky Mountain natural gas and oil fields during the last three decades, including the Grand Valley, Parachute, and Rulison fields in the Piceance Basin, the Powder River Basin coalbed methane play, the Hilight field, the Cave Gulch field and the Madden field.

 

    Inventory of Growth Opportunities . We have established an asset base of 1,079,231 net undeveloped leasehold acres as of December 31, 2005, as well as an additional 130,346 net undeveloped acres that are subject to drill-to-earn agreements. From inception through December 31, 2005, we participated in the drilling of 797 gross wells. In 2006, we plan to participate in the drilling of 411 gross wells across our operations. In addition, as of December 31, 2005, we have 26 exploration projects.

 

    Rocky Mountain Asset Base . In January 2004, the Department of Energy estimated that Rocky Mountain natural gas production would grow by 91% from 2002 to 2025, compared to other large U.S. gas producing areas, which were forecast to decline or grow at significantly lower rates over the same period. Our assets are focused in the natural gas prone basins of the Rockies. This asset base allows us to leverage our experience and expertise as we pursue our growth strategy. Although we are focused in the Rockies, we achieve both geographic and geologic diversification by being active in nine distinct basins and the overthrust belt.

 

    Financial Flexibility . As of December 31, 2005, we had $68.3 million in cash with $86 million of debt outstanding under our $200 million revolving credit facility. We currently are negotiating an amendment to our revolving credit facility, which we anticipate will be for $400 million, expandable up to $600 million, with an initial borrowing base of at least $280 million. We are committed to maintaining a conservative financial position to preserve our financial flexibility. We believe that our operating cash flow and available borrowing capacity under our credit facility provide us with the financial flexibility to pursue our planned exploration and development activities and leasehold acquisitions in 2006 and into 2007.

 

    Significant Employee Investment . All of our corporate officers and substantially all our employees own our stock or stock options. As a result, our management team and other employees have interests that are aligned with those of our stockholders.

Piceance Basin

The Piceance Basin is located in northwestern Colorado. We entered the Piceance Basin on September 1, 2004, when we purchased producing and undeveloped properties from Calpine Corporation and Calpine Natural Gas L.P., which included 25,985 gross and 19,180 net acres in and around Gibson Gulch field, for approximately $137 million.

Our total leasehold position in the Piceance Basin as of December 31, 2005 consisted of 17,767 gross and 14,302 net undeveloped acres and 2,887 gross and 2,075 net developed acres, all of which are in our Gibson Gulch development area. Our estimated net proved reserves in the Piceance Basin at year end 2005 were 114.5 Bcfe.

Gibson Gulch

The Gibson Gulch area is a basin-centered gas play along the north side of the Divide Creek anticline at the eastern end of the Piceance Basin’s productive Mesaverde trend. Our properties are largely undeveloped relative to those fields to the west and southwest. We are in the early stages of this development project. We currently are testing a number of different completion techniques in an effort to optimize production and recoveries, and reduce our costs. Although we drill on a 20-acre well pattern, we have received authority for development on a 10-acre pattern and will use recently acquired 3-D seismic to evaluate development on this basis. Our natural gas production in this basin currently is gathered through our own gathering system and delivered to markets through pipelines owned by Questar Pipeline Company. In late 2005, we acquired a 20 square mile 3C 3-D seismic survey over a major portion of Gibson Gulch. Initial results from and interpretations of the survey are expected to

 

12


be available in the second quarter of 2006. The Company is employing 3C 3-D seismic technology to its Gibson Gulch and certain other projects. Although the science behind this technology has been known for some time, the implementation and the practical use of 3C 3-D seismic technology is relatively new, unproven, and unconventional. A theoretical promise of 3C 3-D seismic is to provide information about fracture density in the subsurface regions we explore. Gas recovery from basin centered unconventional tight gas reservoirs increases with increasing fracture density. We are using this 3C 3-D seismic technology with the hope of improving our ability to find these areas of enhanced fracturing or “sweet spots”.

At December 31, 2005, we held interests in 156 gross (143 net) producing wells that produced 26 MMcfe/d net to our interest in the month of December 2005 with an average working interest of 78%. In our current capital budget, we estimate our capital expenditures for 2006 will be $126.5 million to participate in the drilling of 81 gross wells (68 net wells) in the Gibson Gulch area, and to expand our compression and gathering facilities. During the year ended December 31, 2005, we had capital expenditures of $129.5 million to participate in the drilling of 80 wells, of which 58 were completed as of year end and 66 of which were completed as of February 28, 2006.

Wind River Basin

The Wind River Basin is located in central Wyoming. Our activities in the area are concentrated primarily in the eastern Wind River Basin. Our Wind River Basin development operations are conducted in four general project areas, three of which are located along the greater Waltman Arch area: Cave Gulch, Cooper Reservoir and Wallace Creek. In addition, we have eight exploration projects, of which Pommard, Windjammer and East Madden are in areas of the basin where we have no existing development operations. We are seeking industry partners to enter into joint exploration agreements, which would involve the sale of a portion of our interests and joint drilling obligations for certain exploration projects in the Wind River Basin.

Our total leasehold position in the Wind River Basin as of December 31, 2005 consisted of 339,594 gross and 159,426 net undeveloped acres and 8,531 gross and 6,164 developed acres. Our estimated net proved reserves in the Wind River Basin at year end 2005 were 85.8 Bcfe. Our current operations in the basin include active infill and field expansion development programs, as well as exploration activities. We have access to over 638 square miles of 3-D seismic in ten different surveys covering the Cave Gulch, Cooper Reservoir, Wallace Creek, Stone Cabin and East Madden project areas, and 3,700 miles of 2-D seismic across a majority of the eastern 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 and Colorado Interstate Gas Company (“CIG”).

Cave Gulch

The Cave Gulch field is a structural-stratigraphic play along the Owl Creek Thrust at the northern end of the Waltman Arch. Our primary focus is on the overpressured deep Frontier and Muddy Formations from 16,700 to 19,000 feet. In addition, the Company continues to evaluate our 20-acre development program involving drilling and recompletions in discontinuous lenticular sands at depths from approximately 4,900 to 9,200 feet in the Lance formation. We also are producing from wells in the Fort Union, from 3,500 to 4,900 feet.

In our current capital budget, we estimate our capital expenditures for 2006 will be $31.5 million in Cave Gulch, which includes one development well, one exploration well, and three recompletions. Additionally, in 2006 we plan to add 23 square miles of new 3-D seismic data to our existing 3-D data in the area to better image the northern portions of the Cave Gulch project area. In the year ended December 31, 2005, we spent $29.7 million of capital expenditures to participate in the drilling of six wells, one recompletion, three workovers, and to make facilities improvements. These capital expenditures include approximately $11 million to drill and complete the Bullfrog 14-18 exploratory well, which is discussed below. The Company successfully drilled and completed four Lance wells and had one Lance dry hole.

 

13


In July 2005, we completed the Bullfrog 14-18 well in our Cave Gulch project area in the Wind River Basin, a 19,400 foot deep exploratory test targeting the Lakota, Muddy and Frontier formations in which we have a 93% working interest. We also have identified Muddy and Frontier stimulation and re-stimulation candidates in our Cave Gulch development program. The first of these stimulations was performed in mid-June 2005 in the Muddy formation in the Cave Gulch 1-29, in which we have a 70% working interest. It should be noted that other similar Muddy wells in the area tend to have relatively short reserve lives and highly variable reservoir size.

Cooper Reservoir

Our position in the Cooper Reservoir field lies six miles south of Cave Gulch along the Waltman Arch. The primary producing formations at Cooper are the Lance and Fort Union formations at depths ranging from 3,200 to 8,500 feet. Currently, our primary focus is the deep potential we have identified utilizing 3-D seismic. The Company also is assessing the potential for 40-acre and 80-acre Lance development on field extensions north and south of the main field. We are using 3-D seismic technology across the Cooper Reservoir area region to evaluate these and other opportunities.

In our current capital budget, we estimate our capital expenditures for 2006 will be $3.9 million in Cooper Reservoir to participate in the drilling of one deep well and workovers on four wells. During the year ended December 31, 2005, we spent $12.3 million to participate in the drilling of six wells, of which five wells are producing into the sales line and the other development well was a dry hole. As a result of drilling these wells and ongoing evaluation of the area, we determined that infill wells are encountering depleted sands and are not recovering sufficient incremental reserves to continue the program in the Lance and Fort Union formations. We recorded an impairment expense of $29.5 million in the second quarter of 2005 to reduce the carrying value of properties in the Cooper Reservoir to fair value. We have identified deeper Muddy and Frontier potential on 3-D seismic and will continue to assess the Cooper Reservoir as an exploration play.

Wallace Creek, Stone Cabin and Pommard

In our current capital budget, we estimate our capital expenditures for 2006 will be $2.5 million. In 2005, our capital program in this area was approximately $1.5 million.

In the Pommard area, we are evaluating the potential of drilling a Madison test. This test would be done by re-entering the Pommard #1, a 14,976 feet Tensleep test drilled in 2004, milling a window, and side tracking the well down through the Tensleep and into the Madison. We also are considering selling a portion of our interest in this area to an industry partner prior to this test.

No wells were drilled in Wallace Creek during 2005. The Company plans to drill one Radarville wells in 2006. The Radarville formation is the primary producer in this field and is found at a general depth range of 7000 to 7500 feet. We also recognize a potential coalbed methane play in the Wallace Creek area. We currently are assessing the multiple coal beds of the Meeteetse formation, which underlies the Lance formation in a 1,500 to 4,500 feet depth range. We plan to sell a portion of our interest in our Meeteetse coal rights to an industry partner before testing this play’s potential.

Windjammer—Coal Bank Hills Unit

In the first quarter of 2005, we formed the Coal Bank Hills Federal Unit covering the majority of our Windjammer project area. Our working interest in this Federal Unit averages over 50%. This area lies to the northwest of our Wallace Creek development project. In the third quarter of 2005, the Company drilled a Unit obligation well targeting the Radarville formation. This well was determined to be non-commercial and was plugged and abandoned and the Unit was terminated. We currently are evaluating our 114 square mile 3-D survey, shot in late 2004, for Lance, Meeteetse coal, and deeper horizon potential.

 

14


Talon and East Madden

In our Talon and East Madden areas, we are targeting an unconventional, basin-centered play concept in the Lance and Fort Union formations. The Talon exploratory project lies due west of the Cave Gulch area and extends over a multi-township area. Our East Madden exploration prospect lies east of the extensive Madden field along the Madden anticline. In our current capital budget, we estimate our capital expenditures for 2006 will be $2.7 million to purchase leases and drill one shallow Fort Union well. In 2005, our capital program in this area was approximately $13.4 million and included 3-D seismic acquisition, three Fort Union wells, and two recompletions.

Uinta Basin

Our exploration and development activities are focused on various geologic play types in several locations. During the year ended December 31, 2005, we had capital expenditures of $82.2 million to participate in the drilling of 22 wells, of which 11 were completed as of year end and five of which were completed as of February 28, 2006. We operated 34 gross wells in this basin as of December 31, 2005. In our current capital budget, we estimate our capital expenditures in 2006 will be $83.9 million in the Uinta Basin area to fund our interests in 30 additional gross wells and infrastructure improvements.

West Tavaputs

We began operations in the Uinta Basin in April 2002 through the acquisition of 3.4 Bcfe of proved reserves and 46,702 gross and 42,355 net leasehold acres at West Tavaputs. With effective application of new fracturing techniques and 3D seismic, we have greatly enhanced our ability to commercialize the gas potential of this area, including the discovery of new gas reservoirs in the Dakota, Entrada and Navajo formations in our Peters Point #6-7D wildcat well.

Our natural gas production at West Tavaputs is gathered and compressed by our facilities and delivered to markets on the Questar pipeline system. We recently entered into Precedent Agreements with Questar Gas to subscribe for firm transportation arrangements on two expansion projects that we believe will provide adequate capability to move anticipated gas volumes from West Tavaputs. We also are negotiating Precedent Agreements with Questar Gas to subscribe for processing services to ensure our gas will meet hydrocarbon dewpoint specifications on the Questar southern system.

Full development of the West Tavaputs area will require the completion of an environmental impact statement, or EIS, which we initiated in February 2005. See “—Operations—Environmental Matters and Regulation”.

Garmesa

The Garmesa prospect lies southeast of West Tavaputs and consists of three adjacent prospect areas: Hill Creek, Tumbleweed and Cedar Camp. We believe these prospects have similar geologic characteristics and reserve potential, but are differentiated mainly by our level of working interest, industry partners and ownership structures. In the year ended December 31, 2005, we conducted a 3-D seismic survey and participated in the drilling of three wells. Two of the drilled wells were successfully completed and one was a dry hole. No activity is anticipated in the Garmesa area until we evaluate our 21-square mile Tumbleweed 3-D seismic survey and the production results from two Cedar Camp wells that are scheduled to be hooked up to a pipeline during the first half of 2006.

Hill Creek . Within the Hill Creek area, we hold interest in 10 wells that targeted the Dakota, Entrada and Wingate formations at depths down to 11,900 feet.

 

15


Tumbleweed . Our Tumbleweed project area is located directly southeast and adjacent to Hill Creek. We operate this prospect and are targeting the same reservoir objectives as the Hill Creek project.

Cedar Camp . Our Cedar Camp project area is located directly from the Tumbleweed area. We operate this prospect and are targeting the same reservoir objectives as the Hill Creek and Tumbleweed projects. As of December 31, 2005, three wells have been drilled (80% working interest), two of which are waiting on pipeline connection, which is expected by the end of the second quarter of 2006, while the third was plugged and abandoned.

Lake Canyon/ Brundage Canyon

Lake Canyon . Lake Canyon is an exploration project that targets Green River formation oil zones at depths of 6,500 feet, gas zones in the Wasatch at depths of 8,000 feet and basin-centered tight gas in the Mesaverde formation at depths ranging from approximately 10,000 to 14,000 feet. In 2005, our capital program in this area included the acquisition of approximately 52 square miles of 3C 3-D seismic, acreage acquisition and participating in the drilling of three gross exploratory wells.

In July 2004, we and an industry partner entered into an exploration and development agreement with the Ute Indian Tribe of the Uintah and Ouray Reservation, or the Ute Tribe, 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. This drill-to-earn agreement was revised in September 2004 to include the Ute Development Corporation as a party and was approved by the Department of Interior’s Bureau of Indian Affairs, or BIA, in October 2004. Pursuant to this agreement, we have the right to earn up to a 75% working interest in the Mesaverde formation and deeper horizons, plus up to a 25% interest in shallower Green River formations. To earn these interests pursuant to this agreement, we and our partner are required to drill 13 deep wells and 21 shallow wells prior to December 31, 2009, including one deep and two shallow wells by December 31, 2005. The Ute Tribe has an option to participate for a 25% working interest in wells drilled pursuant to the agreement. The Ute Tribe exercised this option on the two shallow wells, which decreased our working interest to 18.75%. This right terminates as to all future wells in a lease block if the Ute Tribe does not elect to participate in one of the first two wells in that lease block. We will drill and operate the deep wells and our industry partner will drill and operate the shallow wells. In December 2005, we reached total depth of 14,325 feet on our Mesaverde test well, the #1 DLB (75% working interest), and set casing to a depth of 11,539 feet. Testing will focus on several Upper Price River (Mesaverde) and shallower Wasatch intervals where the gas shows and open hole log analysis indicates gas potential. We intend to complete the well once pipeline construction into the area is completed by the beginning of the second quarter. In 2005, we also participated in two 6,500-foot Green River formation wells operated by our industry partner that are on line and producing oil. Gas potential from the wells is restricted and awaiting completion of the pipeline extension. These two Green River wells extend production westward from the same reservoir interval that is productive in neighboring Brundage Canyon field.

Brundage Canyon . In September 2004, we entered into a farm-out agreement with the same industry partner as with our Lake Canyon prospect pursuant to which we had the right to earn a 75% working interest in the deep Mesaverde formation and deeper horizons on existing exploration and development agreements that encompass 49,000 acres within the Brundage Canyon field by drilling a deep exploration test well. This field is located on the Ute Tribe’s lands and is situated adjacent to and just east of the acreage in the Lake Canyon prospect covered by our agreement with the Ute Tribe. We commenced the drilling of our initial deep exploratory well in Brundage Canyon in November 2004 and abandoned it in January 2005, pending further evaluation of the Lake Canyon 3-D seismic survey and assessment of the completion of the #1 DLB well.

Hook and Woodside

We plan to continue to acquire leasehold acreage through 2006 in these prospects in the southwestern portion of the Uinta Basin. We then plan to sell a portion of our interest to an industry partner prior to conducting exploratory activities.

 

16


Powder River Basin

The Powder River Basin is primarily located in northeastern Wyoming. The basin contains the Rockies’ most active drilling area: the Wyodak and Big George coalbed methane plays. As of December 31, 2005, we held approximately 32,959 gross and 26,048 net developed leasehold acres and 95,666 gross and 53,040 net undeveloped leasehold acres in the Powder River Basin. Our estimated net proved reserves in the basin at year end 2005 were 25.9 Bcfe. In December 2005, we produced a net 19.9 MMcfe/d. Our development and exploration activities are concentrated in seven major projects.

Our key project areas are located in both the Big George and Wyodak fairways. In our current capital budget, we estimate our capital expenditures for 2006 will be $21.5 million, which includes participating in 220 wells, of which 12 are PUD locations, and leasehold acquisitions. In the year ended December 31, 2005, we made $28.7 million of capital expenditures to participate in the drilling of 217 wells and for leasehold acquisitions. As of February 28, 2006, we had the necessary drilling permits and environmental approvals in place for all but 48 of the Company operated wells that are planned to be drilled in 2006. If we do not receive additional permits for the planned wells, we plan to drill other locations for which we have the necessary approvals.

Coalbed methane wells typically first produce water in a process called dewatering. This process lowers pressure, allowing the gas to detach from the coal and flow to the well bore. As the reservoir pressure declines, the wells begin producing methane gas at an increasing rate. As the wells mature, the production peaks, stabilizes and then begins declining. The average life of a coal bed well is approximately seven years. The average coal bed well in the Powder River Basin produces at a much lower rate with fewer reserves attributed to it than conventional natural gas wells in the Rockies.

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

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

Williston Basin

The Williston Basin, which is located in western North Dakota, northwestern South Dakota and eastern Montana, is a predominantly oil prone basin and produces oil and natural gas from 11 major geologic horizons that range in depth from approximately 1,000 to over 14,000 feet. The majority of our properties, both producing and prospective, are located within a 50-mile radius of Williston, North Dakota, the major industry service center for the area. The tight concentration of assets and proximate location to a service center allows for efficient operations.

While we have interests in a substantial number of wells in the Williston Basin, which target several different zones, our exploration and development activities currently are concentrated on three of the oil producing formations, the Madison, Bakken and the Red River. The application of horizontal completions in these formations has yielded significant improvement in the recovery of hydrocarbons from reservoirs compared to vertically drilled well completions in the same type of formations. The basin has established infrastructure and access to materials and services. Our oil is stored in tanks located at the well site and periodically collected by independent oil purchasers. Regulatory delays are less prevalent than other areas due to fee ownership of properties, more efficient state and local regulatory bodies and more reasonable permitting requirements.

We participated in the drilling of 12 horizontal wells in 2005 as part of our 2005 capital program of $17.0 million in this area. In our current capital budget, we estimate our capital drilling and completion expenditures for 2006 will be $28.5 million in the Williston Basin, which includes drilling 14 horizontal wells.

 

17


Madison, Bakken and Red River Development Projects

Our development drilling programs within the Williston Basin lie along the Montana and North Dakota and North and South Dakota borders and target prospective Madison, Bakken and Red River formations at depths of 7,400 to 10,500 feet. Wells are drilled vertically to these depths and then extended laterally up to 5,000 feet through our target zones.

In our 2005 Madison drilling program in Montana and North Dakota, we drilled or participated in six horizontal development wells in our Target, Nameless and Indian Hills field areas. Five of the six wells were successfully completed with initial gross potential production rates between 47 and 238 Bopd and we hold working interests ranging between 41% and 98%. The sixth well, a wildcat drilled in our Indian Hills area, was completed in December 2005 and currently is producing. The Company has a 42% working interest in this well and additional offset locations. In 2006, the Company plans to drill an additional five horizontal Madison development wells in our Target area, a second wildcat in the Indian Hills area and two additional horizontal Madison wildcat wells in our Red Bank Extension area of North Dakota.

The Company participated in three successful North Dakota nonoperated horizontal Bakken wells in 2005. Two were development wells in our Mondak area and the third was an exploratory well in our Red Bank extension area and all three currently are producing. The Company expects to participate in three additional non-operated Mondak Bakken development wells in 2006 with working interests between 10% and 25%. In our Red Bank Extension area, we participated in a horizontal Bakken exploration well with a 6% working interest in 2005 that currently is producing. This well establishes Bakken potential in addition to the horizontal Madison within the Red Bank Extension acreage area. We anticipate drilling an operated 60% working interest Red Bank Bakken exploration well in the late second quarter of 2006. In November 2005, we drilled the initial horizontal Bakken exploration well on our Montana, Red Water prospect leasehold. The well, in which we have a 50% working interest, is currently testing after a fracture stimulation.

In November 2005, we spud our first horizontal Red River B test well, in which we have a 60% working interest, in our Grand River area along the North and South Dakota border on the southern flank of the Williston Basin. Early tests are disappointing with recovery of water and slight shows of gas. A second exploratory well is scheduled for the second quarter of 2006.

Denver-Julesburg Basin

The DJ Basin covers parts of Colorado, Wyoming, Nebraska and Kansas and contains the well known Wattenberg field.

Tri-State

On January 28, 2005, we sold a 50% working interest in our Tri-State leasehold to an industry partner and entered into an agreement to jointly explore this area. Our exploration program focuses on the eastern side of the DJ Basin, which we refer to as our Tri-State area (which includes portions of northeastern Colorado, southwestern Nebraska and northwestern Kansas) and targets the biogenic shale gas potential of the Niobrara formation at depths less than 2,000 feet, and the conventional oil potential of Kansas City-Lansing, Marmaton, and Cherokee Formations of the Pennsylvanian System at depths of 4,000 to 4,800 feet. Production from this area can be sold into an already established interstate pipeline network.

We believe the Niobrara potential of the Tri-State area can be exploited with 3-D seismic “bright spot” technologies. During the year ended December 31, 2005, we participated in the drilling of seven wells, made leasehold acquisitions, and acquired 2-D seismic and 3-D seismic. All wells were completed and currently are producing into a pipeline. Based on our current capital expenditure budget, we estimate our capital expenditures for 2006 will be $7.7 million to participate in the drilling of 48 wells, for compression and gathering facilities, and for additional acreage acquisitions.

 

18


Big Horn Basin

The Big Horn Basin is located in north central Wyoming and lies west and north of the Powder River and Wind River Basins, respectively. Although the Big Horn Basin is largely considered an oil prone basin, we are pursuing both conventional stratigraphic and structural gas plays, as well as unconventional basin-centered gas plays in the basin. We have plans in 2006 to bring in an industry partner and to acquire a 42 square mile 3-D seismic survey and we plan to re-enter an existing well and test several additional formations as part of our ongoing program to assess the basin-centered gas potential of the basin.

Overthrust Belt

Montana Overthrust

We had 159,127 net undeveloped acres in the Montana overthrust belt as of December 31, 2005. In 2005, we acquired approximately 68 square miles of 3-D seismic. In 2006, we plan to bring in an industry partner, acquire additional 3-D seismic, and drill two exploratory tests.

Utah Hingeline

Our Utah Hingeline exploration play is located in the thrust belt of central Utah. As of December 31, 2005, we held interests in 17,346 net undeveloped acres.

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. As of December 31, 2005, we owned interests in 90,170 gross acres and 63,986 net acres in this area.

Pine Ridge

The Pine Ridge exploration prospect explores for gas fields in stratigraphic traps associated with salt diapirs. We intend to build our acreage position in this play through acquisitions or other arrangements with acreage owners in the area. During 2005, our planned 20 square mile 3-D seismic survey was delayed due to a court ruling affecting U.S Forest Service permitting procedures. Current plans call for the survey to be acquired in the fall of 2006.

Yellow Jacket

This prospect will target natural gas from a fractured shale reservoir at depths of 4,500 to 6,500 feet. Our plans for 2006 include continued acreage acquisition, which will be followed by selling a portion of our interest to an industry partner prior to drilling four exploratory test wells in 2006 to evaluate the shale gas potential.

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, 2003, 2004, and 2005 based on reserve reports prepared by us and reviewed in their entirety by our independent petroleum engineers. All our proved reserves included in the reserve report are located in North America. Ryder Scott Company, L.P. reviews all our reserve estimates except for our reserve estimates in the Powder River Basin, which are reviewed by Netherland, Sewell & Associates, Inc. When compared on a well-by-well or lease-by-lease basis, some of our estimates of net proved

 

19


reserves are greater and some are less than the estimates of our independent petroleum engineers. However, our internal estimates of total net proved reserves are within 10% of those estimated by our independent petroleum engineers. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the Securities and Exchange Commission 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,

 
     2003     2004     2005  

Estimated Net Proved Reserves:

      

Natural gas (Bcf)

     180.9       257.8       306.0  

Oil (MMBbls)

     3.9       5.7       5.8  

Total (Bcfe)

     204.2       292.3       341.0  

Percent proved developed

     62.5 %     61.1 %     61.1 %

Standardized Measure (in millions) (1)

   $ 404.8     $ 466.1     $ 782.5  

(1) The Standardized Measure represents the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development, production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. In accordance with SEC requirements, our reserves and the future net revenues were determined using market prices for natural gas and oil at each of December 31, 2003, 2004, and 2005, which were $5.58 per MMBtu of gas and $32.55 per barrel of oil at December 31, 2003, $5.52 per MMBtu of gas and $43.46 per barrel of oil at December 31, 2004, and $7.72 per MMBtu of gas and $61.04 per barrel of oil at December 31, 2005. These prices were adjusted by lease for quality, transportation fees and regional price differences.

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

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

Our independent engineers, Ryder Scott Company, L.P. and Netherland, Sewell & Associates, Inc., perform a well-by-well review of all of our properties and of our estimates of proved reserves and then provide us with their review reports concerning our estimates. Ryder Scott Company, L.P. provided us with a report stating its opinion that the methods and techniques used in preparing our reserve report are in accordance with generally accepted procedures for the determination of reserves, and that, in its judgment, there was no evidence of bias in the application of the methods and techniques for estimating proved reserves, and that the total proved net reserves estimated would be within 10% of those estimated by Ryder Scott Company, L.P. Netherland, Sewell & Associates, Inc. stated in its report that our estimates of proved oil and gas reserves and future revenue as shown in its report and in certain computer printouts in its office are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. These review reports do not state the degree of their concurrence with the accuracy of our estimate for the proved reserves attributable to our interest in any specific basin, property or well, although this information is generated by the independent engineers as a basis for their review report.

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

 

20


market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standard 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 Ryder Scott Company, L.P. and Netherland, Sewell & Associates, Inc. to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. Neither Ryder Scott Company, L.P. nor Netherland, Sewell & Associates, Inc. nor any of their respective employees has any interest in those properties and the compensation for these engagements is not contingent on their estimates of reserves and future cash inflows for the subject properties. During 2005, we paid Ryder Scott Company, L.P. $69,780 for reviewing our reserve estimates and $0 for other consulting services. During 2005, we paid Netherland, Sewell & Associates, Inc. $108,400 for reviewing our reserve estimates and $0 for other consulting services.

Production and Price History

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

 

    

Year Ended

December 31,

   2003    2004    2005

Production Data:

        

Natural gas (MMcf) (1)

     16,315      28,864      36,287

Oil (MBbls)

     328      474      523

Combined volumes (MMcfe)

     18,283      31,708      39,425

Daily combined volumes (MMcfe/d)

     50.1      86.6      108.0

Average Prices (2):

        

Natural gas (per Mcf)

   $ 4.03    $ 5.10    $ 7.16

Oil (per Bbl)

     28.85      39.49      46.68

Combined (per Mcfe)

     4.12      5.23      7.21

Average Costs (per Mcfe):

        

Lease operating expense

   $ 0.46    $ 0.46    $ 0.50

Gathering and transportation Expense

     0.20      0.19      0.30

Production tax expense

     0.54      0.63      0.85

Depreciation, depletion and Amortization

     1.68      2.15      2.27

General and administrative (3)

     0.78      0.57      0.62

(1) Production of natural gas liquids is included in natural gas revenues and production.
(2) Includes the effects of hedging transactions, which reduced average gas prices by $0.48 per Mcf in 2003, $0.43 per Mcf in 2004, and $0.57 per Mcf in 2005.
(3) Excludes non-cash stock-based compensation expense.

 

21


Productive Wells

The following table sets forth information at December 31, 2005 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

Basin

  

Gross

Wells

  

Net

Wells

  

Gross

Wells

  

Net

Wells

Piceance

   156.0    143.4    0    0

Wind River

   175.0    158.3    2.0    1.5

Uinta

   44.0    40.2    0    0

Powder River (1)

   421.0    349.3    43.0    8.4

Williston

   0    0    97.0    35.8

Big Horn

   2.0    1.0    0    0
                   

Total

   798.0    692.2    142.0    45.7
                   

(1) The five wells that had completions in more than one zone are each shown as only one gross well.

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2005 relating to our leasehold acreage.

 

    

Developed

Acreage (1)

  

Undeveloped

Acreage (2)

 

Basin

   Gross (3)    Net (4)    Gross (3)    Net (4)  

Piceance Basin

   2,887    2,075    17,767    14,302  

Wind River

   8,531    6,164    339,594    159,426  

Uinta

   8,609    8,262    181,579    137,764 (5)

Powder River

   32,959    26,048    95,666    53,040  

Williston

   13,952    9,190    228,281    126,807  

Green River

   —      —      17,076    7,716  

Denver-Julesburg

   —      —      380,119    182,856  

Paradox

   —      —      90,170    63,986  

Big Horn

   2,601    701    188,059    140,959  

Montana Overthrust

   —      —      197,648    159,127  

Utah Hingeline

   —      —      22,026    17,346  

Other

   2,624    1,112    34,823    15,902  
                     

Total

   72,163    53,552    1,792,808    1,079,231 (5)
                     

(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) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(4) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
(5) An additional 130,346 net undeveloped acres that are subject to drill-to-earn agreements are not included.

 

22


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 that we have been unable to obtain drilling permits due to a pending EA, Environmental Impact Statement or related legal challenge. The following table sets forth as of December 31, 2005 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, 2006

   51,389    30,288

December 31, 2007

   163,662    94,706

December 31, 2008

   424,702    222,500

December 31, 2009

   180,458    125,524

December 31, 2010 and later (1)

   972,597    606,213
         

Total

   1,792,808    1,079,231
         

(1) Includes 459,646 gross and 199,580 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, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.

 

    

Year Ended

December 31,

2003

  

Year Ended

December 31,

2004

  

Year Ended

December 31,

2005(1)

     Gross    Net    Gross    Net    Gross    Net

Development

                 

Productive

   50    41.5    150    147.9    98    82.3

Dry

   1    0.9    2    1.7    3    3

Exploratory

                 

Productive

   39    35.8    93    79.9    103    84.9

Dry

   2    1.6    13    10.0    5    3.3
                             

Total

                 

Productive

   89    77.3    243    227.8    201    167.2

Dry

   3    2.5    15    11.7    8    6.3

(1) The determination of development and exploratory wells shown in the table above is based on an interpretation of the definitions of those terms in Rule 4-10(a) of Regulation S-X, which governs financial disclosures in filings with the SEC, that includes as development wells only those wells drilled on drilling locations to which proved undeveloped, or PUD, reserves have been attributed at the time at which drilling of the wells commenced, and in which all other wells are considered exploratory. We also are providing information with respect to drilling results in which development wells include not only wells drilled on PUD locations but also wells drilled in a proved area in which proved reserves have been attributed by our reservoir engineers as of the time of commencement of drilling. On this basis, during 2005, we completed 190 gross (163.7 net) productive and 1 gross (0.9 net) dry development wells and 13 gross (5.5 net) productive and 5 gross (3.3 net) dry exploratory wells.

 

23


From inception through December 31, 2005, we participated in drilling 797 gross wells, of which 533 were completed as producing, 238 were in process of completing or dewatering and 26 were dry holes. Also during that time, we recompleted 88 gross wells, which are not included in the totals above.

Operations

General

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

Marketing and Customers

We market the majority of the natural gas and oil production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell the majority of our production to a variety of purchasers under short term and long term gas purchase contracts with daily, monthly, seasonal, annual or multi-year terms, all at market prices. 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. For a list of our purchasers that accounted for 10% or more of our natural gas and oil revenues during the last two calendar years, see “Notes to Consolidated Financial Statements—Note 12—Significant Customers and Other Concentrations”.

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

Our natural gas and oil are transported through our own and third party gathering systems and pipelines and we incur 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 transporter. Transportation space 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 contractually commit to long term firm transportation agreements to ensure that we have the guaranteed pipeline capacity to flow and sell a portion of our gas volumes. We also may contractually commit to long term firm sales agreements to ensure that we are selling to a purchaser who has guaranteed pipeline capacity. The following table sets forth information with respect to long term (greater than one year from December 31, 2005) firm transportation contracts for pipeline capacity, which typically require a demand charge and firm sales contracts.

 

24


Type of Arrangement

   Pipeline System /Location    Volume (MMBtu/d)    Term

Firm Transport

   WIC Medicine Bow    18,000    1/05–3/07

Firm Sales

   Cheyenne Hub    10,000    4/05 – 3/07

Firm Sales

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

Firm Sales

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

Firm Transport

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

Firm Transport

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

Firm Transport

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

Firm Transport

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

Firm Transport

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

Firm Transport

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

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 may be able to pay more for productive oil and natural gas properties and exploratory prospects or to 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 or integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state, local and Native American tribal laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to 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 properties, we may obtain a title opinion or review previously obtained title opinions. Our natural gas and oil properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Seasonal Nature of Business

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

 

25


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 the Company to litigation by environmental and other special interest groups.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and the federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or more stringent and costly waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of more stringent future laws and regulations at this time. For the year ended December 31, 2005, we did not incur any material capital expenditures for remediation or retrofit of pollution control equipment at any of our facilities.

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

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

 

26


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

Water Discharges . The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by 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 substantial compliance with the terms thereof. Obtaining permits has the potential to delay the development of oil and natural gas projects.

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

 

27


compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining permits has the potential to delay the development of oil and natural gas projects.

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

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

Other Regulation of the Oil and Gas Industry

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

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

 

    the location of wells;

 

    the method of drilling and casing wells;

 

    the rates of production or “allowables”;

 

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

 

    the plugging and abandoning of wells; and

 

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

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration

 

28


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

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

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 service, which occurs upstream of jurisdictional transmission services, is regulated by state agencies. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point-of-sale locations.

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

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

 

29


court system, unless there is a specific waiver of sovereign immunity by the Native American tribe allowing resolution of disputes between the Native American tribe and those lessees or operators to occur in federal or state court.

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

Employees

As of February 28, 2006, we had 190 full time employees, including 19 geologists and geophysicists, 16 petroleum engineers, and eight land and regulatory professionals. Of our 190 full time employees, 129 work in our Denver office and 61 are in our district and field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees is represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Offices

As of December 31, 2005, we leased approximately 60,533 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 have field offices in or near the Cave Gulch field, which we own, and in Gillette, Wyoming, Parachute, Colorado, and Roosevelt, Utah, which we lease. We believe that our facilities are adequate for our current operations and that additional leased space can be obtained 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 18 th Street, Suite 2300, Denver, Colorado 80202.

 

30


GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report on Form 10-K.

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.

AMI. Area of mutual interest.

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, used in this Annual Report on Form 10-K in reference to crude oil or other liquid hydrocarbons.

Bbl/d. Bbl per day.

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.

Biogenic gas. Bacteria-generated natural gas usually found at depths of a few hundred to a few thousand feet because it is formed at the low temperatures that accompany the shallow burial and rarely is generated at depths greater that 3,000 feet.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

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

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

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

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

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.

 

31


Discontinuous lenticular sands. Sandstone reservoirs that have a limited aerial extent. In general these types of sandstones will be encountered by separate wellbores infrequently in a given area depending on well density. By comparison, a continuous or blanket sandstone may be encountered repeatedly by multiple wellbores in a given area.

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 or exploration agreement.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

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

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

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

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

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and Development Costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Fractured shale gas. Gas that is present in fractures in a formation consisting mostly of shale.

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

Horizontal re-entry well. A new well in which a pre-existing wellbore is used as the starting point of a new horizontal borehole. Drilling a horizontal re-entry well typically involves milling a hole in the casing of the pre-existing wellbore and drilling hundreds or thousands of feet from the pre- existing wellbore.

Identified drilling locations . Total gross locations specifically identified and scheduled by management as an estimation of the Company’s multi-year drilling activities on existing acreage. The Company’s 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.

Infill drilling. The drilling of wells between established producing wells on a lease to increase reserves or productive capacity from the reservoir.

 

32


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.

MMboe. Million barrels of oil equivalent.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcf/d. MMcf per day.

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

MMcfe/d. MMcfe per day.

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

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

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

PDNP. Proved developed nonproducing.

PDP. Proved developed producing.

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.

PUD. Proved undeveloped.

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

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

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

 

33


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

Proved undeveloped reserves (PUD). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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

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

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 oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.

Tight gas sands. A formation with low permeability that produces natural gas with very low flow rates for long periods of time.

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

The Company’s business involves a high degree of risk. You should carefully consider the following risks and all of the other information contained in this Form 10-K before deciding to invest in our common stock. The risks described below are not the only ones facing our company. 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

 

34


impact on the value of our reserves and on our cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

    the domestic and foreign supply of oil and natural gas;

 

    the price of foreign imports;

 

    overall domestic and global economic conditions;

 

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

 

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

 

    the level of consumer product demand;

 

    weather conditions;

 

    technological advances affecting energy consumption;

 

    domestic and foreign governmental regulations;

 

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

 

    the price and availability of alternative fuels; and

 

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

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

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

In considering whether to invest in our common stock, you should consider that there is only limited historical financial and operating information available on which to base your evaluation of our performance. We were formed in January 2002 and, as a result, we have a limited operating history.

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

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

No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and

 

35


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. We prepare our own estimates of proved reserves, which are reviewed by independent petroleum engineers. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. Also, we make certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. At year end 2003, we revised our proved reserves downward from our 2002 reserve report by approximately 41 Bcfe. The majority of the downward revision was due to reclassifying deep proved undeveloped reserves and reevaluating the economic potential of behind pipe reserves in the Wind River Basin as a result of a periodic review of our reserves and reserve evaluation methodologies and an analysis of the results of our recompletion program. At year end 2004, we revised our proved reserves downward from our 2003 reserve report by approximately 32 Bcfe. The downward revision was primarily the result of infill drilling in depleted sands in the Wind River Basin and greater pressure depletion than expected in two areas in the Powder River Basin. At year end 2005, we revised our proved reserves downward from our 2004 reserve report by approximately 24.7 Bcfe, primarily as a result of a reduction in proved undeveloped reserves in the Piceance Basin due to the use of completion techniques performed from January through September 2005 that yielded results lower than our expectations at year end 2004. During 2005, reviews of proved oil and gas properties in the Wind River Basin indicated a decline in the recoverability of their carrying value and the need for an impairment in the Cooper Reservoir, Talon and East Madden fields in the total amount of $42.7 million. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and gas we ultimately recover being different from our reserve estimates.

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

 

    actual prices we receive for oil and natural gas;

 

    the amount and timing of actual production;

 

    supply of and demand for oil and natural gas; and

 

    changes in governmental regulations or taxation.

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

Our independent engineers perform a well-by-well review of all of our properties and of our estimates of proved reserves, but the review report they issue to us only addresses the total amount of our estimates for the sum of all properties covered by our reserve report. These review reports do not state the degree of their concurrence with the accuracy of our estimate for the proved reserves attributable to our interest in any specific basin, property or well, although this information is generated by the independent engineers as a basis for their review report. In the case of the properties reviewed by each of the two independent engineers, our estimates of proved reserves at December 31, 2005 in the aggregate were 8.1% above those of Ryder Scott Company, L.P. and at December 31, 2005 in the aggregate were 7.6% above Netherland, Sewell & Associates, Inc.

 

36


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

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2005, production will decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to 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 current prospects and our plans to explore those prospects in this prospectus. 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. From inception through December 31, 2005, we participated in drilling a total of 797 gross wells, of which 26 have been identified as dry holes. 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. In sum, the cost of drilling, completing and operating any wells is often uncertain and new wells may not be productive.

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

The Powder River Basin represented a significant part of our drilling program and production in 2005. Our development operations are conducted in seven project areas in this basin. 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 have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

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

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas 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

 

37


enable geoscientists to know whether hydrocarbons are, in fact, present in those structures. The Company is employing 3C 3-D seismic technology to certain of its 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 increases its cost. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. 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 over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may chose not to acquire option or lease rights prior to acquiring seismic data and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, it would result in our having made substantial expenditures to acquire and analyze 3-D data without having an opportunity to attempt to benefit from those expenditures.

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

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

 

    unusual or unexpected geological formations;

 

    pressures;

 

    fires;

 

    blowouts;

 

    loss of drilling fluid circulation;

 

    title problems;

 

    facility or equipment malfunctions;

 

    unexpected operational events;

 

    shortages or delivery delays of equipment and services;

 

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

 

    adverse weather conditions.

Additionally, the coal beds in the Powder River Basin from which we produce methane gas frequently contain water, which may hamper our ability to produce gas in commercial quantities. The amount of coalbed methane that can be commercially produced depends upon the coal quality, the original gas content of the coal seam, the thickness of the seam, the reservoir pressure, the rate at which gas is released from the coal, and the existence of any natural fractures through which the gas can flow to the well bore. However, coal beds frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore. The average life of a coal bed well is only five to six years. 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.

 

38


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

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

 

    our proved reserves;

 

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

 

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

 

    our ability to acquire, locate and produce new reserves.

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

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

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

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

Our Powder River Basin coalbed methane exploration and production activities result in the discharge of large volumes of produced groundwater into adjacent lands and waterways. The ratio of methane gas to produced water varies over the life of the well. The environmental soundness of discharging produced groundwater

 

39


pursuant to water discharge permits has come under increased scrutiny. Moratoriums on the issuance of additional water discharge permits, or more costly methods of handling these produced waters, may affect future well development. Compliance with more stringent laws or regulations, or more vigorous enforcement policies of the regulatory agencies, or 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.

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

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

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 are focused on the Rocky Mountain region, which means our producing properties are geographically concentrated in that area. In particular, a substantial portion of our proved oil and natural gas reserves are located in the Piceance and Wind River Basins. Approximately 34% of our proved reserves at December 31, 2005 and approximately 19% of our December 2005 production were located in the Piceance Basin and approximately 25% of our proved reserves at December 31, 2005 and approximately 33% of our December 2005 production were located in the Wind River Basin. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production or interruption of transportation of natural gas produced from the wells in these basins.

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

 

40


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

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

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

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

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

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

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

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

To achieve a more predictable cash flow, to reduce our exposure to adverse fluctuations in the prices of oil and natural gas and to comply with credit agreement requirements, we currently, and may in the future, enter into

 

41


hedging arrangements for a portion of our oil and natural gas production. Hedging arrangements for a portion of our oil and natural gas production expose us to the risk of financial loss in some circumstances, including when:

 

    production is less than expected;

 

    the counter-party to the hedging contract defaults on its contract obligations; or

 

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

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

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

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

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

We depend on the performance of our executive officers and other key employees. The loss of any member of our senior management or other key employees could negatively impact our ability to execute our strategy. We do not maintain key person life insurance policies on any of our employees. For a description of our management philosophy, see “Item 10. Directors and Executive Officers of the Registrant—Executive Officers and Other Key Employees—Management Philosophy”.

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

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

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

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

 

42


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

Risks Related to Our Common Stock

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

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

 

    actual or anticipated quarterly variations in our operating results;

 

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

 

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

 

    conditions generally affecting the oil and natural gas industry;

 

    the success of our operating strategy; and

 

    the operating and stock price performance of other comparable companies.

Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. If the market price of our common stock declines significantly, you may be unable to resell your shares of common stock at or above the public offering price. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly, including a decline below the public offering price, in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.

Future sales of our common stock may cause our stock price to decline.

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

As of February 28, 2006, we had 43,837,395 shares of common stock outstanding, excluding stock options. All of the 14,950,000 shares sold in our initial public offering in December 2004, other than shares purchased by our affiliates, are freely tradable. In addition, the remaining outstanding shares are either freely tradable or may be sold in accordance with the provisions of Rule 144. Certain of our stockholders have contractual rights to cause us to register the resale of up to 14,332,836 of these shares. This registration may be accomplished quickly by filing prospectus supplements under our currently effective shelf registration statement. The resale of a large number of shares could cause our stock price to decline.

 

43


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 a shareholder rights plan.

These provisions also could discourage proxy contests and make it more difficult for you and other 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 entities affiliated with The Goldman Sachs Group, Inc. (each an “institutional investor”) beneficially own approximately 23.0% and 6.3%, respectively, of our outstanding common stock. Additional stockholders beneficially own 7.4% and 9.9% of our outstanding common stock. Accordingly, these stockholders may be able to control the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws and the approval of mergers and other significant corporate transactions. This concentrated ownership makes it less likely that any other holder or group of holders of common stock will be able to affect the way we are managed or the direction of our business. These factors also may delay or prevent a change in our management or voting control. In addition, one of our directors is affiliated with Warburg Pincus Private Equity VIII, L.P. and another director is affiliated with The Goldman Sachs Group, Inc.

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

 

Item 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. 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.

 

44


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 period from December 10, 2004 when trading of our Common Stock commenced on the New York Stock Exchange through December 31, 2005, as reported by the NYSE, is as follows:

 

     High    Low

2004

     

Fourth Quarter (from December 10, 2004 through December 31, 2004)

   $ 35.00    $ 27.49

2005

     

First Quarter

   $ 33.00    $ 26.00

Second Quarter

     32.30      25.90

Third Quarter

     39.39      28.89

Fourth Quarter

     42.59      30.19

On February 28, 2006, the closing sales price for the Common Stock as reported by the NYSE was $33.12 per share.

Holders. On February 28, 2006, the number of holders of record of common stock was 192.

Dividends. We have not paid any cash dividends since our inception. We anticipate that all earnings will be retained for the development of our business and that no cash dividends will be paid on our Common Stock in the foreseeable future.

 

Item 6. Selected Financial Data

The following table presents selected historical financial data of the Company for the period from January 7, 2002 (inception) through December 31, 2002 and the years ended December 31, 2003, 2004, 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 financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”, presented elsewhere in this Annual Report on Form 10-K.

Selected Historical Information for Bill Barrett Corporation

The consolidated income statement information for the years ended December 31, 2003, 2004, and 2005 and the balance sheet information as of December 31, 2004 and 2005 are derived from our audited financial statements included elsewhere in this report. The income statement information for the period from January 7, 2002 (inception) through December 31, 2002 and the balance sheet information at December 31, 2002 and 2003 is derived from audited financial statements that are not included in this report.

 

45


      

Period from
January 7, 2002
(inception)
through
December 31,

2002

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

Statement of Operations Data:

        

Production revenues(1)

   $ 16,007     $ 75,252     $ 165,843     $ 284,406  

Other revenues

     74       184       4,137       4,353  

Operating expenses:

        

Lease operating expense

     2,231       8,462       14,592       19,585  

Gathering and transportation expense

     229       3,646       5,968       11,950  

Production tax expense

     2,021       9,815       20,087       33,465  

Exploration expense

     1,592       3,655       12,661       10,930  

Impairment, dry hole costs and abandonment expense

     —         4,274       24,011       55,353  

Depreciation, depletion and amortization

     9,162       30,724       68,202       89,499  

General and administrative

     5,476       14,213       18,061       24,540  

Non-cash stock-based compensation expense

     1,322       3,637       3,031       3,212  
                                

Total operating expenses

     22,033       78,426       166,613       248,534  
                                

Operating (loss) income

     (5,952 )     (2,990 )     3,367       40,225  

Other income (expense):

        

Interest income

     303       123       437       1,977  

Interest expense

     (65 )     (1,431 )     (9,945 )     (3,175 )

Loss on sale of securities

     (1,465 )     —         —         —    
                                

Total other expense

     (1,227 )     (1,308 )     (9,508 )     (1,198 )
                                

Income (loss) before income taxes

     (7,179 )     (4,298 )     (6,141 )     39,027  

Provision for (benefit from) income taxes

     (2,164 )     (320 )     (875 )     15,222  
                                

Income (loss) from continuing operations

     (5,015 )     (3,978 )     (5,266 )     23,805  

Income from discontinued operations (net of taxes)

     27       —         —         —    
                                

Net income (loss)

     (4,988 )     (3,978 )     (5,266 )     23,805  

Less deemed dividends on preferred stock

     —         —         (36,343 )     —    

Less cumulative dividends on preferred stock

     (4,430 )     (12,682 )     (18,633 )     —    
                                

Net income (loss) attributable to common stockholders

   $ (9,418 )   $ (16,660 )   $ (60,242 )   $ 23,805  
                                

Income (loss) per common share(2):

        

Basic

   $ (18.02 )   $ (19.38 )   $ (15.40 )   $ 0.55  

Diluted

   $ (18.02 )   $ (19.38 )   $ (15.40 )   $ 0.55  

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

     522.7       859.4       3,912.3       43,238.3  

Weighted average number of common shares outstanding, diluted

     522.7       859.4       3,912.3       43,439.6  
      

Period from
January 7, 2002
(inception)
through
December 31,

2002

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

Selected Cash Flow and Other Financial Data:

        

Net income (loss)

   $ (4,988 )   $ (3,978 )   $ (5,266 )   $ 23,805  

Depreciation, depletion, impairment and amortization

     9,162       30,724       68,202       89,499  

Other non-cash items

     672       7,786       26,887       71,168  

Change in assets and liabilities

     (967 )     (659 )     (2,941 )     (202 )
                                

Net cash provided by operating activities

   $ 3,879     $ 33,873     $ 86,882       184,270  
                                

Capital expenditures(4)

   $ 166,893     $ 186,327     $ 347,520 (5)   $ 347,427 (5)

(1) Revenues are net of effects of hedging transactions.
(2) All per share information has been adjusted to reflect the 1-for-4.658 reverse common stock split effected upon the completion of our IPO in December 2004.

 

46


(3) The weighted average number of common shares outstanding used in the loss per share calculation are computed pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 128 Earnings Per Share . The weighted average common shares outstanding for the year ended December 31, 2004 does not include the 6,594,725 Series A or the 51,951,418 Series B preferred stock that were converted into a total of 26,387,679 common shares until the completion of our IPO in December 2004.
(4) Excludes future reclamation liability accruals of $1.0 million, $2.9 million, $7.1 million, and $10.7 million in 2002, 2003, 2004, and 2005, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $1.6 million, $6.1 million, $36.2 million, and $23.6 million in 2002, 2003, 2004, 2005, respectively. Also includes furniture, fixtures and equipment costs of $1.1 million in 2002, $1.8 million in 2003, $2.1 million in 2004, and $2.6 million in 2005.
(5) Not deducted from the amount is $8.8 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, 2004 and 2005, respectively.

 

     As of December 31,
     2002    2003    2004    2005
     (in thousands)

Balance Sheet Data:

           

Cash and cash equivalents

   $ 5,713    $ 16,034    $ 99,926    $ 68,282

Other current assets

     7,246      19,613      37,964      73,036

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

     156,372      307,920      549,182      737,992

Other property and equipment, net of depreciation

     896      1,539      2,983      7,956

Other assets

     2,465      2,663      6,103      1,679
                           

Total assets

   $ 172,692    $ 347,769    $ 696,158    $ 888,945
                           

Current liabilities

   $ 10,873    $ 46,156    $ 62,106    $ 132,798

Long-term debt

     36,900      58,900      —        86,000

Other long-term liabilities

     1,117      4,387      14,320      39,364

Stockholders’ equity

     123,802      238,326      619,732      630,783
                           

Total liabilities and stockholders’ equity

   $ 172,692    $ 347,769    $ 696,158    $ 888,945
                           

 

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

Introduction

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the accompanying financial statements and related notes included elsewhere herein. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Item 1A. Risk Factors” and the “Cautionary Note Regarding Forward-Looking Statements” subsection of this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

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.

 

47


We intend to increase stockholder value by profitably growing reserves and production, primarily through drilling operations. We seek high quality exploration and development projects with potential for providing long- term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of natural gas and oil production under either short-term contracts or spot gas purchase contracts at market prices. Approximately 93% of our December 2005 production was natural gas.

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

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 our private equity stock investments, our bank line of credit, cash flow from operations and, in the case of the Piceance Basin properties, a bridge loan that was repaid in December 2004 with a portion of the proceeds of our initial public offering. The March 2002 purchase of properties in the Wind River Basin included core properties in the Cave Gulch and Wallace Creek fields. The April 2002 acquisition in the Uinta Basin included the West Tavaputs project area. The December 2002 acquisition included the Cooper Reservoir field, properties in the Powder River Basin and oil properties in the Williston Basin, along with other properties that were not deemed core to our business operations (approximately 20% of the acquisition) and that were sold in 2003. The September 2004 acquisition included the Gibson Gulch field in the Piceance Basin. Our 2003 and 2004 activities include development drilling and exploration in each of these areas. Our activities are now focused on evaluating and developing our asset base, increasing our acreage positions, and evaluating potential acquisitions.

As of December 31, 2005, we had 341 Bcfe of estimated net proved reserves with a Standardized Measure of $782 million. As of December 31, 2004, we had 292 Bcfe of estimated net proved reserves with a Standardized Measure of $466 million, while at December 31, 2003, we had 204 Bcfe of estimated net proved reserves with a Standardized Measure of $405 million.

Our finding and development costs over the relatively short period of our existence have been high relative to other operators, particularly those with later stage development activities in the Rockies, and we expect that trend to continue at least through 2006 and until we have a higher proportion of later stage development activities. We anticipate that, as we conduct further development, we will be able to leverage existing infrastructure and achieve economies from improved production recovery experience and infill drilling development. Although we cannot provide assurance, we anticipate that, in the long term, our future finding and development costs will be more competitive with the industry broadly and with Rockies operators, in particular.

 

48


The average sales prices received for natural gas in all our core areas rose sharply in 2003, 2004, and 2005 compared to prior periods. Before the effect of hedging contracts, the average price we received for natural gas in 2003 was $4.51 per Mcf compared to $2.39 per Mcf in 2002. Before the effects of hedging contracts, the average price we received for oil was $28.85 per Bbl in 2003 compared to $25.39 per Bbl in 2002. Before the effect of hedging contracts, the average price we received for natural gas and oil in 2004 was $5.53 per Mcf and $39.49 per Bbl, respectively. During the year ended December 31, 2005, before the effects of hedging contracts, the average price we received for natural gas was $7.73 per Mcf and the average price we received for oil was $53.69 per Bbl.

Higher oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of those goods and services. To date, the higher sales prices for natural gas and oil have more than offset the higher field costs. Given the inherent volatility of oil and natural gas prices that are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions, which generally are lower than the average sales prices received in 2005. We focus our efforts on increasing natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production.

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

 

49


Results of Operations

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

 

             2003 to 2004
Increase
(Decrease)
        2004 to 2005
Increase
(Decrease)
 
     Year Ended
December 31, 2003
  Year Ended
December 31, 2004
  Amount     Percent     Year Ended
December 31, 2005
  Amount     Percent  
     (in thousands)  

Operating Results:

              

Revenues

              

Oil and gas production

   $ 75,252   $ 165,843   $ 90,591     120 %   $ 284,406   $ 118,563     71 %

Other income

     184     4,137     3,953     2,148 %     4,353     216     5 %

Operating Expenses

              

Lease operating expense

     8,462     14,592     6,130     72 %     19,585     4,993     34 %

Gathering and transportation expense

     3,646     5,968     2,322     64 %     11,950     5,982     100 %

Production tax expense

     9,815     20,087     10,272     105 %     33,465     13,378     67 %

Exploration expense

     3,655     12,661     9,006     246 %     10,930     (1,731 )   (14 %)

Impairment, dry hole costs and abandonment expense

     4,274     24,011     (19,737 )   (462 %)     55,353     31,342     131 %

Depreciation, depletion and amortization

     30,724     68,202     37,478     122 %     89,499     21,297     31 %

General and administrative

     14,213     18,061     3,848     27 %     24,540     6,479     36 %

Non-cash stock-based compensation expense

     3,637     3,031     (606 )   (17 %)     3,212     181     6 %
                                      

Total operating expenses

   $ 78,426   $ 166,613   $ 88,187     112 %   $ 248,534   $ 81,921     49 %
                                      

Production Data:

              

Natural gas (MMcf)

     16,315     28,864     12,549     77 %     36,287     7,423     26 %

Oil (MBbls)

     328     474     146     45 %     523     49     10 %

Combined volumes (MMcfe)

     18,283     31,708     13,426     73 %     39,425     7,716     24 %

Daily combined volumes (Mmcfe/d)

     50     87     37     74 %     108     21     24 %

Average Prices (1):

              

Natural gas (per Mcf)

   $ 4.03   $ 5.10   $ 1.07     27 %   $ 7.16   $ 2.06     40 %

Oil (per Bbl)

     28.85     39.49     10.64     37 %     46.68     7.19     18 %

Combined (per Mcfe)

     4.12     5.23     1.11     27 %     7.21     1.98     38 %

Average Costs (per Mcfe):

              

Lease operating expense

   $ 0.46   $ 0.46   $ 0.00     0 %   $ 0.50   $ 0.04     9 %

Gathering and transportation expense

     0.20     0.19     (0.01 )   (5 %)     0.30     0.11     58 %

Production tax expense

     0.54     0.63     0.09     17 %     0.85     0.22     35 %

Depreciation, depletion and amortization

     1.68     2.15     0.47     28 %     2.27     0.12     6 %

General and administrative

     0.78     0.57     (0.21 )   (27 %)     0.62     0.07     13 %

(1) Average prices shown in the table are net of the effects of hedging transactions. As a result of hedging transactions, natural gas and oil production revenues were reduced by $7.7 million, $12.4 million and $24.3 million for the years ended December 31, 2003, 2004, and 2005, respectively. Before the effect of hedging contracts, the average price we received for natural gas in 2005 was $7.73 per Mcf compared with $5.53 per Mcf in 2004 and $4.51 per Mcf in 2003.

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

Production Revenues . Production revenues increased from $165.8 million for the year ended December 31, 2004 to $284.4 million for the year ended December 31, 2005 due to both an increase in production and increases in natural gas and oil prices. Price increases added approximately $62.8 million of production revenues, and production increases from the development of existing properties added approximately $55.8 million of

 

50


production revenues. Significant decreases in product prices would significantly reduce our revenues from existing properties. See “—Quantitative and Qualitative Disclosure about Market Risk”. Other revenues totaled $4.4 million for the year ended December 31, 2005, which were principally gains on disposals of oil and gas properties.

Total production volumes for the 2005 calendar year increased 24% from 2004 with increases in all of the major producing basins with the exception of the Wind River Basin, which showed a decrease of 15% from 2004. Additional information concerning production is in the following table.

 

     Year Ended December 31,
     2004    2005
     Oil    Natural Gas    Total    Oil    Natural Gas    Total
     (MBbls)    (MMcf)    (MMcfe)    (MBbls)    (MMcf)    (MMcfe)

Wind River Basin

   107    17,676    18,318    68    15,157    15,565

Uinta Basin

   6    5,295    5,331    8    7,612    7,660

Powder River Basin

   —      4,934    4,934    —      8,405    8,405

Williston Basin

   329    162    2,136    376    149    2,405

Piceance Basin

   5    779    809    45    4,937    5,207

Other

   27    18    180    26    27    183
                             

Total

   474    28,864    31,708    523    36,287    39,425
                             

The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields that occurred throughout 2005. These natural production declines in the Wind River Basin were partially offset as the result of the exploration success of the Bullfrog Federal 14-18 well, the successful re-stimulation of the Cave Gulch 1-29 well, and of our development activities in the Talon field. Both the Bullfrog Federal 14-18 and the Cave Gulch 1-29 were put on production in late July 2005. The production increase in the Uinta Basin is due to development activities in West Tavaputs along with the exploration success of the Peters Point 6-7D well, which was put on production in October 2005. The production increase in the Powder River Basin reflects the success of our development activities throughout 2005. The production increase in the Williston Basin is principally due to continued exploration and development activities on our properties. The production increase in the Piceance Basin is the result of a full year of production and our development activities on properties we acquired in September 2004.

Hedging Activities . In 2005, we hedged approximately 50% of our natural gas volumes and 49% of our oil volumes, resulting in a reduction in revenues of $24.3 million. In 2004 we hedged approximately 38% of our natural gas volumes, incurring a reduction in revenues of $12.4 million. No oil volumes were hedged in 2004.

Lease Operating Expense and Gathering and Transportation Expense . Our lease operating expense increased slightly to $0.50 per Mcfe in 2005 compared to $0.46 in 2004, while our gathering and transportation expense increased from $0.19 per Mcfe in 2004 to $0.30 per Mcfe in 2005. The slight increase in lease operating expense is primarily the result of equipment rentals and diesel fuel costs associated with a temporary electrical power supply for new wells in the Powder River Basin. The increase in gathering and transportation expense is principally attributable to an increase of $5.4 million for our CBM properties in the Powder River Basin relating to increased third party charges for compressor fuel, processing charges incurred for removal of CO 2 in order to meet pipeline specifications, the relative increase in production in the Powder River Basin, which is a higher gathering cost area as compared to our conventional gas areas, and firm transportation fees we commenced incurring in 2005. We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to avoid possible production curtailments that may arise due to limited pipeline capacity in the Wind River, Uinta and Powder River Basins.

Production Tax Expense . Total production taxes increased from $20.1 million in 2004 to $33.5 million in 2005 as a result of higher production revenues, which increased primarily due to higher prices received and

 

51


higher volumes produced in 2005 compared to 2004. Production taxes as a percentage of natural gas and oil sales before hedging adjustments decreased from 11.3% in 2004 to 10.8% in 2005. Production taxes are primarily based on the wellhead values of production and tax rates that vary across the different areas that we operate. As the ratio of our production changes from area to area, our production rate will either increase or decrease depending on the quantities produced from each area and the production tax rates in effect in each individual area. For example, as we continue to develop our acreage position in the Piceance Basin in the State of Colorado, where the production tax rate for the state will approximate 6%, which is lower than our current overall rate, our overall production tax rate will decrease as more volumes are added from this lower tax rate area. Conversely, our overall production tax rate will increase as more volumes are added from higher tax areas such as in the State of Utah.

Exploration Expense . Exploration expense decreased from $12.7 million in 2004 to $10.9 million in 2005. The costs in 2004 include $11.3 million for seismic programs primarily in the DJ, Wind River and Uinta Basins and $1.4 million for delay rentals and other costs. The costs in the 2005 period include $9.4 million for seismic programs principally in the Uinta, Wind River and Big Horn Basins, and Montana Overthrust, and $1.5 million for delay rentals and other costs.

Impairment, Dry Hole Costs and Abandonment Expense . Our impairment, dry hole costs and abandonment expense increased from $24.0 million in 2004 to $55.3 million in 2005. During 2004, impairment expense was $0.5 million, dry hole costs were $23.0 million for exploratory dry holes primarily in the Wind River and Uinta Basins, and abandonment expense was $0.5 million. During 2005, impairment expense was $42.7 million, dry hole costs were $11.1 million for dry holes in the Wind River, Green River, Uinta and Williston Basins, and abandonment expense was $1.5 million. The impairment expense is the result of a $29.5 million impairment charge in the Cooper Reservoir field, $11.3 million impairment charge in the Talon field, and $1.9 million impairment charge in the East Madden field, all of which are located in the Wind River Basin. During the quarter ended June 30, 2005, production from existing and recently drilled infill wells in the Cooper Reservoir field declined more rapidly than anticipated indicating well interference and limited downspacing opportunities. In the Talon and East Madden fields, production from exploratory wells was at a rate that is not economic based on the capital investment.

We account for oil and gas exploration and production activities using the successful efforts method under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense, otherwise, the costs remain capitalized and are depleted as production occurs. The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of December 31, 2005 pending determination of whether the wells will be assigned proved reserves. The following table does not include $7.1 million related to exploratory wells in progress for which drilling had not been completed at December 31, 2005:

 

     Time Elapsed Since Drilling Completed
    

0-3

Months

  

4-6

Months

  

7-12

Months

  

> 12

Months

   Total
     (in thousands)

Wells for which drilling has completed

   $ 23,182    $ 19,194    $ 8,646    $ 3,418    $ 54,440

Depreciation, Depletion and Amortization . Depreciation, depletion and amortization expense was $89.5 million in 2005 compared to $68.2 million in 2004. $16.6 million of the increase was due to the 24% increase in production and $4.7 million was due to an increased DD&A rate for 2005. In 2004, the weighted average DD&A rate was $2.15 per Mcfe compared to $2.27 per Mcfe in 2005. Under successful efforts accounting, depletion expense is separately computed for each producing area. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a depletion rate for current production. In 2005, the relationship of capital expenditures, proved reserves and production from certain producing areas yielded a higher depletion rate than 2004. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

 

52


General and Administrative Expense . General and administrative expense increased $6.5 million from $18.0 million in 2004 to $24.5 million in 2005. This increase was primarily due to increased personnel required to support our capital program and production levels. As of December 31, 2005, we had 127 full-time employees in our corporate office compared to 101 as of December 31, 2004. On a per unit of production basis, general and administrative expense increased from $0.57 per Mcfe in 2004 to $0.62 per Mcfe in 2005. A significant portion of our general and administrative expense relates to the management of our capital expenditure program. Until our current capital investment levels result in increases in our production levels, we expect general and administrative expense per unit of production to remain at current levels.

Non-cash stock-based compensation expense included in general and administrative expense was $3.0 million in 2004 compared to $3.2 million in 2005. Non-cash stock-based compensation for 2004 is related to the vesting of the restricted common stock issued to management and employees upon formation of the Company, our stock option plans and purchases by employees of Series B convertible preferred stock at less than estimated fair market value. Non-cash stock-based compensation for 2005 is also related to the vesting of the restricted common stock issued to management upon the formation of the Company and our stock option plans, as well as nonvested equity shares of common stock issued to employees in 2005. The increase in expense was due principally to the recognition of compensation cost over the requisite service period for those awards granted in December 2004 and during 2005. The components of non-cash stock-based compensation for 2004 and 2005 are shown in the following table.

 

    

Year Ended

December 31,

     2004    2005
     (in thousands)

Restricted common stock

   $ 2,044    $ 489

Stock options and nonvested equity shares of common stock

     705      2,723

Employee purchases of Series B convertible preferred stock

     282      —  
             

Total

   $ 3,031    $ 3,212
             

Restricted common stock was subject to dual vesting provisions of: (1) one share vesting for every $141.62355 received from investors in Series B Preferred Stock (“dollar vesting”), and (2) 20% vesting upon purchase and an additional 20% vesting each year for four years after purchase (“time vesting”). These restricted shares vest at the later to occur of time vesting and dollar vesting. At December 31, 2005, the restricted common stock was 100% dollar vested and 98.3% time vested. As a result of being 100% dollar vested, no additional stock-based deferred compensation on restricted common stock will be incurred, however, at December 31, 2005, a balance of $0.04 million of deferred compensation remained to be amortized into non-cash stock-based compensation expense through January 2006 as a result of time vesting.

Interest Expense . Interest expense decreased $6.7 million to $3.2 million in 2005 compared to 2004. The decrease was due to higher debt levels in 2004 to fund acquisitions and development activities and a lack of a need to draw on our credit facility until the third quarter of 2005 due to the availability of the proceeds of our IPO in December 2004. The weighted average outstanding balance under our credit facility was $73.7 million for 2004 as compared to $23.4 million for 2005. In addition to increased borrowings under our credit facility in 2004, we borrowed $150 million under a bridge loan on September 1, 2004 to fund the acquisition of our Piceance Basin properties. The bridge loan, as well as the outstanding balance of our credit facility, was repaid in full in December 2004 with proceeds from our initial public offering. The bridge loan was terminated at that time so that it had no outstanding balance and no interest expense for the year ended December 31, 2005. To date, no interest has been capitalized.

Income Tax Expense . Our effective tax rate was 39% in 2005 and 14% in 2004. Our effective tax rate for 2005 and 2004 differs from the statutory rates primarily because of the amount of stock-based compensation expense recorded for financial statement purposes under Accounting Principles Board (“APB”) Opinion No. 25

 

53


and SFAS No. 123(R) that is not deductible for income tax purposes. Due to our net income position for the year ended December 31, 2005, these non-deductible permanent differences caused our effective tax rate to be higher than the rate that would have been effective if the costs would have been deductible. For the year ended December 31, 2004, the Company was in a net loss position and the non-deductible stock-based compensation expense caused the net loss to be greater than the net loss upon which income taxes are computed, thereby decreasing our effective tax rate. All of our income tax benefits and provisions to date are deferred. Due to the net operating loss carryforward and tax deductions being created by our drilling activities, we expect that we will not incur cash income tax liabilities for at least the next year.

Net Income (Loss) . We generated a net income of $23.8 million in 2005 compared to a net loss of $5.3 million in 2004. The primary reasons for the increase include an increase in total revenues of $118.8 million, an increase in interest income of $1.5 million, a decrease in exploration expense of $1.7 million and a decrease in interest expense of $6.7 million. This was offset by an increase in non-cash impairment, dry hole costs and abandonment expense of $31.3 million, an increase in depreciation, depletion and amortization of $21.3 million, and increase in other operating expenses of $31.0 million and an increase in income tax expense of $16.0 million.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Production Revenues . Production revenues increased from $75.3 million for the year ended December 31, 2003 to $165.8 million for the year ended December 31, 2004 due to both an increase in production and increases in natural gas and oil prices. Price increases added approximately $20.3 million of production revenues, and production increases from the development of existing properties, and to a lesser extent, the Piceance Basin Acquisition Properties, added approximately $70.2 million of production revenues. Significant decreases in product prices would significantly reduce our revenues from existing properties. See “—Quantitative and Qualitative Disclosure about Market Risk”. Other revenues totaled $4.1 million for the year ended December 31, 2004, which were principally gains on disposals of oil and gas properties.

Total production volumes for the 2004 calendar year increased 74% from 2003 with increases in all major producing basins. Additional information concerning production is in the following table.

 

     Year Ended December 31,
     2003 (1)    2004
     Oil    Natural Gas    Total    Oil    Natural Gas    Total
     (MBbls)    (MMcf)    (MMcfe)    (MBbls)    (MMcf)    (MMcfe)

Wind River Basin

   71    12,513    12,939    107    17,676    18,318

Uinta Basin

   2    1,355    1,367    6    5,295    5,331

Powder River Basin

   —      2,114    2,114    —      4,934    4,934

Williston Basin

   216    197    1,493    329    162    2,136

Piceance Basin

   —      —      —      5    779    809

Other

   39    136    370    27    18    180
                             

Total

   328    16,315    18,283    474    28,864    31,708
                             

(1) Excludes volumes produced related to properties held for sale.

The production increase in the Wind River Basin is due to development in our Cave Gulch and Cooper Reservoir fields that occurred throughout 2003 and 2004. The production increase in the Uinta Basin is due to development activities in both the West Tavaputs and Hill Creek areas. The production increase in the Powder River Basin reflects the acquisition made in March 2003 along with an active development program that commenced in the middle of 2003 and continued through 2004. The production increase in the Williston Basin is principally due to continued development activities on the properties that were acquired in December 2002.

Hedging Activities . In 2004, we hedged approximately 38% of our natural gas volumes, which resulted in a reduction in revenues of $12.4 million. No oil volumes were hedged in 2004. In 2003, we hedged approximately 45% of our natural gas volumes, incurring a reduction in revenues of $7.7 million, and in 2003 we hedged approximately 38% of our oil volumes, resulting in an immaterial increase to revenues.

 

54


Lease Operating Expense and Gathering and Transportation Expense . Our lease operating expense remained flat at $0.46 per Mcfe in 2004 and 2003, while our gathering and transportation expense decreased from $0.20 per Mcfe in 2003 to $0.19 per Mcfe in 2004. The decrease in gathering and transportation expense was primarily a result of using company owned gathering lines to transport gas in the Wallace Creek field in 2004 instead of outside party facilities that were used in 2003.

Production Tax Expense . Total production taxes increased from $9.8 million in 2003 to $20.1 million in 2004 as a result of higher production revenues, which increased primarily due to higher prices received and higher volumes produced in 2004 compared to 2003. Production taxes as a percentage of natural gas and oil sales before hedging adjustments remained relatively flat at 11.3% in 2004 and 11.8% in 2003. Production taxes are primarily based on the wellhead values of production and tax rates that vary across the different areas that we operate. As the ratio of our production changes from area to area, our production rate will either increase or decrease depending on the quantities produced from each area and the production tax rates in effect in each individual area.

Exploration Expense . Exploration expense increased from $3.7 million in 2003 to $12.7 million in 2004. The costs in the 2003 period include $3.1 million for seismic programs principally in the Wind River, DJ and Uinta Basins, and $0.6 million for delay rentals and other costs. The costs in 2004 include $11.3 million for seismic programs primarily in the DJ, Wind River and Uinta Basins and $1.4 million for delay rentals and other costs.

Impairment, Dry Hole Costs and Abandonment Expense . Our impairment, dry hole costs and abandonment expense increased from $4.3 million in 2003 to $24.0 million in 2004. During 2003, impairment expense was $1.8 million, for a write-down to fair value of undeveloped leasehold costs in southern Montana, dry hole costs were $2.2 million for exploratory dry holes in the Powder River and Uinta Basins and abandonment expense was $0.3 million. During 2004, impairment expense was $0.5 million, dry hole costs were $23.0 million for exploratory dry holes primarily in the Wind River and Uinta Basins and abandonment expense was $0.5 million. We account for oil and gas exploration and production activities using the successful efforts method under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense, otherwise, the costs remain capitalized and are depleted as production occurs. The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of December 31, 2004 pending determination of whether the wells will be assigned proved reserves. The following table does not include $4.1 million related to exploratory wells in progress for which drilling had not been completed at December 31, 2004:

 

     Time Elapsed Since Drilling Completed
    

0-3

Months

  

4-6

Months

  

7-12

Months

  

> 12

Months

   Total
     (in thousands)

Wells for which drilling has completed

   $ 10,105    $ 5,158    $ 570    $ —      $ 15,833

Depreciation, Depletion and Amortization . Depreciation, depletion and amortization expense was $68.2 million in 2004 compared to $30.7 million in 2003. $22.6 million of the increase was due to the 73% increase in production and $15.5 million was due to an increased DD&A rate for 2004. In 2003, the weighted average DD&A rate was $1.68 per Mcfe compared to $2.15 per Mcfe in 2004. Under successful efforts accounting, depletion expense is separately computed for each producing area. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a depletion rate for current production. In 2004, the relationship of capital expenditures, proved reserves and production from certain producing areas yielded a higher depletion rate than 2003. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

 

55


General and Administrative Expense . General and administrative expense increased $3.2 million from $17.9 million in 2003 to $21.1 million in 2004. This increase was primarily due to increased personnel required for our capital program and production levels. As of December 31, 2004, we had 101 full-time employees in our corporate office compared to 75 as of December 31, 2003. On a per unit produced basis, general and administrative expense decreased from $0.98 per Mcfe in 2003 to $0.67 per Mcfe in 2004 as production increased at a greater rate than our general and administrative expenses. At our stage of investment activity compared to our production level, a significant portion of our general and administrative expense consists of the personnel and related costs to prudently manage our capital expenditure program. Over time, as our capital expenditure program results in significantly higher production levels, we expect that general and administrative expense per unit of production will continue to decrease.

Non-cash stock-based compensation expense was $3.6 million in 2003 compared to $3.0 million in 2004. Non-cash stock-based compensation for 2003 and 2004 is related to the vesting of the restricted common stock issued to management and employees upon formation of the Company, our stock option plans and purchases by employees of Series B convertible preferred stock at less than estimated fair market value. The decrease in expense was due principally to the 2004 and 2003 vesting events related to our restricted common stock and stock options. The components of non-cash stock-based compensation for 2003 and 2004 are shown in the following table.

 

    

Year Ended

December 31,

     2003    2004
     (in thousands)

Restricted common stock

   $ 2,640    $ 2,044

Stock options

     565      705

Employee purchases of Series B convertible preferred stock

     432      282
             

Total

   $ 3,637    $ 3,031
             

Restricted common stock was subject to dual vesting provisions of: (1) one share vesting for every $141.62355 received from investors in Series B Preferred Stock (“dollar vesting”), and (2) 20% vesting upon purchase and an additional 20% vesting each year for four years after purchase (“time vesting”). These restricted shares vest at the later to occur of time vesting and dollar vesting. At December 31, 2004, the restricted common stock was 100% dollar vested and 78.3% time vested. As a result of being 100% dollar vested, no additional stock-based deferred compensation on restricted common stock will be incurred, however, at December 31, 2004, a balance of $0.5 million of deferred compensation remained to be amortized into non-cash stock-based compensation expense through January 2006 as a result of time vesting.

Interest Expense . Interest expense increased $8.5 million to $9.9 million in 2004 compared to 2003. The increase was due to higher debt levels in 2004 to fund acquisitions and development activities. The weighted average outstanding balance under our credit facility was $73.7 million for 2004 as compared to $39.8 million for 2003. In addition to borrowings under our credit facility, we borrowed $150 million under a bridge loan on September 1, 2004 to fund the acquisition of our Piceance Basin properties. The bridge loan, as well as the outstanding balance of our credit facility, was repaid in full in December 2004 with proceeds from our initial public offering. Total interest expense in 2004 under the bridge loan was $6.3 million comprised of fees of $3.7 million and interest charges of $2.6 million. To date, no interest has been capitalized.

Income Tax Expense . Our effective tax rate was 7% in 2003 and 14% in 2004. Our effective tax rate for 2003 and 2004 differs from the statutory rates primarily because of the amount of stock-based compensation expense recorded for financial statement purposes that is a permanent difference and will not be deducted for tax purposes. All of our income tax benefit and provisions to date are deferred. Our estimates of future taxable income, including potential elections to capitalize all intangible drilling costs and reversals of deferred tax liabilities, are considerable such that management has determined that the net deferred tax assets will be realized, and therefore no valuation allowance has been provided.

 

56


Net Income (Loss) . We generated a net loss of $5.3 million in 2004 compared to a net loss of $4.0 million in 2003. The primary reasons for the increased loss was an increase in impairment, dry hole costs and abandonment expense of $19.7 million, an increase in exploration expense of $9.0 million and an increase in other expense of $8.2 million (principally interest expense). These factors contributing to the increased loss were offset by an increase in operating income, excluding impairment, dry hole costs and abandonment expense and exploration expense of $35.1 million and an increase in income tax benefit of $0.5 million.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been from sales and other issuances of securities, net cash provided by operating activities, a bank line of credit and a bridge loan to finance our September 2004 acquisition of properties in the Piceance Basin in Colorado. Our primary use of capital has been for the acquisition, development, and exploration of oil and natural gas properties. As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we may need to obtain additional equity or debt financing.

At December 31, 2005, our balance sheet reflected a cash balance of $68.3 million with a balance of $86.0 million outstanding on our credit facility. The bridge loan was repaid and terminated in December 2004, principally as a result of completing our initial public offering on December 15, 2004 from which we received net proceeds of $347 million.

Cash Flow from Operating Activities

Net cash provided by operating activities was $33.9 million, $86.9 million and $184.3 million in 2003, 2004 and 2005, respectively. The increases in net cash provided by operating activities was substantially due to increased production revenues, partially offset by increased expenses, as discussed above in “—Results of Operations”. Changes in assets and liabilities reduced cash flow from operations by $0.7 million, $2.9 million, and $0.02 million in 2003, 2004 and 2005, respectively.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas and oil produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially 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 below, “—Quantitative and Qualitative Disclosure About Market Risk”.

To mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices and to comply with our credit agreement, we have entered into commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. At December 31, 2005, we had in place natural gas and crude oil collars covering portions of our 2006 and 2007 production. Our natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities , and are classified as either current or non current liabilities in our Consolidated Balance Sheets based on scheduled delivery of the underlying production.

As of February 28, 2006, we had hedges in place for approximately 59,000 MMbtu and 29,000 MMbtu of natural gas production for 2006 and 2007, respectively, and approximately 750 Bbls and 600 Bbls of oil production for 2006, and 2007, respectively.

 

57


The table below summarizes the volumes associated with the collar contracts as of February 28, 2006:

 

Product

  

Volume

Per Day

  

Quantity

Type

  

Weighted
Average Floor

Pricing

  

Weighted
Average Ceiling

Pricing

  

Index

Price (1)

   Contract Period

Natural gas

   35,000    MMBtu    $ 4.82    $ 6.72    NORRM    1/1/2006–12/31/2006

Natural gas

   24,000    MMBtu    $ 7.54    $ 13.68    CIG    1/1/2006–12/31/2006

Oil

   750    Bbls    $ 42.53    $ 52.26    WTI    1/1/2006–12/31/2006

Natural gas

   29,000    MMBtu    $ 5.25    $ 10.22    CIG    1/1/2007–12/31/2007

Oil

   600    Bbls    $ 50.00    $ 78.15    WTI    1/1/2007–12/31/2007

(1) NORRM refers to Northwest Pipeline Rocky Mountains price and CIG refers to Colorado Interstate Gas Rocky Mountains price as quoted in Platt’s for Inside FERC on the first business day of each month. WTI refers to the West Texas Intermediate price as quoted on the New York Mercantile Exchange. See “—Quantitative and Qualitative Disclosure about Market Risk”.

By removing the price volatility from a portion of our natural gas and oil production for 2006 and 2007, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are creditworthy major financial institutions deemed by management as competent and competitive market makers.

Based on hedging contracts outstanding on December 31, 2005, our cash flow hedge positions from natural gas and oil derivatives had an estimated net pre-tax liability of $36.0 million recorded as both current and non-current liabilities, as appropriate. We will reclassify this amount to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected market prices, the net amount of existing unrealized after-tax loss as of December 31, 2005 to be reclassified from accumulated other comprehensive loss to net income in the next twelve months would be $18.3 million. We anticipate that all original forecasted transactions will occur by the end of the originally specified time periods.

Capital Expenditures

Our capital expenditures were $347.4 million in 2005 and $347.5 million in 2004. The total for 2005 includes $28.2 million for acquisitions of properties and other real estate, $293.1 million for drilling, development, exploration and exploitation (including related gathering and facilities, but excluding exploratory dry holes, which are expensed under successful efforts accounting as exploration expense) of natural gas and oil properties, $23.6 million related to geologic and geophysical costs and exploratory dry holes, and $2.5 million for furniture, fixtures and equipment. The total for 2004 includes $152.8 million for acquisitions of properties, $156.4 million for drilling, development, exploration and exploitation of natural gas and oil properties, $36.2 million related to geologic and geophysical costs and exploratory dry holes, and $2.1 million for furniture, fixtures and equipment. In 2003, our capital expenditures were $186.3 million, including $49.0 million for the acquisition of properties, which includes $35.4 million for Powder River Basin properties acquired in March 2003, $129.4 million for drilling, development and exploration of natural gas and oil properties, $6.1 million for geologic and geophysical costs, and $1.8 million for furniture, fixtures and equipment. For the years ended December 31, 2005, 2004 and 2003, the Company received $13.8 million, $8.8 million and $11.9 million, respectively, of proceeds principally from the sale of interests in oil and gas properties, which are not deducted from the capital expenditures presented above.

Unevaluated properties increased $30.7 million to $168.3. million at December 31, 2005 from $137.6 million at December 31, 2004, principally from increases in uncompleted wells in progress resulting from increased development and exploratory drilling activity during the year ended December 31, 2005.

Our current capital budget, the amount and allocation of which is anticipated to change as we conduct activities throughout the year and which could decrease if costs rise and certain activities are curtailed, is

 

58


approximately $350 million for 2006. Of this $350 million capital budget, we plan to spend approximately $250 million for development drilling and facilities, $66 million on exploration drilling, $18 million for leasehold acquisitions, $11 million on geologic and geophysical costs, and $5 million for equipment and other costs. We are projecting that cash on hand, cash available from operating activities and borrowings from our credit facility, and proceeds from selling down a portion of our interests in certain properties will be sufficient to fund our 2006 capital budget. Certain of the activities contemplated by our 2006 capital budget as well as additional activities are subject to our entering into joint exploration agreements with industry partners, which would involve a sell down of our working interests in a number of exploration projects.

The amount and timing of capital expenditures is largely discretionary and within our control. If oil and natural gas 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 these planned 2006 capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and crews. Based upon current oil and natural gas price expectations for 2006, we anticipate that our operating cash flow and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for 2006. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities

Credit Facility. Our current bank line of credit has a face value of $200 million. This credit facility was entered into on February 4, 2004 and matures on February 4, 2007. The credit facility was amended on September 1, 2004. The credit facility bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate, or LIBOR, plus applicable margins ranging from 1.25% to 2.00% or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.50%. We pay commitment fees ranging from 0.375% to 0.50% of the unused borrowing base. The credit facility is secured by natural gas and oil properties representing at least 85% of the value of our proved reserves and the pledge of all of the stock of our subsidiaries. The borrowing base included a $25 million portion, referred to as the “Tranche B” portion, that allowed the borrowing base to be greater than the typical borrowing base that would have been computed based on proved natural gas and oil reserves. The Tranche B portion of the borrowing base terminated on November 30, 2005. At December 31, 2005, the total borrowing base remained at $200 million, which was redetermined based upon our June 30, 2005 reserve report. At December 31, 2004, there were no amounts outstanding under our revolving credit facility and, as of December 31, 2005, we had $86 million outstanding under the credit facility. For information concerning the effect of changes in interest rates on interest payments under this facility, see below, “—Quantitative and Qualitative Disclosure About Market Risk—Interest Rate Risks”.

The credit facility contains certain financial covenants. We have complied with all financial covenants for all periods.

We currently are negotiating an amendment to our credit facility, which we anticipate will increase the facility amount to $400 million, with an initial borrowing base of at least $280 million and will be for a period of five years. We expect to close the amendment by March 31, 2006.

 

59


Contractual Obligations. A summary of our contractual obligations as of and subsequent to December 31, 2005 is provided in the following table.

 

     Payments Due By Year (1)
     2006    2007    2008    2009    2010   

After

2010

   Total
     (in thousands)

Long-term debt (2)

   $ —      $ 86,000    $ —      $ —      $ —      $ —      $ 86,000

Other commitments for developing oil and gas properties

     19,920      22,265      2,345      —        —        —        44,530

Office and office equipment leases

     1,273      1,535      1,476      1,469      1,521      378      7,652

Firm transportation and processing agreements

     5,025      5,622      14,866      17,193      17,604      134,615      194,925
                                                

Total

   $ 26,218    $ 115,422    $ 18,687    $ 18,662    $ 19,125    $ 134,993    $ 333,107
                                                

(1) This table does not include (a) the liability for dismantlement, abandonment and restoration costs of oil and gas properties (effective with the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations , we recorded a separate liability for the fair value of this asset retirement obligation); (b) any liability associated with derivatives; and (c) any liability associated with commitment or other fees on our credit facility.
(2) Amount does not include interest expense because we cannot determine with accuracy the timing of future loan advances and the future interest rate to be charged under floating rate instruments.

The Company has entered into contracts which provide firm transportation capacity and processing rights on pipeline systems. The remaining terms on these contracts range from 1 to 13 years and require the Company to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by the Company.

In addition to the commitments above, the Company has commitments for the purchase of facilities equipment as of and subsequent to December 31, 2005 for a total of $39.0 million.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon the 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. Below, we provide expanded discussion of our more significant accounting policies, estimates and judgments. 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

 

60


capitalized when incurred, pending determination of whether the property has proved reserves. If an exploratory well is not assigned proved reserves, the costs of drilling the well are charged to exploration expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows pursuant to SFAS No. 19. The costs of development wells are capitalized whether productive or nonproductive. Gas and oil lease acquisition costs also are capitalized. If it is determined that these properties will not yield proved reserves, the related costs are expensed in the period in which that determination is made. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use.

Other exploration costs, including personnel costs, 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. Maintenance and repairs are charged to expense and renewals and betterments are capitalized to the appropriate property and equipment accounts.

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

We review our proved natural gas and oil properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our gas and oil properties and compare these future cash flows to the carrying amount of the gas and oil properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. In 2003, we recorded impairment expense of $1.8 million related to unevaluated properties located in southern Montana. In 2004, we recorded impairment expense of $0.5 million related to the evaluated costs of the Talon Field in Wyoming’s Wind River Basin. For the year ended December 31, 2005, we recorded impairment expense of $42.7 million related to the evaluated costs of the Talon, East Madden and Cooper Reservoir fields in Wyoming’s Wind River Basin.

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

The provision for depreciation, depletion and amortization (“DD&A”) 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. Taken into consideration in the calculation of DD&A are estimated future dismantlement, restoration and abandonment costs, net of estimated salvage values.

 

61


Oil and Gas Reserve Quantities

Our estimate of proved reserves is based on the quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. Ryder Scott Company reviews all our reserve estimates except our reserve estimates for the Powder River Basin, which are reviewed by Netherland, Sewell & Associates. A reserve report is prepared by us for all properties and these independent engineering firms review the entire report on a well-by-well basis.

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

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered. At year end 2005, we revised our proved reserves downward from the 2004 reserve report by approximately 24.7 Bcfe, offset by approximately 7.5 Bcfe of upward revisions due to commodity price increases. At year end 2004, we revised our proved reserves downward from the 2003 reserve report by approximately 32 Bcfe, offset by approximately 6 Bcfe of upward revisions due to commodity price increases. At year end 2003, we revised our proved reserves downward from the 2002 reserve report by approximately 41 Bcfe, offset by approximately 5 Bcfe of upward revisions due to commodity price increases.

Revenue Recognition

We record revenues from the sales of natural gas and oil when delivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred.

We may have an interest with other producers in certain properties, in which case we use the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of natural gas actually sold by the Company. In addition, we record revenue for our share of natural gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. We also reduce revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. Our remaining over-and under-produced gas balancing positions are considered in our proved reserves. Gas imbalances as of December 31, 2004 and 2005 were not significant.

Derivative Instruments and Hedging Activities

We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas and oil production by reducing our exposure to price fluctuations. For the year ended December 31, 2005, these transactions included swaps and cashless collars. We account for these activities pursuant to SFAS No. 133, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. SFAS No. 133 requires a company to formally document, at the inception of a hedge, the hedging relationship and the entity’s risk management objective and strategy for undertaking the hedge, including identification of the hedging

 

62


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 other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings.

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

As of December 31, 2005, the fair value of the derivative positions for our oil and gas collars for 2006 and 2007 production was $36.0 million. The deferred income tax effect on the fair value of derivatives at December 31, 2005 totaled $13.3 million, which is recorded in current and noncurrent deferred tax assets.

Income Taxes

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.

Stock-based Compensation

In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123(R), which revises SFAS No. 123, Accounting for Stock-Based Compensation , and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees . We early adopted the provisions of the new standard effective October 1, 2004. Prior to the adoption of SFAS No. 123(R), we used the intrinsic value method in accordance with APB Opinion No. 25 and the disclosure only provisions of SFAS No. 123.

Restrictions on the vesting of Management Stock and options granted under our 2002 Stock Option Plan (the “2002 Option Plan”) were put in place in connection with the initial capitalization of the Company, including Series A and B preferred stock issuances, and initially were designed to ensure that the relative ownership interests of Series B preferred stock investors were not diluted. Thus, the Management Stock and option grants under the 2002 Option Plan only vested if capital was raised from Series A and Series B investors (or upon other capital raising events). This is referred to as “dollar vesting” in the case of Management Stock and “equity vesting” in the case of options granted under the 2002 Option Plan. Dollar vested Management Stock and equity vested options are further subject to time vesting provisions. As of May 12, 2004, all Management Stock and options granted under the 2002 Option Plan were fully dollar and equity vested.

We recorded non-cash stock-based compensation of $3.6 million, $3.0 million, and $3.2 million in 2003, 2004 and 2005, respectively, for the Management Stock awards, option grants, option modifications and nonvested equity shares of common stock, in addition to Series B preferred stock purchases by employees at less than estimated fair value for financial reporting purposes. For awards granted after we were a public company (those granted subsequent to April 16, 2004, the date of which is defined by SFAS No. 123(R) as the date we became a public company as a result of making a filing with a regulatory agency in preparation for the sale of equity securities in a public market), we adopted SFAS No. 123(R) using the modified prospective application

 

63


effective October 1, 2004, whereby as of that date we began applying the provisions of SFAS No. 123(R) to new awards and to awards modified, repurchased, or cancelled after that date. We recognized share-based employee compensation cost based on the historical grant-date fair value as computed under SFAS No. 123 on that date for the portion of awards previously issued and for which the requisite service had not yet been rendered, and all deferred compensation related to those awards was eliminated against the appropriate equity accounts on the adoption date. For awards granted while we were a nonpublic company (those granted previous to April 16, 2004 as defined in SFAS No. 123(R)), we adopted SFAS No. 123(R) using the prospective transition method, under which we continue to account for the portion of the award outstanding at the date of application using the minimum value method described under SFAS No. 123.

Significant Factors, Assumptions, and Methodologies Used in Determining Fair Value.

The fair value of our common stock for stock-based awards granted during March 2002 through September 2003 was originally estimated on a contemporaneous basis by management as having a value of no greater than $0.41 per share for financial reporting purposes. Our computations during that period indicated that the corporate values of our assets, principally acquired properties, did not exceed the preferred stock preference amounts. For determining our fair value at December 31, 2003 and subsequent dates, we prepared valuation reports based on methodologies consistent with those that were proposed in the then-draft AICPA Practice Aid, “Valuation of Privately Held Company Equity Securities Issued as Compensation”, which subsequently was issued in final form in 2004. From December 2003 until the completion of our initial public offering in December 2004, we contemporaneously prepared at least one valuation report per quarter, which were provided to the board of directors and used by the compensation committee when approving stock option grants. Since our initial public offering, the fair value is determined using the previous day’s closing price on the New York Stock Exchange.

Prior to closing our initial public offering, determining the fair value of our stock required making complex and subjective judgments. For our retrospective valuations used to calculate non-cash deferred compensation and stock-based compensation expense reported in the financial statements, we used a probability-weighted expected return method. Under the probability-weighted expected return method, the value of the common stock was estimated based upon an analysis of values for us assuming various outcomes (initial public offering, merger or sale, liquidation, and remaining private) and the estimated probability of each outcome assuming that all preferred stock is converted into common stock. As we progressed through the initial public offering process, we placed increasing weight on an initial public offering or merger or sale within the probability-weighted expected return method.

Our valuation comparisons and estimates were inherently uncertain. The assumptions underlying the estimates were consistent with our business plan. The risks associated with achieving various outcomes related to our forecasts were assessed when selecting the weighting within the probability-weighted expected return method. If different probabilities had been used, the valuations would have been different. Furthermore, we did not use an unrelated valuation specialist. However, we believe that our management team has the appropriate expertise and experience to perform such analyses and we utilized methodologies acknowledged in the AICPA Practice Aid, but the valuation results we calculated may be different than what an unrelated valuation specialist may have calculated.

Acquisitions

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

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

 

64


There are various assumptions we made in determining the fair values of acquired assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the natural gas and oil properties acquired. To determine the fair values of these properties, we prepare estimates of natural gas and oil reserves. These estimates are based on work performed by our engineers and that of outside consultants. The fair value of reserves acquired in a business combination must be based on our estimates of future natural gas and oil prices and not the prices at the time of the acquisition. Our estimates of future prices are based on our own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics such as economic growth forecasts. They also are based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis. Forecasts of future prices from independent third parties are noted when we make our pricing estimates.

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

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

New Accounting Pronouncements

In June 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections , which replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements . Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. APB Opinion No. 20 previously required that most voluntary changes in an accounting principle be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. SFAS No. 154 now requires retrospective application of changes in an accounting principle to prior period financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The Statement is effective for fiscal years beginning after December 15, 2005. We do not expect the adoption of this statement will have a material impact on our financial statements.

On August 31, 2005, the FASB issued FSP FAS No. 123(R)-1, Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement 123(R) . This guidance applies to equity shares, as well as stock options, and requires that a freestanding financial instrument issued to an employee in exchange for past or future employee services that is subject to SFAS No. 123(R) shall continue to be subject to the recognition and measurement provisions of SFAS No. 123(R) throughout the life of the instrument, unless its terms are modified when the holder is no longer an employee. The Company adopted FSP FAS No. 123(R)-1 during the quarter ended September 30, 2005, and it did not have an impact on our financial statements.

On October 18, 2005, the FASB issued FSP FAS No. 123(R)-2, Practical Accommodation to the Application of Grant Date as Defined in SFAS No. 123(R ), which provides a reasonable approach in determining the grant date of an equity award. The Position clarifies that a mutual understanding of the grant terms shall be presumed to exist at the date the award is approved if (1) the grantee is not able to negotiate the terms of the award and (2) the terms of the grant are communicated to the grantee within a reasonable period of time. FSP FAS No. 123(R)- 2 was effective for our Company as of the fourth quarter of 2005. We have evaluated the provisions of FSP FAS No. 123(R)-2 and its adoption did not have an impact on our financial statements.

 

65


In October 2005, the FASB issued FSP FAS No. 13-1, Accounting for Rental Costs Incurred during a Construction Period , which is effective for reporting periods beginning after December 15, 2005. This Position requires that rental costs associated with ground or building operating leases that are incurred during a construction period be recognized as rental expense. We do not expect the adoption of FSP No. 13-1 to have an impact on our financial statements.

In February 2006, the FASB issued FSP FAS No. 123(R)-4, Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event . This FSP is effective for reporting periods beginning after February 3, 2006, with early application permitted, and it amends FAS No. 123(R) by stipulating that if a cash settlement feature can be exercised only upon the occurrence of a contingent event that is outside the employee’s control then it should be treated as an equity award until it becomes probable that the event will occur. As of December 31, 2005, the Company has accounted for all options in accordance with FSP FAS 123(R)-4.

Quantitative and Qualitative Disclosure About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our price swap and collars contracts in place in 2005, our annual income before income taxes, including hedge settlements, for the year ended December 31, 2005 would have decreased by approximately $1.7 million for each $0.10 decrease in natural gas prices and approximately $0.2 million for each $1.00 change in crude oil prices.

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

As of February 28, 2006, we had hedges in place for approximately 59,000 MMbtu and 29,000 MMbtu of natural gas production for 2006 and 2007, respectively, and approximately 750 Bbls and 600 Bbls of oil production for 2006, and 2007, respectively. These hedges are summarized in the table presented above under “—Cash Flow from Operating Activities”. Based on the pricing and contracts outstanding as of December 31, 2005, the estimated fair value of our hedge positions was a liability of $36.0 million owed by us to the counterparty.

 

66


Price Collars

Through price collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas production in 2006 and 2007. The weighted average minimum, or floor, price we will receive in 2006 is $4.82 per MMBtu for a Northwest Pipeline Corp. Rocky Mountain (“NORRM”) price and $7.54 and $5.25 in 2006 and 2007, respectively, per MMBtu for a Colorado Interstate Gas Rocky Mountain (“CIG”) price. The weighted average maximum, or ceiling, price we will receive in 2006 is $6.72 per MMBtu for a NORRM price and $13.68 and $10.22 in 1006 and 2007, respectively, per MMBtu for a CIG price. We also have fixed the minimum price we will receive on a portion of our oil production in 2006 and 2007, when the collars are settled, based on a weighted average floor price of $42.53 and $50.00 per Bbl for a West Texas Intermediate (“WTI”) price, respectively, and a weighted average maximum price of $52.26, and $78.15 WTI, respectively. The price collars also allow us to share in upward price movements up to the ceiling prices referenced in the contracts. The table presented above under “—Cash Flow from Operating Activities” provides the volumes and floor and ceiling prices associated with these various arrangements as of February 28, 2006.

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

Interest Rate Risks

At December 31, 2005, we had debt outstanding of $86 million, all of which bears interest at floating rates in accordance with our revolving credit facility. The average annual interest rate incurred on this debt for the year ended December 31, 2005 was 5.9%. A one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate for the year ended December 31, 2005 would result in an estimated $0.2 million increase in interest expense assuming a similar average debt level to the year ended December 31, 2005.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

 

Item 8. Financial Statements and Supplementary Data

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

 

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

Not applicable.

 

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures. Based on an evaluation carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, as of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer believe that our disclosure controls and procedures, as defined in Securities Exchange Act Rules 13a-15(d) and 15d-15(e), were, as of the end of the period covered by this report, to the best of their knowledge, effective.

 

67


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

 

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

 

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

 

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control—Integrated Framework, management concluded that its internal control over financial reporting was effective as of December 31, 2005.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche, LLP, an independent registered public accounting firm, as stated in their report which is included in this Annual Report on Form 10-K.

Changes in internal controls. There has been no change in our internal control over financial reporting during the fourth fiscal quarter of 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Bill Barrett Corporation

Denver, Colorado

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Bill Barrett Corporation and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

 

68


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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, 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, 2005 of the Company and our report dated March 1, 2006 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado

March 1, 2006

 

Item 9B. Other Information

Not applicable.

 

69


PART III

 

Item 10. Directors and Executive Officers of the Registrant

The following table sets forth information regarding our 10 executive officers, our directors and other key employees as of March 1, 2006.

 

Name

   Age   

Position

Fredrick J. Barrett

   45    Chief Executive Officer; President; and Director

William J. Barrett

   77    Director; Former Chief Executive Officer and Chairman

Thomas B. Tyree, Jr

   45    Chief Financial Officer

Robert W. Howard

   51   

Executive Vice President—Finance and

Investor Relations, and Treasurer

Dominic J. Bazile II

   47   

Senior Vice President—Operations and

Engineering

Francis B. Barron

   43   

Senior Vice President—General Counsel

and Corporate Secretary

Terry R. Barrett

   46    Senior Vice President—Exploration, Northern Division

Kurt M. Reinecke

   47    Senior Vice President—Exploration, Southern Division

Wilfred R. Roux

   48    Senior Vice President—Geophysics

Huntington T. Walker

   50    Senior Vice President—Land

Lynn Boone Henry

   45    Vice President—Reservoir Engineering

Duane J. Zavadil

   46    Vice President—Government and Regulatory Affairs

Kevin Finnegan

   46    Vice President—Information Systems

Henry Cornell

   49    Director

James M. Fitzgibbons

   71    Director

Jeffrey A. Harris

   50    Director

Roger L. Jarvis

   52    Director

Philippe S. E. Schreiber

   65    Director

Randy Stein

   52    Director

Michael E. Wiley

   55    Director

Each of William J. Barrett and Fredrick J. Barrett may be deemed to be a promoter and founder of the Company due to his initiative in organizing the Company. William J. Barrett is the father of Fredrick J. Barrett and Terry R. Barrett.

Executive Officers and Other Key Employees

Fredrick J. Barrett . Mr. Barrett has served as our President and a Director since our inception in January 2002 and as our Chief Executive Officer since March 1, 2006. Mr. Barrett served as our Chief Operating Officer from June 2005 through February 2006. Mr. Barrett served as senior geologist of Barrett Resources and its successor in the Rocky Mountain Region from 1997 through 2001, and as geologist from 1989 to 1996. From 1987 to 1989, Mr. Barrett was a partner in Terred Oil Company, a private oil and gas partnership providing geologic services for the Rocky Mountain Region. From 1983 to 1987, Mr. Barrett worked as a project and field geologist for Barrett Resources.

William J. Barrett . Mr. Barrett has served as a Director since our inception in January 2002. Mr. Barrett served as our Chairman of the Board and Chief Executive Officer from inception through February 2006. Mr. Barrett founded Barrett Resources Corporation (“Barrett Resources”), which was acquired in August 2001

 

70


by The Williams Companies. Mr. Barrett served as the Chief Executive Officer of Barrett Resources from December 1983 until November 18, 1999, except for the period from July 1, 1997 through March 23, 1998. He also served Barrett Resources as Chairman of the Board from September 1994 until March 2000, and as President from December 1983 until September 1994. From March 2000 until November 2001, Mr. Barrett was retired. From November 2001 until the formation of the Company in January 2002, Mr. Barrett consulted on the establishment of the Company and its planned activities. Prior to 1983, Mr. Barrett held various positions with several other oil and gas companies. Mr. Barrett has informed the Company that he intends to retire as an employee and director on May 17, 2006.

Thomas B. Tyree, Jr. Mr. Tyree has served as our Chief Financial Officer since February 2003. From August 1989 until January 2003, Mr. Tyree was employed by Goldman, Sachs & Co., most recently as a Managing Director in the Investment Banking Division, working with oil and gas companies. From 1983 to 1987, Mr. Tyree was employed by Bankers Trust Company as an Associate in corporate finance.

Robert W. Howard . Mr. Howard has served as our Executive Vice President—Finance and Investor Relations since January 2004 and as our Treasurer since our inception in January 2002. From February 2003 until January 2004, Mr. Howard served as our Executive Vice President—Finance and Accounting. From January 2002 until February 2003, Mr. Howard served as our Chief Financial Officer; from our inception in January 2002 until February 2004, Mr. Howard served as our Secretary; and from January 2002 until March 2002 he served as a Director of the Company. From August 2001 until December 2001, Mr. Howard served as Vice President—Finance and Administration and a director of AEC Oil & Gas (USA) Inc., an indirect subsidiary of Alberta Energy Company, Ltd., an oil and gas exploration and development company that subsequently was acquired by EnCana Corporation. Mr. Howard served as Senior Vice President—Investor Relations and Corporate Development of Barrett Resources from February 1999 until August 2001. Mr. Howard previously served as Barrett Resource’s Senior Vice President beginning in March 1992 and as Treasurer beginning in March 1986.

Dominic J. Bazile II . Mr. Bazile has served as Senior Vice President—Operations and Engineering since May 2003 and previously served as our Vice President of Operations beginning in February 2002. Prior to joining us, Mr. Bazile was employed by Barrett Resources and its successor from July 1995 until January 2002, including serving as Drilling Manager.

Francis B. Barron . Mr. Barron has served as Senior Vice President—General Counsel and Secretary since March 2004. Mr. Barron was a partner at the Denver, Colorado office of Patton Boggs LLP from February 1999 until February 2004, practicing corporate, securities and general business law. Prior to February 1999, Mr. Barron was a partner of and served as an associate at Bearman Talesnick & Clowdus Professional Corporation, a Denver law firm. Mr. Barron’s clients included publicly-traded oil and gas companies.

Terry R. Barrett . Mr. Barrett has served as Senior Vice President—Exploration, Northern Division since March 1, 2006 and previously served as Vice President—Exploration, Northern Division from our inception in January 2002 through February 2006. From 1989 to 2001, Mr. Barrett served as Senior Geologist or Project Geologist in numerous Rocky Mountain basins for Barrett Resources Corporation, prior to the acquisition of that company by The Williams Companies. He served as Senior Geologist for approximately five months with The Williams Companies from August through December 2001. From 1987 to 1989, Mr. Barrett was a general partner in Terred Oil Company, a private oil and gas partnership providing geologic services for the Rocky Mountain Region. From 1983 to 1987, Mr. Barrett worked as a contract project and field geologist for Barrett Resources.

Kurt M. Reinecke . Mr. Reinecke has served as Senior Vice President—Exploration, Southern Division since March 1, 2006 and previously served as Vice President—Exploration, Southern Division from our inception in January 2002 through February 2006. From 1985 to 2001, Mr. Reinecke served as a Senior Exploration Geologist or Operations Geologist in numerous Rocky Mountain and Mid-Continent basins for Barrett Resources Corporation, prior to the acquisition of that company by The Williams Companies.

 

71


Wilfred R. (Roy) Roux . Mr. Roux has served as Senior Vice President—Geophysics since March 1, 2006 and previously served as Vice President—Geophysics from February 2002 through February 2006. Prior to joining us, Mr. Roux was employed by Barrett Resources and The Williams Companies from July 1995 until January 2002, including as Senior Geoscientist and Senior Geophysicist. Mr. Roux’s responsibilities with us include overseeing our implementation and use of technology and geophysical data.

Huntington T. Walker . Mr. Walker has served as Senior Vice President—Land since March 1, 2006 and previously served as Vice President—Land from our inception in January 2002 through February 2006. From June 1981 through December 2001, Mr. Walker was self employed in the oil and gas industry as an independent landman performing consulting work for various clients, including Barrett Resources, and investing in oil and gas properties for his own account. From May 1979 through June 1981, Mr. Walker was employed by Hunt Energy Corporation in its Denver office.

Lynn Boone Henry . Ms. Henry has served as Vice President—Reservoir Engineering since January 2004. From October 2003 until January 2004, Ms. Henry served as our Reservoir Engineering Manager. From January 2003 until October 2003, Ms. Henry served as the Senior Reservoir Engineer for our Wind River Basin team. From January 2002 until joining the Company in January 2003, Ms. Henry was an independent consultant on reservoir engineering projects for various Rocky Mountain exploration and production companies. From 1998 until 2002, Ms. Henry served as a Reserves Manager and Project Manager for Cody Energy, LLC in Denver.

Duane J. Zavadil . Mr. Zavadil has served as Vice President—Government and Regulatory Affairs since January 2005. From the time that he joined the Company in July 2002 until January 2005, Mr. Zavadil served as our Government and Regulatory Affairs Manager. From 1994 until July 2002, Mr. Zavadil served as the Environmental, Health and Safety Manager with Barrett Resources Corporation and its successor, The Williams Companies. Mr. Zavadil was a consultant providing environmental and regulatory services to the oil and gas industry from 1984 through 1994.

Kevin Finnegan . Mr. Finnegan has served as our Vice President—Information Systems since March 1, 2006. He previously served as our Director of Information Systems from July 2002 through February 2006. Mr. Finnegan served as IT Project Manager and IT Network Manager for AT&T Wireless Services Corporation from September 1996 until July 2002, and previously served as the IT Network and Telecommunications Administrator for Barrett Resources Corporation and as Electronic System—Test Engineer and Technician for Martin Marietta Corporation.

Outside Directors

Henry Cornell . Mr. Cornell has been a director of the Company since 2002. Mr. Cornell is a Managing Director in the Principal Investment Area of Goldman, Sachs & Co., which he joined in 1984. He is a member of the Investment Committee of the Principal Investment Area of Goldman, Sachs & Co. Mr. Cornell also serves on the Board of Directors of Ping An Insurance Company of China and National Golf Properties LLC.

James M. Fitzgibbons . Mr. Fitzgibbons has been a director since July 2004. Mr. Fitzgibbons also has served as a Director/Trustee of Dreyfus Laurel Funds, a series of mutual funds, since 1994. From January 1998 until 2001, Mr. Fitzgibbons served as Chairman of the Board of Davidson Cotton Company. From January 1994 until it was sold in August 2001, Mr. Fitzgibbons served as a director of Barrett Resources, for which he also served as a director from July 1987 until October 1992. From October 1990 through December 1997, Mr. Fitzgibbons was Chairman of the Board and Chief Executive Officer of Fieldcrest Cannon, Inc.

Jeffrey A. Harris . Mr. Harris has been a Director of the Company since 2002. Mr. Harris has served since 1998 as a Managing Director of Warburg Pincus LLC, which he joined in 1983. Mr. Harris’ responsibilities include involvement in investments in energy, technology and other industries. Mr. Harris is a director of Knoll, Inc., Nuance Communications, Inc. as well as several private companies.

 

72


Roger L. Jarvis . Mr. Jarvis has been a Director of the Company since 2002. Mr. Jarvis served as President, Chief Executive Officer and Director of Spinnaker Exploration Company from 1996 until December 2005 and as Chairman of the Board of Spinnaker from 1998 until December 2005, when Spinnaker was acquired by Norsk Hydro ASA. From 1986 to 1994, Mr. Jarvis served in various capacities with King Ranch Inc. and its subsidiary, King Ranch Oil and Gas, Inc., including Chief Executive Officer, President and Director of King Ranch Inc. and Chief Executive Officer and President of King Ranch Oil and Gas, Inc., where he expanded its activities in the Gulf of Mexico. Mr. Jarvis has served as a director of National-Oilwell Varco, Inc. since 2002.

Philippe S.E. Schreiber . Mr. Schreiber has been a Director of the Company since February 2002. Mr. Schreiber is an independent lawyer and business consultant. Mr. Schreiber served as a director of Barrett Resources from 1985 until 2001. From August 1985 through December 1998, he was a partner of, or of counsel to, the law firm of Walter, Conston, Alexander & Green, P.C. in New York, New York. Since 1991, Mr. Schreiber has served as a director of the United States principal affiliate of The Mayflower Corporation plc (in Administration), which was a publicly-listed company in the United Kingdom until it filed for creditor protection in April 2004. The United States affiliated companies of The Mayflower Corporation plc (in Administration) are not subject to any bankruptcy or creditor protection proceedings and Mr. Schreiber has not served as an officer or director of The Mayflower Corporation plc (in Administration). Mr. Schreiber also has served since February 2005 as a director of Capital Energy Limited, an English company that intends to invest in U.S. oil and gas prospects, and since January 2006 as a director and officer of its CAP Energy USA, Inc. subsidiary. Mr. Schreiber also serves as a director of other private companies.

Randy Stein . Mr. Stein has served as a director and the chair of our audit committee since July 2004. Mr. Stein is a self-employed tax and business consultant. From July 2000 until its sale in June 2004, Mr. Stein was a director of Westport Resources Corporation, a Denver based oil and natural gas exploration and development company, where Mr. Stein served as the chair of the audit committee. Mr. Stein served from 2001 through 2005 as a director of Koala Corporation, a Denver based public company engaged in the design, production and marketing of family convenience products, where he served on the audit and compensation committees. Mr. Stein has served as a director and co-chairman of the audit committee of Denbury Resources Inc., a Dallas based, publicly traded, independent oil and gas company, since January 2005. He also was a principal at PricewaterhouseCoopers LLP, formerly Coopers & Lybrand LLP, from November 1986 to June 30, 2000.

Michael E. Wiley . Mr. Wiley has served as a director since January 2005. Mr. Wiley served as Chairman of the Board and Chief Executive Officer of Baker Hughes Incorporated, an oilfield services company, from August 2000 until October 2004. He also served as President of Baker Hughes from August 2000 to February 2004. Mr. Wiley was President and Chief Operating Officer of Atlantic Richfield Company, an integrated energy company, from 1998 through May 2000. Prior to 1998, he served as Chairman, President and Chief Executive Officer of Vastar Resources, Inc., an independent oil and gas company. Mr. Wiley served as a director of Spinnaker Exploration Company from 2001 through 2005. Mr. Wiley is a director of Tesoro Corporation and Post Oak Bank, NA, a trustee of the University of Tulsa and a member of the National Petroleum Council. He also serves on the Advisory Board of Riverstone Holdings LLC.

Fredrick J. Barrett, our Chief Executive Officer and President, leads our officers in the day-to-day management of the Company. Fredrick J. Barrett, Thomas B. Tyree, Jr., our Chief Financial Officer, and Francis B. Barron, Senior Vice President—General Counsel, meet formally on a weekly basis and informally with other officers on a daily basis. All 12 officers of the Company meet formally on a weekly basis. Interaction among the officers is intense, candid and highly cooperative, reflecting a team-oriented management philosophy that defines the culture of our company. All of our executive officers successfully worked together, as officers and advisors, for many years with Barrett Resources and now with Bill Barrett Corporation.

In addition to overall management, Fredrick J. Barrett manages the operations and exploration side of our business, which includes seven dedicated, multi-functional basin teams, as well as our Geophysics and

 

73


Information Technology teams. Each of our basin teams — Wind River, Uinta, Piceance, Powder River, Williston, Tri-State and Paradox — is led by a senior manager with extensive experience in his respective region of operations. Our basin team leaders manage their regions as separate business units, with responsibility for exploration, production, land, acquisitions, capital budgeting, and other functions relevant to their respective regions, including the continuing generation of new geologic play concepts. Each team works very closely with our Operations Department. Our basin teams are directly accountable for the performance of their respective basins, which is measured based on production, cash flow, cost structure, exploration and development success and other factors.

Our executive officers and board of directors view our employees as our greatest asset, and recognize the importance of identifying talented individuals and preparing them for senior management positions. An executive development effort has been implemented, which provides increasing levels of responsibility and training for those employees who could ultimately succeed to senior management positions within our company. Several individuals have been identified and are being developed as candidates for various of our executive positions. In addition to these internal candidates, the board and management, as a matter of course, monitor other individuals within as well as outside of our company.

Board of Directors

We currently have nine directors. Our certificate of incorporation and bylaws provide for a classified board of directors consisting of three classes of directors, each serving staggered three-year terms. As a result, stockholders will elect a portion of our board of directors each year. Class I directors’ terms will expire at the annual meeting of stockholders to be held in 2008, Class II directors’ terms will expire at the annual meeting of stockholders to be held in 2006 and Class III directors’ terms will expire at the annual meeting of stockholders to be held in 2007. The Class I directors are Messrs. Fredrick Barrett, Cornell and Wiley, the Class II directors are Messrs. Fitzgibbons, Harris and Stein, and the Class III directors are Messrs. William Barrett, Jarvis and Schreiber. At each annual meeting of stockholders, the successors to directors whose terms will then expire will be elected to serve from the time of election until the third annual meeting following election. The division of our board of directors into three classes with staggered terms may delay or prevent a change of our management or a change in control.

In addition, our bylaws provide that the authorized number of directors, which shall constitute the entire board of directors, may be changed by a resolution duly adopted by the board of directors. Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the total number of directors. Vacancies and newly created directorships may be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum.

Committees of the Board

Our board of directors currently has an audit committee, a compensation committee and a nominating and corporate governance committee. In February 2006, all the members of these committees were determined by our board of directors to be “independent” under the standards of the New York Stock Exchange and SEC regulations. In making this determination, the board of directors considered the directors’ relationships with the Company, including commercial relationships with and stock ownership by entities affiliated with the directors, and the specific provisions of the NYSE corporate governance standards that would make a director not independent.

Audit Committee . As of March 1, 2006, our audit committee consisted of Messrs. Stein, Fitzgibbons and Schreiber. The board of directors has determined that Mr. Stein is an “audit committee financial expert”, as defined under the rules of the SEC. As required by the standards of the New York Stock Exchange, the audit committee consists solely of independent directors. Our audit committee operates pursuant to a formal written

 

74


charter. This committee oversees, reviews, acts on and reports to our board of directors on various auditing and accounting matters including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants, our accounting practices, and the selection and performance of personnel performing our internal audit function. In addition, the audit committee oversees our compliance programs relating to legal and regulatory requirements.

Compensation Committee . As of March 1, 2006, our compensation committee consisted of Messrs. Fitzgibbons, Harris, Jarvis, and Schreiber. As required by the standards of the New York Stock Exchange, the compensation committee consists solely of independent directors. Our compensation committee operates pursuant to a formal written charter. This committee establishes salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee also administers our incentive compensation and benefit plans.

Nominating and Corporate Governance Committee . As of March 1, 2006, our nominating and corporate governance committee consisted of Messrs. Cornell, Harris, and Jarvis. As required by the standards of the New York Stock Exchange, this committee consists solely of independent directors. Our nominating and corporate governance committee operates pursuant to a formal written charter. This committee identifies, evaluates and recommends qualified nominees to serve on our board of directors, develops and oversees our internal corporate governance processes and maintains a management succession plan.

Compensation Committee Interlocks and Insider Participation

The compensation committee consists of Messrs. Fitzgibbons, Harris, Jarvis and Schreiber, all of whom are non-employee directors. None of these individuals has ever been an officer or employee for our company. In addition, none of our executive officers serves as a member of a board of directors or compensation committee of any entity that has one or more executive officers who serve on our board or on our compensation committee.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), requires our directors and executive officers, and persons who own more than ten percent of a registered class of our equity securities, to file with the Commission and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of common shares and other equity securities of the Corporation.

To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of our officers, directors and greater than 10% shareholders under Section 16(a) were satisfied during the year ended December 31, 2005 except one report on Form 4 reporting a sale in November 2005 by Huntington T. Walker, a Senior Vice President, was filed two days late due to the failure of Mr. Walker’s brokerage firm to timely notify the Company of the sale.

Code of Ethics

We maintain a Code of Ethics and Business Conduct, which includes our code of ethics for senior financial management. The Code of Ethics and Business Conduct is posted on our website, www.billbarrettcorp.com . See “Item 1. Business and Properties—Website and Code of Business Conduct and Ethics”.

 

75


Item 11. Executive Compensation

Summary Compensation Table

The following table sets forth the compensation of our chief executive officer and each of our other four most highly compensated executive officers serving as of December 31, 2005 (we refer to these five individuals, collectively, as the named executive officers) for the fiscal years ended December 31, 2005, 2004 and 2003.

 

          Annual Compensation    

Long-Term
Compensation
Awards Securities

Underlying
Options/SARs (#)(1)

     

Name and

Principal Position

   Year    Salary    Bonus     Other Annual
Compensation
      All Other
Compensation(2)

Fredrick J. Barrett

Chief Executive Officer and President (3)(4)

   2005
2004
2003
   $
 
 
226,857
199,905
154,700
   $
 
 
165,000
125,000
75,000
 
 
 
  $
 
 
—  
—  
—  
 
 
 
  —  
109,641
—  
 
 
 
  $
 
 
7,669
6,218
5,768

Thomas B. Tyree, Jr.

Chief Financial Officer

   2005
2004
2003
   $
 
 
226,857
210,005
183,333
   $
 
 
165,000
125,000
75,000
 
 
 
  $
 
 
—  
—  
510,288
 
 
(5)
  —  
149,402
246,896
 
 
 
  $
 
 
7,699
6,575
6,000

Francis B. Barron

Senior Vice President — General Counsel; and Secretary

   2005
2004
2003
   $
 
 
199,664
174,762
—  
   $
 
 
120,000
115,000
—  
 
(6)
 
  $
 

 
—  
24,160

—  
 
(7)

 
  —  
50,762

—  
 
(8)

 
  $
 
 
7,413
5,748
—  

William J. Barrett

Former Chief Executive Officer (4)

   2005
2004
2003
   $
 
 
293,395
263,755
237,500
   $
 
 
300,000
267,500
100,000
 
 
 
  $
 
 
—  
—  
—  
 
 
 
  —  
273,954
—  
 
 
 
  $
 

 
—  
—  

—  

J. Frank Keller

Former Executive Vice President and Chief Operating Officer(3)

   2005
2004
2003
   $
 
 
215,626
216,255
201,250
   $
 
 
125,000
125,000
75,000
 
 
 
  $
 
 
—  
—  
—  
 
 
 
  —  
149,402
—  
 
 
 
  $
 
 
8,400
8,597
8,870

(1) The options shown in the table as granted for 2004 include options that were exchanged when we allowed the holders of all outstanding options with an exercise price of $30.28 per share (the “Tranche A Options”), including the named executive officers, to amend those options to provide for an exercise price equal to the price to the public in our initial public offering of $25.00 in December 2004, to decrease the number of shares subject to the options and to shorten the term to December 9, 2011. Each Tranche A Option previously issued to purchase one share of common stock became an option to purchase 0.926 shares. The Tranche A Options initially were issued to Mr. Tyree in 2003, Mr. Barron in 2004 and the other named executive officers in 2002.
(2) Consists of 401(k) plan matching contributions.
(3) Mr. Keller served as Chief Operating Officer until Mr. Fredrick J. Barrett was elected to that position effective in June 2005. Mr. Keller retired as Executive Vice President on February 1, 2006.
(4) Mr. William J. Barrett served as Chief Executive Officer and Chairman of the Board until Mr. Fredrick J. Barrett was elected to those positions effective March 1, 2006. Mr. William J. Barrett informed the Company that he intends to retire as an employee and director on May 17, 2006.
(5) Consists of $17,648, which was the difference between the purchase price for shares of common stock purchased by Mr. Tyree and the fair market value of those shares, $300,000 for relocation expenses (including travel expenses to search for a house in Colorado, moving expenses, brokerage commissions, real estate transfer taxes and legal fees related to the sale of Mr. Tyree’s residence, and the cost of temporary housing), $15,000 for legal expenses relating to the commencement of employment (including for the negotiation of Mr. Tyree’s terms of employment with us and the terms of his separation from his previous employer), and $177,640 for the reimbursement of income taxes related to expense payments.

 

76


(6) Includes $30,000 paid in the form of a restricted stock grant of 917 shares of common stock at $32.70 per share pursuant to our 2004 Stock Incentive Plan. These shares vest 25% on each of March 9, 2006, 2007, 2008 and 2009 if Mr. Barron continues as an employee on those dates.
(7) Consists of the difference between the purchase price for Series B preferred stock purchased by Mr. Barron and the fair market value of those shares.
(8) 7,514 of these options were Tranche A Options and were granted on March 4, 2004. These options were exchanged for 6,958 options as described in Note (1) above. Both the initial grant and the exchanged options are included in the table.

Stock Options Granted During 2005

During 2005, the Company did not grant stock options to the named executive officers. In December 2005, the Compensation Committee approved the acceleration of the vesting of options held by Mr. Barrett and Mr. Keller upon their respective retirements in 2006.

Aggregated Option Exercises During 2005

and Option Values at December 31, 2005

The following table sets forth certain information regarding options that the named executive officers exercised during 2005 and the options that those persons held at December 31, 2005.

 

     Shares
Acquired on
Exercise (#)
       

Number of Securities
Underlying Unexercised
Options/SARs at

FY-End (#)

   Value of Unexercised
In-the-Money Options/SARs
at FY-End ($)

Name

      Value Realized
($)
   Exercisable    Unexercisable    Exercisable    Unexercisable

Fredrick J. Barrett

   —        —      62,626    51,845    $ 911,698    $ 765,017

Thomas B. Tyree, Jr.

   27,910      856,837    72,141    133,081    $ 981,839    $ 3,183,790

Francis B. Barron

   —        —      12,520    30,172    $ 246,728    $ 566,162

William J. Barrett

   172,858    $ 7,225,222    0    118,486    $ 0    $ 1,826,396

J. Frank Keller

   64,608      2,657,084    3,397    90,414    $ 46,233    $ 1,341,406

Acceleration of Vesting of Options for Retiring Officers

In December 2005, the Compensation Committee approved the acceleration of the vesting of all outstanding options held by Mr. William J. Barrett and Mr. Keller upon their respective retirements in 2006.

Change in Control Severance Protection Agreements

In July 2004, our board of directors approved severance agreements for the named executive officers and other employees in the event that there is both a change in control (as defined in the agreements) of the Company and the person’s employment is terminated within one year after the change in control other than a termination for cause or without good reason, as defined in the agreement. The named executive officers are entitled to receive a severance payment equal to two times their highest cash compensation, including bonus, during any consecutive 12 month period in the three years preceding the termination. This amount is payable in a lump sum. Each named executive officer also is entitled to accelerated vesting of all unvested stock options and accelerated lapsing of all restrictions on restricted stock grants upon the occurrence of the change in control, regardless of whether the named executive officer is terminated. Each named executive officer also will receive continuation of all life, disability, accident and health insurance for 36 months after termination, or reasonably equivalent benefits, as well as outplacement services to assist in obtaining new employment. Each agreement automatically expires if a change in control has not occurred within a 10-year period, and may be renewed for successive one-year periods by written agreement of the parties.

 

77


Indemnification Agreements

We have entered into an indemnification agreement with each of our directors and executive officers. These agreements require us, among other things, to indemnify our directors and officers against certain liabilities that may arise by reason of their status or service as directors or officers, to advance their expenses incurred as a result of a proceeding as to which they may be indemnified, and to cover them under any directors’ and officers’ liability insurance policy we choose, in our discretion, to maintain. These indemnification agreements are intended to provide indemnification rights to the fullest extent permitted under applicable indemnification rights statutes in the State of Delaware and will be in addition to any other rights that the indemnitee may have under our certificate of incorporation, bylaws and applicable law.

Compensation Committee Interlocks and Insider Participation

The compensation committee consists of Messrs. Fitzgibbons, Harris, Jarvis and Schreiber, all of whom are non-employee directors. None of these individuals has ever been an officer or employee for our company. In addition, none of our executive officers serve as a member of a board of directors or compensation committee of any entity that has one or more executive officers who serve on our board or on our compensation committee.

Director Compensation

Our directors who are not employees of the Company and who were not previously nominated by the investors in our Series B preferred stock (“Outside Directors”) receive an annual retainer of $25,000 and a meeting attendance fee of $1,000 for each board and committee meeting attended. The chair of the audit committee receives an additional annual retainer of $15,000 and a meeting attendance fee of $1,000 for substantive meetings with management and auditors, the chair of the compensation committee receives an additional annual retainer of $10,000, and the chairs of other committees receive an additional annual retainer of $5,000. In July 2004, our compensation committee determined that the Outside Directors should receive equity compensation under our 2004 Stock Incentive Plan with a value at the date of award or grant of approximately $80,000 per year in the form of stock options, restricted stock and/or other equity grants. In July 2004, the Compensation Committee determined that the first grant to Outside Directors would be in the form of options to purchase 10,000 shares of common stock effective upon the completion of our initial public offering with an exercise price equal to the price to the public in the initial public offering. The number of shares underlying the options was based on the estimated initial public offering price at that time. When the initial public offering price, and therefore the Black-Scholes value of the 10,000 options, increased, the Committee did not reduce the number of options granted upon the completion of the initial public offering. When Mr. Wiley was elected as an Outside Director in January 2005, the Compensation Committee approved granting him options to purchase 10,000 shares of common stock at an exercise price equal to the closing sales price on the New York Stock Exchange on the last trading day prior to his election in accordance with the 2004 Stock Incentive Plan. All these options vest 25% on each of the first four anniversaries of the date of grant, and terminate on the seventh anniversary of the date of grant. All directors are reimbursed for all reasonable out-of-pocket expenses incurred in attending meetings of the board of directors. In December 2005, the compensation committee determined grants of equity compensation to new Outside Directors as well as the equity portion of compensation paid to Outside Directors each year would be in the form of options to purchase 10,000 shares of common stock with an exercise price equal to the fair market value of the common stock on the day before the election of the new Outside Director or the date of grant.

 

78


During 2005, the Outside Directors received the following compensation:

 

Name

  

Annual Retainer
for Serving as a

Director

  

Annual Retainer
for Serving as

Committee Chair

  

Meeting

Attendance

Fees

  

Total

Cash

Compensation

Henry Cornell

     —        —        —        —  

Jeffrey A. Harris

     —        —        —        —  

Roger Jarvis

   $ 25,000      —      $ 15,000    $ 40,000

James M. Fitzgibbons

   $ 25,000      —      $ 20,000    $ 45,000

Philippe S.E. Schreiber

   $ 25,000      —      $ 20,000    $ 45,000

Randy Stein

   $ 25,000    $ 15,000    $ 14,000    $ 54,000

Michael E. Wiley

   $ 25,000    $ 2,292    $ 11,000    $ 38,292

 

Item 12. Security Ownership of Certain Beneficial Owners and Management

The following table and footnotes show information as of February 28, 2006, except as otherwise noted, regarding the beneficial ownership of our common stock by:

 

    each stockholder known by us to be the beneficial owner of more than 5% of the outstanding shares of our common stock;

 

    each member of our board of directors and each of our named executive officers; and

 

    all members of our board of directors and our named executive officers as a group.

Unless otherwise indicated in the footnotes to this table and subject to community property laws where applicable, we believe that each of the stockholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned. Unless otherwise indicated, the address for each person set forth in the table is c/o Bill Barrett Corporation, 1099 18th Street, Suite 2300, Denver, Colorado 80202.

 

79


In calculating the number of shares beneficially owned by each person and the percentage owned by each person, we assumed that all shares issuable upon exercise of options on or prior to April 30, 2006 are exercised by that person. The total number of shares outstanding used in calculating the percentage owned assumes no exercise of options held by other persons.

 

Name of Beneficial Owner

 

Number of Common Shares

Beneficially Owned

   

Percentage of
Outstanding Common
Shares

Beneficially Owned (1)

 

5% Stockholders:

   

Warburg Pincus Private Equity VIII, L.P.

    466 Lexington Avenue

    New York, NY 10017

  10,081,278 (2)   23.0 %

The Goldman Sachs Group, Inc.

    85 Broad Street

    New York, NY 10004

  2,768,665 (3)   6.3 %

State Farm Mutual Automobile Insurance Co.

    One State Farm Plaza

    Bloomington, IL 61710

  3,241,567 (4)   7.4 %

T. Rowe Price Associates, Inc.

    100 East Pratt Street

    Baltimore, MD 21202

  4,351,997 (5)   9.9 %

Executive Officers and Directors:

   

Fredrick J. Barrett

  259,267 (6)   *  

Thomas B. Tyree, Jr.

  368,575 (7)   *  

Francis B. Barron

  41,109 (8)   *  

William J. Barrett

  1,098,835 (9)   2.5 %

J. Frank Keller

  434,232 (10)   1.0 %

Philippe S.E. Schreiber

  51,826 (11)   *  

Henry Cornell

  2,768,665 (3)   6.3 %

Jeffrey A. Harris

  10,081,278 (2)   23.0 %

James M. Fitzgibbons

  26,085 (12)   *  

Roger Jarvis

  30,741 (13)   *  

Randy Stein

  3,000 (12)   *  

Michael E. Wiley

  4,500 (12)   *  

All executive officers and directors as a group (21 persons)

  16,292,245
(7

    (11
        (14
(2)(3)(4)(5)(6)
)(8)(9)(10)

)(12)(13)
)
  36.5 %

* Less than 1%
(1) Based on an aggregate of 43,837,395 shares of common stock issued and outstanding as of February 28, 2006.
(2) Consists of shares directly owned by Warburg Pincus Private Equity VIII, L.P., including three related limited partnerships. Warburg Pincus & Co. serves as the sole general partner of Warburg Pincus Private Equity VIII, L.P. and that limited partnership is managed by Warburg Pincus LLC. Our director, Jeffrey A. Harris, is a general partner of Warburg Pincus & Co. and a member and managing director of Warburg Pincus LLC. All shares indicated owned by Mr. Harris are included because of his affiliation with the Warburg Pincus entities. Mr. Harris disclaims beneficial ownership of all the shares of common stock held by Warburg Pincus Private Equity VIII, L.P. and its affiliates. The 10,081,278 shares are included three times in the table under the beneficial ownership of each of Mr. Harris, Warburg Pincus Private Equity VIII, L.P. and all executive officers and directors as a group.

 

80


(3) The Goldman Sachs Group, Inc., which we refer to as GS Group, and certain affiliates, may be deemed to own beneficially and indirectly in the aggregate 2,768,665 shares of common stock which are owned directly or indirectly by investment partnerships, of which affiliates of Goldman Sachs and GS Group are the general partner or managing general partner. We refer to these investment partnerships as the GS Limited Partnerships. Goldman Sachs is the investment manager of certain of the GS Limited Partnerships. Our director Henry Cornell is a managing director of Goldman Sachs. Mr. Cornell, Goldman Sachs and GS Group each disclaims beneficial ownership of the shares owned directly or indirectly by the GS Limited Partnerships, except to the extent of their pecuniary interest therein, if any. The shares are included three times in the table under the beneficial ownership of each of Mr. Cornell, GS Group and all executive officers and directors as a group.
(4) Based on information included in a Schedule 13G filed with the Securities Exchange Commission (“SEC”) on February 2, 2006.
(5) Based on information included in a Schedule 13G filed with the SEC on February 10, 2006.
(6) Includes 62,626 common shares issuable upon exercise of options that have vested or that will vest on or before April 30, 2006 and 29.43 shares in Mr. Barrett’s Company 401(k) account.
(7) Includes 119,931 common shares issuable upon exercise of options that have vested or that will vest on or before April 30, 2006 and 29.43 shares in Mr. Tyree’s Company 401(k) account.
(8) Includes 16,327 common shares issuable upon exercise of options that have vested or that will vest on or before April 30, 2006, 878 shares held by Mr. Barron as custodian for his minor children, 229 restricted shares that vest on March 9, 2006, and 25.77 shares in Mr. Barron’s Company 401(k) account.
(9) Includes 118,486 common shares issuable upon exercise of options held by Mr. Barrett, the vesting of which will be accelerated upon Mr. Barrett’s retirement. Includes 384,676 shares owned by a limited liability limited partnership in which Mr. Barrett is the general partner.
(10) Includes 90,414 common shares issuable upon exercise of options held by Mr. Keller, all of which have vested, and 76.37 shares in Mr. Keller’s Company 401(k) account.
(11) Includes 24,301 common shares issuable upon exercise of options that have vested or that will vest on or before April 30, 2006. Includes 21,085 shares owned by Mr. Schreiber’s spouse.
(12) Includes 2,500 common shares issuable upon exercise of options that have vested or that will vest on or before April 30, 2006.
(13) Includes 26,448 common shares issuable upon exercise of options that have vested or that will vest on or before April 30, 2006.
(14) Includes 798,275 common shares issuable upon exercise of options that have vested or that will vest on or before April 30, 2006 for all directors and executive officers as a group.

Equity Compensation Plan Information

The following table provides aggregate information presented as of December 31, 2005 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

   2,663,775    $ 25.11    3,100,213

Equity compensation plans not approved by shareholders

   —        —      —  
                

Total

   2,663,775    $ 25.11    3,100,213
                

 

81


Item 13. Certain Relationships and Related Transactions

Following is a discussion of transactions between us and our officers, directors and stockholders owning more than 5% of the outstanding shares of preferred stock and common stock.

Mr. Cornell, a director of the Company, is a managing director of Goldman Sachs. Mr. Cornell initially was nominated as a director pursuant to the stockholders’ agreement and stock purchase agreement dated March 28, 2002, relating to the sale of the Series B preferred stock, pursuant to which certain affiliates of Goldman Sachs purchased a total of 14,000,000 shares of the Series B preferred stock for $5.00 per share for a total purchase price of $70,000,000. J. Aron & Company, an affiliate of Goldman Sachs, is the counterparty to certain of the Company’s natural gas and oil hedge transactions. In management’s opinion, the swap and collar terms were provided on terms at least as favorable to the Company as could be obtained from non-related sources.

Mr. Richard Aube, a director of the Company until May 2005, was until July 2005 a Partner of J.P. Morgan Partners LLC, a company affiliated with the lead arranger and agent for our revolving credit facility. In management’s opinion, the terms obtained through the credit facility were provided on terms at least as favorable to the Company as could be obtained from non-related sources. Affiliates of J.P. Morgan Partners have provided commercial banking and related financial services to us in the past and are expected to provide similar services in the future. Mr. Aube was elected as the J.P. Morgan Entities’ (as defined below) nominee on our board of directors pursuant to the stockholders’ agreement and Series B stock purchase agreement, relating to the sale of the Series B preferred stock, pursuant to which the J.P. Morgan Entities purchased 10,000,000 shares of the Series B preferred stock for $5.00 per share for a total purchase price of $50,000,000. JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan Partners, is a counterparty to certain of the Company’s natural gas and oil hedge transactions. In management’s opinion, the swap and collar terms were provided on terms at least as favorable to the Company as could be obtained from non-related sources.

Mr. Harris, a director of the Company, is a member and serves as a Managing Director at Warburg Pincus LLC. Mr. Harris initially was nominated as a director pursuant to the stockholders’ agreement and Series B stock purchase agreement, relating to the sale of the Series B preferred stock, pursuant to which an affiliate of Warburg Pincus purchased 22,000,000 shares of Series B preferred stock for $5.00 per share for a total purchase price of $110,000,000.

Investments in the Company

In January 2002, the Company issued 1,800,548 shares of common stock to employees for $370,000 for the Company’s initial funding. In connection with the Series B preferred stock purchase agreement entered into in March 2002, all our stockholders prior to our initial public offering were required to become parties to a stockholders’ agreement originally entered into on March 28, 2002. The stockholders’ agreement contains provisions concerning the appointment of directors, limitations on certain corporate activities, the issuance and transfer of securities, and the vesting of shares of common stock issued to employees in January 2002. These shares are subject to vesting requirements as to the length of service with the Company (20% vests on each of January 31, 2002, 2003, 2004, 2005, and 2006, with all shares vesting upon an employee’s reaching the age of 75), which is referred to as “Time Vesting”, and also were subject to vesting requirements as to the amount of proceeds received by the Company from sales of Series B preferred stock to the investors in our Series B preferred stock, pursuant to the Series B stock purchase agreement entered into in March 2002, which is referred to as “Dollar Vesting”. These management shares vest at the later to occur of Time Vesting and Dollar Vesting. Vesting stops upon the occurrence of a liquidation event with respect to the Company, as defined in the agreement, or the sale of the Company. Because the investors purchased all the Series B preferred stock that give rise to Dollar Vesting, the common stock acquired by employees is subject only to Time Vesting going forward. The stockholders’ agreement terminated upon the closing of our initial public offering except for the provisions concerning the vesting of the common stock issued to management and requiring transfers of shares held by parties to the agreement to be made in accordance with applicable securities laws.

 

82


Registration Rights Agreements

Agreement with Series B Preferred Stock Investors

On March 28, 2002, we entered into a registration rights agreement with the holders of our Series B preferred stock who purchased 51,000,000 shares pursuant to the stock purchase agreement dated March 28, 2002. Pursuant to the registration rights agreement, we have agreed to register the transfer of the 23,370,233 shares of our common stock, which are referred to in the agreement as the “registrable securities”, they received upon conversion of their Series B preferred stock immediately prior to the completion of our initial public offering, under certain circumstances. These holders include (directly or indirectly through subsidiaries or affiliates), among others, The Goldman Sachs Group, Inc., the J.P. Morgan Entities and Warburg Pincus Private Equity VIII, L.P.

Demand Registration Rights . Each stockholder who is the holder of (1) more than 10% of our then outstanding common stock, (2) common stock with an aggregate current market value of at least $50,000,000 or (3) stockholders holding at least 60% of the shares of common stock shall have the right to require us by written notice to register a specified number of shares in accordance with the Securities Act and the registration rights agreement. Until we are eligible to use Form S-3 for registration under the Securities Act, each qualified holder has the right to request up to two registrations. Once we are eligible to use Form S-3 for registration, each qualified holder has the right to request up to five registrations, minus any demand registration rights exercised prior to that date. Nevertheless, in no event shall more than one demand registration occur during any six-month period or within 120 days after the effective date of a registration statement, provided that no demand registration may be prohibited for that 120-day period more than once in any 12-month period.

Piggy-back Registration Rights . We propose to file a registration statement under the Securities Act with respect to an offering of common stock (subject to certain exceptions), whether or not for our own account, then we must give at least 30 days’ notice prior to the anticipated filing date to all holders of registrable securities to allow them to include a specified number of their shares in that registration statement. We will be required to maintain the effectiveness of that registration statement until the earlier of 120 days after the effective date and the consummation of the distribution by the participating holders.

Conditions and Limitations; Expenses . The registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with a demand registration or a registration on Form S-3, regardless of whether a registration statement is filed or becomes effective.

Management Rights Agreement

We have entered into a management rights agreement with each of the Goldman entities, the J.P. Morgan Entities and Warburg Pincus Private Equity VIII, L.P., who purchased our Series B preferred stock pursuant to the stock purchase agreement. Under the terms of this agreement, each of these investors is entitled to (1) consult with and advise us on significant business issues, (2) examine our records, subject to customary confidentiality restrictions on the use of such information, and (3) be notified of and attend all meetings of the board in a non-voting advisory capacity and receive all materials distributed to board members. The parties to the management rights agreement do not receive compensation under the agreement. Each respective agreement will terminate upon the date on which the relevant investor owns less than five percent of our capital stock.

Regulatory Sideletter

On March 28, 2002, we entered into a regulatory sideletter with J.P. Morgan Partners (BHCA), L.P., an affiliate of J.P. Morgan Chase & Co. and a regulated entity, which, together with related entities, which previously held more than 5% of our common stock. J.P. Morgan Partners (BHCA), L.P.’s affiliate was a joint-

 

83


lead manager in our initial public offering. Under the terms of this sideletter, we agreed to cooperate with J.P. Morgan Partners (BHCA), L.P. in all reasonable respects to assist its regulatory compliance in connection with legal restrictions, including banking regulations, on the type and terms of its investment in our securities, including conversion to nonvoting securities. This sideletter will terminate upon the date on which J.P. Morgan Partners (BCHA), L.P. owns less than five percent of our capital stock.

 

Item 14. Principal Accounting Fees and Services

Audit Fees

The aggregate fees billed for professional services rendered by Deloitte & Touche LLP for its audit of our annual financial statements, its review of our quarterly financial statements, including our financial statements included in our Registration Statement on Form S-1 in connection with our initial public offering of common stock in December 2004 and Form S-1 in connection with the sale of common stock by selling stockholders in August 2005, and the audit of the Company’s internal controls as required under the Sarbanes Oxley Act of 2002, for the fiscal years 2004 and 2005 were $690,000 and $496,150, respectively.

Audit Related Fees

The aggregate fees billed for professional services rendered by Deloitte & Touche LLP for assurance and related services that are reasonably related to the performance of audit or review of our financial statements for the fiscal years 2004 and 2005 were $48,000 and $4,600, respectively. The 2004 fees were accrued in connection with the audit of the Statements of Revenues and Direct Operating Expenses for the Wind River Acquisition Properties and Piceance Basin Acquisition Properties for our Registration Statement in connection with our initial public offering. The 2005 fees were incurred in connection with the review of the Form S-8 filed in December 2005.

Tax Fees

The aggregate fees billed for professional services rendered by Deloitte & Touche LLP for professional services for tax compliance, tax advice and tax planning for the fiscal years 2004 and 2005 were $49,000 and $0, respectively.

All Other Fees

Not applicable.

Audit Committee Pre-Approval

Our Audit Committee Charter provides that either (i) the Audit Committee shall pre-approve all auditing and non-auditing services of the independent auditor, subject to de minimus exceptions for other than audit, review or attest services that are approved by the Audit Committee prior to completion of the audit; or (ii) that the engagement of the independent auditor be entered into pursuant to pre-approved policies and procedures established by the Audit Committee, provided that the policies and procedures are detailed as to the particular services and the Audit Committee is informed of each service. The Audit Committee pre-approved all of Deloitte & Touche LLP’s fees for audit services in fiscal years 2004 and 2005. Except as indicated above, there were no fees other than audit fees for fiscal years 2004 and 2005, and the auditors engaged performed all the services described above with their full time permanent employees.

 

84


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” on page F-1(a)

(a)(3) Exhibits.

 

Exhibit

Number

   

Description of Exhibits

3.1     Restated Certificate of Incorporation of Bill Barrett Corporation effective immediately prior to the closing of the offering made pursuant to this registration statement. [Incorporated by reference to Exhibit 3.4 to the Company’s 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 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
4.1     Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 3.2 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.2     Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
4.3     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 the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
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 Exhibits B thereto the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.5     Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, included as Exhibit A to Exhibit 4.4 above.
4.6     Form of Right Certificate, included as Exhibit B to Exhibit 4.4 above.
10.1 (a)   Amended and Restated Credit Agreement, dated February 4, 2004, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.1 (b)   First Amendment to Amended and Restated Credit Agreement dated as of September 1, 2004 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(b) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
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 the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.3     Purchase and Sale Agreement, dated March 27, 2002, between Williams Production RMT Company and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

 

85


10.4    Purchase and Sale Agreement, dated April 1, 2002, among Wasatch Oil & Gas, LLC, Wasatch Gas Gathering, LLC and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.5    Purchase and Sale Agreement, November 4, 2002, among, Intoil, Inc., Aratex Production Company and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.5 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.6    Purchase and Sale Agreement, dated January 1, 2003, among Independent Production Company, Inc., Sapphire Bay, LLC and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.7(a)*    Form of Indemnification Agreement dated April 15, 2004, between Bill Barrett Corporation and each of the directors and certain executive officers. [Incorporated by reference to Exhibit 10.10(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.7(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 the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.8*    Employment Letter Agreement, dated January 10, 2003, between Thomas B. Tyree, Jr. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.11 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.9*    Amended and Restated 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.12 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.10(a)*    Form of Tranche A Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.10(b)*    Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10. 13( b) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.11*    2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.12*    Form of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.13    Form of Management Rights Agreement between Bill Barrett Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.14    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 the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.15    Purchase and Sale Agreement effective July 1, 2004 among Calpine Corporation and Calpine Natural Gas, L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.18 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.16    Senior Subordinated Credit and Guaranty Agreement dated as of September 1, 2004 among Bill Barrett Corporation, as Borrower, Bill Barrett Properties Inc. and Bill Barrett Production Company, as Guarantors, various lenders, Goldman Sachs Credit Partners L.P., as sole lead arranger and Goldman Sachs Credit Partners L.P., as administrative agent. [Incorporated by reference to Exhibit 10.19 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

 

86


10.17*    Form of Change in Control Severance Protection Agreement for named executive officers. [Incorporated by reference to Exhibit 10.20 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.18*    2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.19*    Revised Form of Stock Option Agreement for 2004 Stock Option Plan.
10.20*    Severance Plan. [Incorporated by reference to Exhibit 10.23 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
14    Code of Ethics and Business Conduct [Incorporated by reference to Exhibit 14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004.]
21.1    Subsidiaries of the Registrant. [Incorporated by reference to Exhibit 21.1 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
23.1    Consent of Deloitte & Touche LLP.
23.2    Consent of Ryder Scott Company, L.P., Independent Petroleum Engineers.
23.3    Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers.
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.
32.1    Section 1350 Certification of Chief Executive Officer.
32.2    Section 1350 Certification of Chief Financial Officer.

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

 

87


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
By:   / S /    F REDRICK J. B ARRETT        
 

Fredrick J. Barrett

Chairman and Chief Executive Officer

Date: March 2, 2006

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 /    F REDRICK J. B ARRETT        

Fredrick J. Barrett

  

Chairman of the Board of Directors and Chief Executive Officer

(Principal Executive Officer)

  March 2, 2006

/ S /    T HOMAS B. T YREE , J R .        

Thomas B. Tyree, Jr.

  

Chief Financial Officer

(Principal Financial Officer)

  March 2, 2006

/ S /    R OBERT W. H OWARD        

Robert W. Howard

  

Executive Vice President-Finance and Investor Relations, and Treasurer

(Principal Accounting Officer)

  March 2, 2006

/ S /    W ILLIAM J. B ARRETT        

William J. Barrett

  

Director

  March 2, 2006

/ S /    H ENRY C ORNELL        

Henry Cornell

  

Director

  March 2, 2006

/ S /    J AMES M. F ITZGIBBONS        

James M. Fitzgibbons

  

Director

  March 2, 2006

/ S /    J EFFREY A. H ARRIS        

Jeffrey A. Harris

  

Director

  March 2, 2006

 

Roger L. Jarvis

  

Director

 

/ S /    P HILIPPE S.E. S CHREIBER        

Philippe S. E. Schreiber

  

Director

  March 2, 2006

/ S /    R ANDY S TEIN        

Randy Stein

  

Director

  March 2, 2006

/ S /    M ICHAEL E. W ILEY        

Michael E. Wiley

  

Director

  March 2, 2006

 

88


FINANCIAL STATEMENTS

INDEX TO FINANCIAL STATEMENTS

 

Bill Barrett Corporation   

Report of Independent Registered Public Accounting Firm

   F-2

Consolidated Balance Sheets, December 31, 2004 and 2005

   F-3

Consolidated Statements of Operations, for the years ended December 31, 2003, 2004 and 2005

   F-4

Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss), for the years ended December 31, 2003, 2004 and 2005

   F-5

Consolidated Statements of Cash Flows, for the years ended December 31, 2003, 2004 and 2005

   F-6

Notes to Consolidated Financial Statements

   F-7


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, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2005. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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 accounting for stock-based compensation in 2004 with the implementation of Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payment”.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, 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 March 1, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Denver, Colorado

March 1, 2006


BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

 

     As of December 31,  
     2004     2005  
     (in thousands, except share
and per share data)
 

Assets:

    

Current Assets:

    

Cash and cash equivalents

   $ 99,926     $ 68,282  

Accounts receivable, net of allowance for doubtful accounts of $89 and $171 as of December 31, 2004 and 2005, respectfully

     31,149       55,960  

Prepayments and other current assets

     4,625       6,598  

Deferred income taxes

     2,190       10,478  
                

Total current assets

     137,890       141,318  

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

    

Proved oil and gas properties

     517,210       804,421  

Unevaluated oil and gas properties, excluded from amortization

     137,605       168,284  

Furniture, equipment and other

     4,964       11,533  
                
     659,779       984,238  

Accumulated depreciation, depletion, amortization and impairment

     (107,614 )     (238,290 )
                

Total property and equipment, net

     552,165       745,948  

Deferred Income Taxes

     3,081       —    

Deferred Financing Costs and Other Assets

     3,022       1,679  
                

Total

   $ 696,158     $ 888,945  
                

Liabilities and Stockholders’ Equity:

    

Current Liabilities:

    

Accounts payable and accrued liabilities

   $ 37,392     $ 58,113  

Amounts payable to oil and gas property owners

     5,390       19,697  

Production taxes payable

     15,437       25,930  

Derivative liability and other

     3,887       29,058  
                

Total current liabilities

     62,106       132,798  

Note Payable to Bank

     —         86,000  

Asset Retirement Obligations

     11,806       23,733  

Deferred income taxes

     —         7,960  

Other Noncurrent Liabilities

     2,514       7,671  

Stockholders’ Equity:

    

Common stock, $0.001 par value; authorized 150,000,000 shares; 43,323,270 and 43,695,286 shares issued at December 31, 2004 and 2005, respectively, with 283,887 and 26,577 shares subject to restrictions, respectively

     43       44  

Additional paid-in capital

     709,578       721,145  

Accumulated deficit

     (86,320 )     (62,515 )

Treasury stock, at cost: 124,024 shares

     —         (5,180 )

Accumulated other comprehensive loss

     (3,569 )     (22,711 )
                

Total stockholders’ equity

     619,732       630,783  
                

Total

   $ 696,158     $ 888,945  
                

See notes to consolidated financial statements.

 

F-3


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

 

     Year Ended December 31,  
     2003     2004     2005  
     (in thousands, except share
and per share amounts)
 

Operating Revenues:

      

Oil and gas production

   $ 75,252     $ 165,843     $ 284,406  

Other

     184       4,137       4,353  
                        

Total revenues

     75,436       169,980       288,759  

Operating Expenses:

      

Lease operating expense

     8,462       14,592       19,585  

Gathering and transportation expense

     3,646       5,968       11,950  

Production tax expense

     9,815       20,087       33,465  

Exploration expense

     3,655       12,661       10,930  

Impairment, dry hole costs and abandonment expense

     4,274       24,011       55,353  

Depreciation, depletion and amortization

     30,724       68,202       89,499  

General and administrative

     17,850       21,092       27,752  
                        

Total operating expenses

     78,426       166,613       248,534  
                        

Operating income (loss)

     (2,990 )     3,367       40,225  

Other Income and Expense:

      

Interest and other income

     123       437       1,977  

Interest expense

     (1,431 )     (9,945 )     (3,175 )
                        

Total other income and expense

     (1,308 )     (9,508 )     (1,198 )
                        

Income (Loss) before Income Taxes

     (4,298 )     (6,141 )     39,027  

Provision for (Benefit from) Income Taxes

     (320 )     (875 )     15,222  
                        

Net Income (Loss)

     (3,978 )     (5,266 )     23,805  

Less deemed dividends on preferred stock

     —         (36,343 )     —    

Less cumulative dividends on preferred stock

     (12,682 )     (18,633 )     —    
                        

Net income (loss) attributable to common stock

   $ (16,660 )   $ (60,242 )   $ 23,805  
                        

Net Income (Loss) Per Common Share, Basic

   $ (19.38 )   $ (15.40 )   $ 0.55  
                        

Net Income (Loss) Per Common Share, Diluted

   $ (19.38 )   $ (15.40 )   $ 0.55  
                        

Weighted Average Common Shares Outstanding, Basic

     859,438       3,912,285       43,238,312  
                        

Weighted Average Common Shares Outstanding, Diluted

     859,438       3,912,285       43,439,634  
                        

See notes to consolidated financial statements.

 

F-4


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the years ended December 31, 2003, 2004, and 2005

 

   

Convertible

Preferred

Stock

   

Common

Stock

   

Additional

Paid-In

Capital

   

Accumulated

Deficit

   

Treasury

Stock

   

Accumulated

Other

Compre-

hensive

Loss

   

Total

Stock-

holders’

Equity

   

Compre-

hensive

(Loss)
Income

 
    (in thousands)  

Balance—December 31, 2002

  $ 27     $ 8     $ 129,103     $ (4,988 )     $ (348 )   $ 123,802    

Issuance of Series B convertible preferred stock for cash

    24       —         118,952       —         —         —         118,976     $ —    

Offering costs paid on issuance of Series B convertible preferred stock

    —         —         (1,335 )     —         —         —         (1,335 )     —    

Issuance of Series B convertible preferred stock for acquisition of mineral leasehold interests

    —         —         1,253       —         —         —         1,253       —    

Exercise of options

    —         1       23       —         —         —         24       —    

Stock-based compensation

    —         —         3,637       —         —         —         3,637       —    

Comprehensive loss:

               

Net loss

    —         —         —         (3,978 )     —         —         (3,978 )     (3,978 )

Effect of derivative financial instruments, net of tax

    —         —         —         —         —         (4,053 )     (4,053 )     (4,053 )
                                                               

Total comprehensive loss

                $ (8,031 )
                     

Balance—December 31, 2003

  $ 51     $ 9     $ 251,633     $ (8,966 )   $ —       $ (4,401 )   $ 238,326    

Issuance of Series B convertible preferred stock for cash

    7       —         33,723       —         —         —         33,730     $ —    

Exercise of options

    —         —         52       —         —         —         52       —    

Issuance of Series B convertible preferred stock for acquisition of mineral leasehold interests

    —         —         322       —         —         —         322       —    

Cancellation of Series A convertible preferred stock

    —         —         (500 )     —         —         —         (500 )     —    

Reverse stock split: 1-for-4.658

    —         (7 )     7       —         —         —         —         —    

Proceeds from initial public offering (net of underwriters’ discount of $26,445)

    —         15       347,290       —         —         —         347,305       —    

Conversion of convertible note payable into common stock

    —         —         1,900       —         —         —         1,900       —    

Conversion of issued and outstanding Series A convertible preferred stock into common stock upon initial public offering

    (6 )     2       4       —         —         —         —         —    

Conversion of issued and outstanding Series B convertible preferred stock into common stock upon initial public offering

    (52 )     24       28       —         —         —         —         —    

Recognition of 7% cumulative dividend on Series B convertible stock in common stock

    —         —         35,745       (35,745 )     —         —         —         —    

Recognition of deemed dividends related to the conversion of Series B convertible stock into common stock upon initial public offering

    —         —         36,343       (36,343 )     —         —         —         —    

Stock-based compensation

    —         —         3,031       —         —         —         3,031       —    

Comprehensive (loss) income:

               

Net loss

    —         —         —         (5,266 )     —         —         (5,266 )     (5,266 )

Effect of derivative financial instruments, net of tax

    —         —         —         —         —         832       832       832  
                                                               

Total comprehensive loss

                $ (4,434 )
                     

Balance—December 31, 2004

  $ —       $ 43     $ 709,578     $ (86,320 )   $ —       $ (3,569 )   $ 619,732    

Exercise of options

    —         1       7,149       —         (5,180 )     —         1,970     $ —    

Tax benefit from option exercises

    —         —         1,227       —         —         —         1,227       —    

Stock-based compensation

    —         —         3,211       —         —         —         3,211       —    

Other

    —         —         (20 )     —         —         —         (20 )     —    

Comprehensive income (loss):

               

Net income

    —         —         —         23,805       —         —         23,805       23,805  

Effect of derivative financial instruments, net of tax

    —         —         —         —         —         (19,142 )     (19,142 )     (19,142 )
                                                               

Total comprehensive income

                $ 4,663  
                     

Balance—December 31, 2005

  $ —       $ 44     $ 721,145     $ (62,515 )   $ (5,180 )   $ (22,711 )   $ 630,783    
                                                         

See notes to consolidated financial statements.

 

F-5


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

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

Operating Activities:

      

Net Income (Loss)

   $ (3,978 )   $ (5,266 )   $ 23,805  

Adjustments to reconcile to net cash provided by operations:

      

Depreciation, depletion and amortization

     30,724       68,202       89,499  

Deferred income taxes

     (320 )     (875 )     15,222  

Impairments, dry hole costs and abandonment expense

     4,274       24,011       55,353  

Stock compensation and other non-cash charges

     3,684       3,071       3,226  

Amortization of deferred financing costs

     148       4,409       1,175  

Gain on sale of properties

     —         (3,729 )     (3,808 )

Change in assets and liabilities:

      

Accounts receivable

     (9,272 )     (15,802 )     (24,811 )

Prepayments and other current assets

     (803 )     (2,037 )     (1,891 )

Accounts payable, accrued and other liabilities

     3,490       3,664       1,700  

Amounts payable to oil and gas property owners

     1,314       3,450       14,307  

Production taxes payable

     4,612       7,784       10,493  
                        

Net cash provided by operating activities

     33,873       86,882       184,270  

Investing Activities:

      

Additions to oil and gas properties, including acquisitions

     (173,246 )     (327,430 )     (314,965 )

Additions of furniture, equipment and other

     (1,823 )     (2,141 )     (3,720 )

Proceeds from sale of properties

     11,878       8,811       13,842  
                        

Net cash used in investing activities

     (163,191 )     (320,760 )     (304,843 )

Financing Activities:

      

Proceeds from debt

     110,000       288,000       146,000  

Principal payments on debt

     (88,000 )     (345,000 )     (60,000 )

Proceeds from sale of common and preferred stock

     119,000       33,782       2,979  

Proceeds from initial public offering

     —         373,750       —    

Offering costs

     (1,335 )     (26,384 )     (84 )

Deferred financing costs and other

     (26 )     (6,378 )     34  
                        

Net cash provided by financing activities

     139,639       317,770       88,929  
                        

Increase (Decrease) in Cash and Cash Equivalents

     10,321       83,892       (31,644 )

Beginning Cash and Cash Equivalents

     5,713       16,034       99,926  
                        

Ending Cash and Cash Equivalents

   $ 16,034     $ 99,926     $ 68,282  
                        

See notes to consolidated financial statements.

 

F-6


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2003, 2004 and 2005

1. Organization

Bill Barrett Corporation, a Delaware corporation, is an independent oil and gas company engaged in the acquisition, exploration, development and production of natural gas and crude oil. Since its inception on January 7, 2002, Bill Barrett Corporation 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”, “we”, “us” or “our”). These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany accounts and transactions have been eliminated.

Use of Estimates. Preparation of the Company’s financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses for the reporting period. Actual results could differ from those estimates.

In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. 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 more significant areas requiring the use of assumptions, judgments and estimates relate to volumes of natural gas and oil reserves used in calculating depletion, 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 such calculations. Assumptions, judgments and estimates also are required in determining future abandonment obligations, impairments of undeveloped properties, valuing deferred tax assets and estimating fair values of derivative instruments.

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 pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies . The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs also are 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. To date, the Company has not capitalized any interest expense.

Other exploration costs, including personnel costs, 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

 

F-7


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of proved properties. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unevaluated properties with significant acquisition costs are assessed periodically on a property-by-property basis and any impairment in value is charged to expense. If the unevaluated properties are subsequently determined to be productive, the related costs are transferred to proved oil and gas properties. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain or loss until all costs are recovered. During 2003, the Company recorded impairment expense of $1,795,000 related to unevaluated properties.

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

The following table sets forth the net capitalized costs and associated accumulated depreciation, depletion and amortization, including impairments, relating to the Company’s natural gas and oil producing activities (in thousands):

 

     As of December 31,  
     2004     2005  

Proved properties

   $ 258,387     $ 286,503  

Wells and related equipment and facilities

     216,335       445,943  

Support equipment and facilities

     38,890       64,969  

Materials and supplies

     3,598       7,006  
                

Total proved oil and gas properties

     517,210       804,421  

Accumulated depreciation, depletion, amortization and impairment

     (105,633 )     (234,713 )
                

Total proved oil and gas properties, net

   $ 411,577     $ 569,708  
                

Unevaluated properties

   $ 97,099     $ 93,145  

Wells and equipment in progress

     40,506       75,139  
                

Total unevaluated oil and gas properties, excluded from amortization

   $ 137,605     $ 168,284  
                

Net changes in capitalized exploratory well costs for the years ended December 31, 2003, 2004 and 2005 are reflected in the following table (in thousands):

 

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

Beginning of period

   $ 2,825     $ 310     $ 19,940  

Additions to capitalized exploratory well costs pending the determination of proved reserves

     37,801       85,445       209,847  

Reclassifications to wells, facilities and equipment based on the determination of proved reserves

     (38,103 )     (42,788 )     (157,158 )

Exploratory well costs charged to impairment, dry hole costs and abandonment expense

     (2,213 )     (23,027 )     (11,099 )
                        

End of period

   $ 310     $ 19,940     $ 61,530  
                        

 

F-8


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have be capitalized for a period greater than on year since the completion of drilling (dollars expressed in thousands):

 

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

Capitalized exploratory well costs that have been capitalized for a period of one year or less

   $ 310    $ 19,940    $ 58,113

Capitalized exploratory well costs that have been capitalized for a period greater than one year

     —        —        3,417
                    

End of period balance

   $ 310    $ 19,940    $ 61,530
                    

Number of exploratory wells that have costs capitalized for a period greater than one year

     —        —        24
                    

As of December 31, 2005, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling include costs of $3.4 million. The majority of our exploratory wells that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, we drill wells into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting from a few to twenty four 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, the Company had one well that has been capitalized for a period greater than one year outside of the Powder River Basin. It cannot be completed until the approval of the Bureau of Land Management is granted for the right of way to build a gathering line to an existing gas pipeline.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

During the years ended December 31, 2004 and 2005, the Company recognized non-cash impairment charges of $0.5 million and $42.7 million, respectively included within the Impairment, dry hole costs and abandonment expense, all of which was related to its proved oil and gas properties in the Wind River Basin. The impairment expense during 2005 is comprised of a $29.5 million impairment charge in the Cooper Reservoir field, $11.3 million impairment charge in the Talon field and $1.9 million impairment charge in the East Madden field. This was primarily a result of production from existing and recently drilled wells in the Cooper Reservoir field declining more rapidly than anticipated due to interference caused by infill drilling. Additionally, in the Talon and East Madden fields, production from exploratory wells was at a rate that did not justify the capital investment in those wells. The carrying amount of these properties was adjusted to fair value, which was determined based upon the present value of future cash flows, net of operating and development costs, discounted at various rates consistent with current market conditions at which similar types of properties are being traded.

 

F-9


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The provision for depreciation, depletion and amortization (“DD&A”) 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. Taken into consideration in the calculation of DD&A are estimated future dismantlement, restoration and abandonment costs, net of estimated salvage values.

Furniture, Equipment and Other. Land and other office and field equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Leasehold improvements are amortized over the life of the lease. Maintenance and repairs are expensed when incurred. Depreciation of other property and equipment is computed using the straight-line method over their estimated useful lives of three to ten years. Upon retirement or disposition of assets, the costs and related accumulated depreciation are removed from the accounts with the resulting gains or losses, if any, reflected in results of operations.

Accounts Payable and Accrued Liabilities. Accounts payable and accrued expenses are comprised of the following:

 

     As of December 31,
     2004    2005

Accrued drilling and facility costs

   $ 16,299    $ 36,070

Accrued lease operating and gathering and transportation expenses

     2,680      3,037

Accrued general and administrative expenses

     3,745      5,013

Trade payables

     10,693      8,411

Other

     3,975      5,582
             

Total accounts payable & accrued liabilities

   $ 37,392    $ 58,113
             

Environmental Liabilities. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2004 and 2005, the Company has not accrued for nor been fined or cited for any environmental violations, which would have a material adverse effect upon capital expenditures, operating results or the competitive position of the Company.

Revenue Recognition. The Company records revenues from the sales of natural gas and crude oil when delivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred.

The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at December 31, 2004 and 2005 were not significant.

Comprehensive (Loss) Income. Comprehensive (loss) income consists of net (loss) income and the effective component of derivative instruments classified as cash flow hedges. Comprehensive (loss) income is presented net of income taxes in the Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss).

 

F-10


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Derivative Instruments and Hedging Activities. The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its gas and oil production by reducing its exposure to price fluctuations.

The Company accounts for such activities pursuant to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities , as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities.

The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. SFAS No. 133 requires that a company 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 other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is assessed 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.

The Company may utilize derivative financial instruments which have not been designated as hedges under SFAS No. 133 even though they protect the Company from changes in commodity prices. These instruments are marked to market with the resulting changes in fair value recorded in earnings.

Deferred Financing Costs. Costs incurred in connection with the execution of the Company’s credit facility and bridge loan have been capitalized and are amortized over the life of the facilities.

Income Taxes. 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 liabilities are 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.

Stock-Based Compensation. In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (revised 2004) Share-Based Payment (“SFAS No. 123(R)”), which revises SFAS No. 123, Accounting for Stock-Based Compensation , and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees . SFAS No. 123(R) establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods and services, focusing primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. It also addresses transactions in which an entity incurs liabilities in exchange for goods and services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. We early adopted the provisions of the new standard effective October 1, 2004. Prior to the adoption of SFAS No. 123(R), we used the intrinsic value method in accordance with APB Opinion No. 25 and the disclosure provisions of SFAS No. 123.

 

F-11


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

For awards granted while we were a nonpublic company (those granted prior to April 16, 2004, the date of which is defined by SFAS No. 123(R) as the date we became a public company as a result of making a filing with a regulatory agency in preparation for the sale of equity securities in a public market), we adopted SFAS No. 123(R) using the prospective transition method. Under the prospective transition method, we continue to account for awards granted prior to becoming a public company using the minimum value method described under SFAS No. 123. Accordingly, zero compensation expense was recorded upon adoption of SFAS No. 123(R) for those awards. Additionally, the calculated fair value of those awards using the minimum value method is not comparable to those options granted subsequent to April 16, 2004, for which a fair-value-based method was used.

For awards granted after we were a public company (those granted subsequent to April 16, 2004), we adopted SFAS No. 123(R) using the modified prospective application effective October 1, 2004, whereby as of that date we began applying the provisions of SFAS No. 123(R) to new awards and to awards modified, repurchased, or cancelled on or after October 1, 2004. For awards granted after April 16, 2004 and before October 1, 2004, we recognized share-based employee compensation cost based on the historical grant-date fair value as computed under SFAS No. 123 on October 1, 2004 for the portion of awards previously granted and for which the requisite service had not yet been rendered.

The following table illustrates the pro forma effect on net income and loss per share if compensation costs had been determined based upon the fair value at the grant dates in accordance with SFAS No. 123 for stock option grants issued after we were considered a public company on April 16, 2004, as defined by SFAS No. 123, but before adoption of SFAS No. 123(R) on October 1, 2004:

 

     Year Ended  
     December 31,  
     2003    2004  
     (in thousands,
except per share
amounts)
 

Net loss, as reported

   n/a    $ (5,266 )

Add stock-based compensation included in reported net loss, net of related tax effects

   n/a      3,003  

Deduct stock-based compensation expense determined under fair value method, net of related tax effects

   n/a      (3,016 )
             

Pro forma net loss

   n/a      (5,279 )

Less cumulative and deemed dividends on preferred stock

   n/a      (54,976 )
             

Pro forma loss attributable to common stock

   n/a    $ (60,255 )
             

Basic loss per share:

     

As reported

   n/a    $ (15.40 )

Pro forma

   n/a    $ (15.40 )

Diluted loss per share:

     

As reported

   n/a    $ (15.40 )

Pro forma

   n/a    $ (15.40 )

The Company continues to account for certain stock options under the original provisions of APB Opinion No. 25 as those options were issued prior to April 16, 2004, when we were considered a nonpublic entity as defined by SFAS No. 123(R). As those options were accounted for under the minimum-value method, the calculated fair value is not comparable to those options issued subsequent to April 16, 2004, in which a fair-value-based method was then used. Therefore, pro forma disclosures for stock options granted while we were a nonpublic company accounted for using the minimum-value method have not been included pursuant to SFAS No. 123(R).

 

F-12


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

During the year ended December 31, 2005, the Company granted 266,700 options to purchase shares of common stock with a weighted average exercise price of $32.25 per share and 5,352 nonvested equity shares of common stock. Included within general and administrative expense is non-cash stock based compensation related to option and nonvested equity share awards of $3.0 million and $3.2 million for the years ended December 31, 2004 and 2005, respectively. See Note 10 for additional disclosures about stock-based compensation.

Earnings Per Share. In connection with our initial public offering (“IPO”) in December 2004, a common stock reverse split of 1-for-4.658 was effected. All share and per share amounts for periods prior to December 2004 reflect the reverse split.

Basic net income (loss) per common share of stock is calculated by dividing net income (loss) attributable to common stock by the weighted-average of vested common shares outstanding during each period. Diluted net income (loss) attributable to common shareholders is calculated using the treasury stock method, which also considers the impact to net income and common shares for the potential dilution from stock options and nonvested equity shares of common stock.

Net income (loss) attributable to common stock is calculated by reducing net (loss) income by dividends earned on preferred securities. For the years ended December 31, 2003 and 2004, Series B preferred dividends, whether or not declared or paid, are considered earned for these calculations. The Series A and Series B preferred stock, the convertible note, the issued common shares subject to restrictions and outstanding options, have not been included in the computation of earnings per share for the years ended December 31, 2003 and 2004, as their inclusion would have been anti-dilutive. For the year ended December 31, 2005, 118,700 shares attributable to the assumed exercise of outstanding options were excluded from the calculation of diluted EPS because the effect was antidilutive.

The Emerging Issues Task Force, (“EITF”), has issued EITF Issue No. 03-6, Participating Securities and the Two-Class Method under FASB Statement No. 128 Earnings Per Share ”, (“EITF 03-6”). We adopted EITF 03-6 as of January 1, 2004. EITF 03-6 provides guidance for the computation of earnings per share using the two-class method for enterprises with participating securities or multiple classes of common stock as required by SFAS No. 128. The two-class method allocates undistributed earnings to each class of common stock and participating securities for the purpose of computing basic earnings per share. However, upon completion of our IPO on December 15, 2004, all outstanding preferred securities were converted into common stock and, thus, we were not required to apply the two-class method for the year ended December 31, 2004. For the year ended December 31, 2004, we have included the deemed dividends previously measured related to issuance of preferred securities and their beneficial conversion in the calculation to determine net income (loss) attributable to common stock because the contingency related to the conversion has been resolved due to the completion of the initial public offering.

 

F-13


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table sets forth the calculation of basic and diluted earnings per share:

 

     Year Ended
     December 31,
     2003     2004     2005
     (in thousands except per share
amounts)

Income (loss) from continuing operations

   $ (3,978 )   $ (5,266 )   $ 23,805

Less cumulative dividends on preferred stock

     (12,682 )     (18,633 )     n/a

Less deemed dividends on preferred stock

     —         (36,343 )     n/a
                      

Income (loss) from continuing operations to be allocated

     (16,660 )     (60,242 )     23,805

Less allocation of undistributed earnings to participating preferred stock

     —         —         —  
                      

Net income (loss) attributable to common stock

     (16,660 )     (60,242 )     23,805

Adjustments to net income for dilution

     n/a       n/a       —  
                      

Net income (loss) adjusted for the effect of dilution

   $ (16,660 )   $ (60,242 )   $ 23,805
                      

Basic weighted-average common shares outstanding in period

     859.4       3,912.3       43,238.3

Add dilutive effects of stock options and nonvested equity shares of common stock

     —         —         201.3
                      

Diluted weighted-average common shares outstanding in period

     859.4       3,912.3       43,439.6
                      

Basic income (loss) per common share

   $ (19.38 )   $ (15.40 )   $ 0.55
                      

Diluted income (loss) per common share

   $ (19.38 )   $ (15.40 )   $ 0.55
                      

The weighted-average number of common shares outstanding used in the income (loss) per share calculation is computed pursuant to SFAS No. 128. The weighted-average common shares outstanding for the year ended December 31, 2004 does not include the 6,594,725 shares of Series A or the 51,951,418 shares of Series B preferred stock that were converted into to a total of 26,387,679 common shares until the completion of our initial public offering in December, 2004.

Industry Segment and Geographic Information. The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the United States. Consequently, the Company currently reports a single industry segment.

Reclassifications. The Company reclassified $2.5 million and $23.5 million for the years ended December 31, 2003 and 2004, respectively, from exploration expense to impairment, dry hole costs and abandonment expense in the statements of operations to conform to the current period presentation.

The Company reclassified $3.6 million and $3.0 million for the years ended December 31, 2003 and 2004, respectively, from non-cash stock-based compensation expense to general and administrative expense in the statements of operations to conform to the current period presentation.

New Accounting Pronouncements. In June 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections , which replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements . Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. APB Opinion No. 20 previously required that most voluntary changes in an accounting principle be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. SFAS No. 154 now requires retrospective application of changes in an accounting principle to prior period financial statements, unless it is impracticable to determine

 

F-14


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

either the period-specific effects or the cumulative effect of the change. The Statement is effective for fiscal years beginning after December 15, 2005. We do not expect the adoption of this statement will have a material impact on our financial statements.

On August 31, 2005, the FASB issued FSP FAS No. 123(R)-1, Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement 123(R) . This guidance applies to equity shares, as well as stock options, and requires that a freestanding financial instrument issued to an employee in exchange for past or future employee services that is subject to SFAS No. 123(R) shall continue to be subject to the recognition and measurement provisions of SFAS No. 123(R) throughout the life of the instrument, unless its terms are modified when the holder is no longer an employee. The Company adopted FSP FAS No. 123(R)-1 during the quarter ended September 30, 2005, and it did not have an impact on our financial statements.

On October 18, 2005, the FASB issued FSP FAS No. 123(R)-2, Practical Accommodation to the Application of Grant Date as Defined in SFAS No. 123(R ), which provides a reasonable approach in determining the grant date of an equity award. The Position clarifies that a mutual understanding of the grant terms shall be presumed to exist at the date the award is approved if (1) the grantee is not able to negotiate the terms of the award and (2) the terms of the grant are communicated to the grantee within a reasonable period of time. FSP FAS No. 123(R)-2 was effective for our Company as of the fourth quarter of 2005 and its adoption did not have an impact on our financial statements.

In October 2005, the FASB issued FSP FAS No. 13-1, Accounting for Rental Costs Incurred during a Construction Period , which is effective for reporting periods beginning after December 15, 2005. This Position requires that rental costs associated with ground or building operating leases that are incurred during a construction period be recognized as rental expense. We do not expect the adoption of FSP No. 13-1 to have an impact on our financial statements.

In February 2006, the FASB issued FSP FAS No. 123(R)-4, Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event . This FSP is effective for reporting periods beginning after February 3, 2006, with early application permitted, and it amends FAS No. 123(R) by stipulating that if a cash settlement feature can be exercised only upon the occurrence of a contingent event that is outside the employee’s control then it should be treated as an equity award until it becomes probable that the event will occur. As of December 31, 2005, the Company has accounted for all options in accordance with FSP FAS No. 123(R)-4.

3. Supplemental Disclosures of Cash Flow Information:

Supplemental cash flow information is as follows:

 

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

Cash paid for interest

   $ 1,168    $ 5,362     $ 1,903

Supplemental disclosures of noncash investing and financing activities:

       

Preferred stock issued for payment of oil and gas properties

     1,253      322       —  

Preferred stock returned in settlement to terminate an exploration agreement

     —        (500 )     —  

Treasury stock acquired for employee stock option exercises

     —        —         5,180

Conversion of convertible note payable into Series A convertible preferred stock

     —        1,900       —  

Changes in working capital related to acquisition of property and equipment

     19,687      2,099       17,889

Net change in asset retirement obligations

     2,936      7,153       10,854

 

F-15


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

4. Acquisitions and Dispositions

On July 1, 2002, the Company paid $2.5 million to the Crow Tribe in Montana (the “Crow Tribe”) for an option to acquire leasehold interests pursuant to an exploration agreement dated June 11, 2002. Payment for the option consisted of $2.0 million in cash and 119,904 shares of the Company’s Series A preferred stock. On August 1, 2002, the Company acquired from the Crow Tribe 11,540 leasehold acres for $2.6 million in cash. The Company and the Crow Tribe negotiated a settlement to terminate the exploration agreement, which was approved by the Bureau of Indian Affairs on February 20, 2004. The settlement agreement provides, among other things, for the Crow Tribe to return to the Company the 119,904 shares of Series A preferred stock, the payment of $2.4 million to the Company, and additional payments to the Company of $1.5 million over five and one half years with interest fixed at the prime rate in effect on February 20, 2004 plus 2%, or a total of 6%. An impairment charge of $856,000 was recorded as of December 31, 2003. The Company received the 119,904 shares of stock on March 8, 2004, and received the payment of $2.4 million on March 11, 2004. In addition, the first payment of $750,000 toward the $1.5 million, plus accrued interest, was received in February 2005, and the second payment of $150,000, plus accrued interest, was received in August 2005.

On September 1, 2004, the Company purchased certain oil and natural gas properties and related assets located in Colorado (the “Piceance Basin Acquisition Properties”) from Calpine Corporation and Calpine Natural Gas L.P. The cash purchase price was $137.3 million after closing adjustments including revenue and operating expense between July 1, 2004 and September 1, 2004.

The following unaudited pro forma information presents the financial information of the Company as if the Piceance Basin Acquisition Properties were acquired on January 1, 2003:

 

     Year Ended December 31,  
     2003     2004  
     As Reported     Pro Forma     As Reported     Pro Forma  
     (in thousands)  

Revenue

   $ 75,436     $ 90,302     $ 169,980     $ 182,271  

Direct operating expenses

     (21,923 )     (24,379 )     (40,647 )     (42,489 )
                                

Revenues in excess of direct operating expenses

     53,513       65,923       129,333       139,782  

Net Loss

   $ (3,978 )   $ (4,070 )   $ (5,266 )   $ (4,049 )
                                

Basic and Diluted Net Loss Per Common Share

   $ (19.38 )   $ (19.49 )   $ (15.40 )   $ (15.09 )

5. Note Payable to Bank

The Company has a credit facility (the “Credit Facility”) which provides for a maturity date of February 4, 2007 and commitments of $200 million with an initial borrowing base of $150 million. The initial borrowing base under the Credit Facility includes a $50 million portion, referred to as the “Tranche B” portion that allows the borrowing base to be greater than the typical borrowing base that would have been computed based on proved natural gas and oil reserves. The Credit Facility bears interest, based on the borrowing base usage, at LIBOR or an alternate base rate (based upon the greater of the prime rate, or on the federal funds effective rate) plus applicable margins ranging from 0% to 3.75%. The Company pays commitment fees ranging from 0.375% to 0.50% of the unused borrowing base.

The Credit Facility contains financial covenants, including but not limited to a maximum total debt to EBITDAX ratio (as defined), a minimum current ratio, an interest coverage ratio, and a minimum present value to total debt ratio. The Company has complied with all covenants for all periods. This facility is secured by the Company’s oil and gas properties representing at least 85% of the total value of the Company’s proved reserves and the pledge of all of the stock of the Company’s subsidiaries.

 

F-16


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

On September 1, 2004, the Company amended its Credit Facility to increase the borrowing base to $200 million from $150 million and to allow for incurrence of unsecured debt. The Tranche B portion was amended to be the lesser of $45 million and the difference between $200 million and the borrowing base computed by the bank group based on proved reserves. The Tranche B portion of the amended Credit Facility terminated on November 30, 2005. At December 31, 2005, the total borrowing base, excluding the Tranche B portion, remains at $200 million, which was redetermined based upon our June 30, 2005 reserve report. At December 31, 2005, borrowings outstanding under the Credit Facility totaled $86 million. The weighted-average interest rate was 5.9% at December 31, 2005.

In order to fund the acquisition of the Piceance Basin Acquisition Properties and related costs (see Note 4), the Company entered into a senior subordinated credit and guaranty agreement, or bridge loan, which had a total principal amount of $150 million. In December 2004, the bridge loan was repaid in full with proceeds from our initial public offering and the bridge loan was terminated. The interest rate under the bridge loan was equal to LIBOR, for one or three month periods as selected by the Company and which are known as interest periods, plus a margin. From September 1, 2004 to December 2004, the margin was 4.0%.

6. Asset Retirement Obligations

The Company accounts for its asset retirement obligations in accordance with SFAS No. 143. The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in other long-term liabilities in the accompanying Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the accompanying Consolidated Statements of Operations.

A reconciliation of the Company’s asset retirement obligations is as follows:

 

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

Beginning of period

   $ 1,117    $ 4,297     $ 11,806  

Liabilities incurred

     1,932      6,996       2,429  

Liabilities settled

     —        (848 )     (203 )

Accretion expense

     244      397       1,276  

Revisions to estimate

     1,004      964       8,425  
                       

End of period

   $ 4,297    $ 11,806     $ 23,733  
                       

7. Fair Value of Derivatives and Other Financial Instruments

The Company’s financial instruments including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Credit Facility, as discussed in Note 5, approximates the fair value due to its floating rate structure. The Company’s commodity derivatives are marked to market with changes in fair value being recorded in other comprehensive income.

 

F-17


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

To mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices and to comply with our credit agreement, we have entered into commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. Our natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133 and are included in current and other long-term liabilities in the Company’s Consolidated Balance Sheets.

The estimated fair value of derivatives and other financial instruments has been determined by the Company using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

At December 31, 2005, the Company had the following cashless collars (purchased put options and written call options) in order to hedge a portion of our 2006 and 2007 natural gas and oil production. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas production. The index prices for natural gas contracts are based on Rocky Mountain delivery points and the index prices for oil contracts are based on West Texas Intermediate Crude Oil as quoted on the New York Mercantile Exchange.

 

Product

  

Volume

Per Day

  

Quantity

Type

  

Weighted

Average Floor

Pricing

  

Weighted

Average Ceiling

Pricing

  

Index

Price (1)

   Contract Period

Natural gas

   35,000    MMBtu    $ 4.82    $ 6.72    NORRM    1/1/2006–12/31/2006

Natural gas

   24,000    MMBtu    $ 7.54    $ 13.68    CIG    1/1/2006–12/31/2006

Oil

   750    Bbls    $ 42.53    $ 52.26    WTI    1/1/2006–12/31/2006

Natural gas

   29,000    MMBtu    $ 5.25    $ 10.22    CIG    1/1/2007–12/31/2007

Oil

   600    Bbls    $ 50.00    $ 78.15    WTI    1/1/2007–12/31/2007

(1) NORRM refers to Northwest Pipeline Rocky Mountains price and CIG refers to Colorado Interstate Gas Rocky Mountains price as quoted in Platt’s Inside FERC on the first business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

At December 31, 2005, the estimated fair value of contracts designated and qualifying as cash flow hedges under SFAS No. 133 was a liability of $36.0 million. The Company will reclassify the appropriate amount to gains or losses included in oil and natural gas production operating revenues as the hedged production quantity is produced. Based on current projected market prices, the net amount of existing unrealized after-tax loss as of December 31, 2005 to be reclassified from accumulated other comprehensive loss to net income in the next twelve months would be $18.3 million. The Company anticipates that all original forecasted transactions will occur by the end of the originally specified time periods.

Derivative contract settlements included in oil and gas production operating revenues totaled net losses of $7.7 million, $12.4 million and $24.3 million for the years ended December 31, 2003, 2004 and 2005 respectively. As the underlying prices in the Company’s hedge contracts were consistent with the indices used to sell its oil and gas, no ineffectiveness was recognized related to its hedge contracts for the years ended December 31, 2003, 2004, and 2005.

8. Income Taxes

The expense (benefit) for income taxes consists of the following:

 

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

Deferred:

      

Federal

   $ (296 )   $ (688 )   $ 14,629

State

     (24 )     (187 )     593
                      

Total

   $ (320 )   $ (875 )   $ 15,222
                      

 

F-18


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate of 35% to pretax income (loss) from continuing operations as a result of the following:

 

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

Income tax expense (benefit) at the federal statutory rate

   $ (1,461 )   $ (2,088 )   $ 13,659

State income taxes, net of federal tax effect

     (24 )     (187 )     593

Non-deductible stock-based compensation

     1,185       1,392       797

Other, net

     (20 )     8       173
                      

Income tax expense (benefit)

   $ (320 )   $ (875 )   $ 15,222
                      

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at December 31, 2004 and 2005 are presented below:

 

     December 31,  
     2004     2005  
     (in thousands)  

Current:

    

Deferred tax assets:

    

Derivative instruments

   $ 1,438     $ 10,751  

Accrued employee bonus

     909       —    

Other

     (157 )     (273 )
                

Total current deferred tax assets

   $ 2,190     $ 10,478  
                

Long-term:

    

Deferred tax assets:

    

Net operating loss carryforward

   $ 15,155     $ 30,323  

Start-up/organization costs, net

     431       229  

Long-term derivative instruments

     658       2,587  

Stock-based compensation

     354       324  

Deferred rent

     273       248  

Other

     32       56  
                

Total long-term deferred tax assets

     16,903       33,767  

Deferred tax liabilities:

    

Oil and gas properties

     (13,391 )     (41,534 )

Other

     (431 )     (193 )
                

Total long-term deferred tax liabilities

     (13,822 )     (41,727 )
                

Net long-term deferred tax assets (liabilities)

   $ 3,081     $ (7,960 )
                

At December 31, 2005, the Company had approximately $83.0 million of federal and state tax net operating loss carryforwards which expire through 2025.

Income tax expense (benefit) for the years ended December 31, 2003, 2004 and 2005 differs from the amounts that would be provided by applying the U.S. federal income tax rate to income (loss) before income taxes principally due to stock-based compensation not deductible for income tax purposes and other permanent differences.

 

F-19


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

At December 31, 2005, the Company’s balance sheet reflected net deferred tax assets of $2.5 million, of which $13.3 million pertains to the tax effects of derivative instruments reflected in other comprehensive loss.

9. Stockholders’ Equity

On December 9, 2004, the Company priced its shares to be issued in its initial public offering and began trading on the New York Stock Exchange the following day under the ticker symbol “BBG”. Immediately prior to the initial public offering, a $1.9 million mandatorily convertible note was converted into 455,635 shares of Series A convertible preferred stock (“Series A preferred”), all of the then outstanding shares of Series A preferred and Series B convertible preferred stock (“Series B preferred”) were converted into 2,592,317 and 23,795,362 shares, respectively, of common stock, and the 9,242,648 shares of issued common stock were reverse split into 1,984,303 shares of common stock. Through the initial public offering, the Company sold an additional 14,950,000 shares of common stock to the public at the offering price of $25.00 per share, resulting in total outstanding shares of 43,321,982 immediately following the initial public offering. The Company received $347.3 million in net proceeds after deducting underwriters’ fees and related offering expenses. The proceeds received from the initial public offering were used principally to pay down debt outstanding under our credit facility and the bridge loan.

The Company’s authorized capital structure consists of 75,000,000 shares of $0.001 par value preferred stock and 150,000,000 shares of $0.001 par value common stock. In October 2004, 150,000 shares of $0.001 par value preferred stock were designated as Series A Junior Participating Preferred Stock. At December 31, 2005, the Series A Junior Participating Preferred Stock was the Company’s only designated preferred stock, the remainder of authorized preferred stock being undesignated. Until the date of the Company’s initial public offering, 6,900,000 shares were designated as Series A preferred stock and 52,185,000 shares were designated as Series B preferred stock, both of which were eliminated in December 2004 following the Company’s initial public offering.

Holders of all classes of stock are entitled to vote on matters submitted to stockholders, except that each share of Series A Junior Participating Stock shall entitle the holder thereof to 1,000 votes on all matters submitted to a vote of the Company’s stockholders.

Series A Junior Participating Preferred Stock. There are no issued and outstanding shares of Series A Junior Participating Preferred Stock. The Series A Junior Participating Preferred Stock will be issued pursuant to our shareholder rights plan if a stockholder acquires shares in excess of the thresholds set forth in the plan. The Series A Junior Participating Preferred Stock ranks junior to all series of preferred stock with respect to dividends and specified liquidation events. Dividends on this series are cumulative and do not bear interest, however, no dividend payment, or payment-in-kind, may be made to holders of common stock without declaring a dividend on this series equal to 1,000 times the aggregate per share amount declared on common stock. Upon the occurrence of specified liquidation events, the holders of this series shall be entitled to receive an aggregate amount per share equal to 1,000 times the aggregate amount to be distributed per share to holders of shares of common stock plus an amount equal to any accrued and unpaid dividends. Upon consolidation, merger or combination in which shares of common stock are exchanged for or changed into other securities or other assets, each share of this series shall be similarly exchanged into an amount per share equal to 1,000 times that into which each share of common stock is exchanged. The number of Series A Junior Participating Preferred Stock will be proportionately changed in the event the Company declares or pays a common stock dividend or effects a stock split of common stock.

Series A Preferred Stock. Following the Company’s initial public offering, Series A convertible preferred stock was eliminated. Prior to the Company’s initial public offering, Series A preferred consisted of 6,900,000

 

F-20


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

authorized shares with a stated purchase price of $4.17 per share. It ranked senior to the Company’s common stock with respect to dividends and specified liquidation events. Immediately prior to the Company’s initial public offering, 6,594,725 shares of Series A preferred were issued and outstanding and converted into 2,592,317 shares of common stock.

In connection with the early capitalization of the Company, a mandatorily convertible note was issued for $1.9 million, which amount was classified in long-term liabilities, and pursuant to the terms of the note, automatically converted into 455,635 shares of Series A preferred immediately prior to the Company’s initial public offering.

Series B Preferred Stock. Following the Company’s initial public offering, Series B convertible preferred stock was eliminated. Prior to the Company’s initial public offering, 51,951,418 shares were issued and outstanding and converted, along with $35.7 million of its 7% cumulative and unpaid dividends, into 23,795,362 shares of common stock. Immediately prior to the Company’s initial public offering, Series B convertible preferred stock ranked senior to the Company’s Series A preferred and common stock with respect to dividends and specified liquidation events.

In May 2004, the Company received final payment from investors of Series B preferred stock. Pursuant to EITF 98-5, Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios , these issuances resulted in a beneficial conversion (deemed dividend) since the shares were issued with nondetachable conversion features which were deemed to be in-the-money at the commitment date. According to EITF 98-5, we are required to measure, but not record, the deemed dividend at the commitment date if the shares are convertible only upon the occurrence of a future event outside the control of the holder of such securities and contain conversion terms that change upon the occurrence of a future event. We measured deemed dividends of $19.3 million and $11.3 million related to the 2003 and 2004 issuances of convertible Series B preferred stock, respectively. Additionally, pursuant to EITF 00-27, Application of Issue 98-5 to Certain Convertible Instruments , we measured and recorded at the initial public offering date additional deemed dividends of $3.1 million pertaining to the conversion of Series A and B convertible preferred stock into common stock at a discount to the initial public offering price related to the liquidation preference being converted less the underwriters’ fees. Total deemed dividends recorded at the initial public offering date equaled $36.3 million.

In March and April 2004, the Company sold 50,000 and 95,918 shares, respectively, of Series B preferred stock for $5.00 per share to certain of its employees and recorded non-cash stock-based compensation expense accordingly.

Common Stock. On January 30, 2002, the Company issued, subject to restrictions and adjusted for the 1-for-4.658 reverse stock split on the Company’s initial public offering date, 1,800,548 shares of common stock to founding management and employees. On March 28, 2002, these common stockholders entered into a stockholders’ agreement to restrict ownership of the shares with the following dual vesting provisions: (1) one share vesting for every $141.62355 received from investors in Series B Preferred Stock (“dollar vesting”), and (2) 20% vesting upon purchase and an additional 20% vesting each year for four years after purchase (“time vesting”). These management shares vest at the later to occur of time vesting and dollar vesting. Vesting ceases upon the occurrence of a liquidation event with respect to the Company, as defined in the agreement, or the sale of the Company. At each measurement date (the date the Company received funds from the investors in Series B preferred, i.e., the shares dollar vested), compensation expense was determined based on the then known number of shares that had dollar vested and, to the extent those shares were time vested, stock-based compensation expense was immediately recorded. The remaining charge was recorded as deferred compensation within stockholders’ equity and amortized over the remaining time vesting service period in accordance with FIN No. 28, Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans .

 

F-21


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Of the 1,800,548 common shares issued to founding management and employees, 100% of the shares were dollar vested and 1,778,710 and 1,516,661 shares were time vested as of December 31, 2005 and 2004, respectively. The remaining time vesting will occur ratably through January 2006.

Treasury Stock. In 2005, certain employees paid for the exercise cost of stock options through the transfer of shares of the Company’s common stock to the Company at market prices. As of December 31, 2005 the Company held 124,024 shares of common shares as treasury stock at a cost of $5.2 million.

The following table reflects the activity in the Company’s common, preferred, and treasury stock. All common stock amounts reflect the reverse split that occurred in conjunction with our initial public offering.

 

     Year Ended December 31,
     2003    2004     2005

Series A Preferred Stock Outstanding:

       

Shares at beginning of period

   6,258,994    6,258,994     —  

Shares returned in settlement to terminate an exploration agreement

   —      (119,904 )   —  

Shares issued upon conversion of convertible note payable

   —      455,635     —  

Shares converted into common stock immediately prior to initial public offering

   —      (6,594,725 )   —  
               

Shares at end of period

   6,258,994    —       —  
               

Series B Preferred Stock Outstanding:

       

Shares at beginning of period

   21,100,000    45,145,700     —  

Shares issued under Stock Purchase Agreement dated March 28, 2002

   23,300,000    6,600,000     —  

Shares issued for cash under Bill Barrett Corporation Employee Restricted Stock Purchase Plan

   495,100    145,918     —  

Shares issued for mineral leasehold interests

   250,600    59,800     —  

Shares converted into common stock immediately prior to initial public offering

   —      (51,951,418 )   —  
               

Shares at end of period

   45,145,700    —       —  
               

Common Stock Outstanding:

       

Shares at beginning of period

   1,800,548    1,857,477     43,323,270

Exercise of common stock options

   56,929    128,135     366,664

Shares issued for nonvested equity shares of common stock

   —      —       5,352

Fractional shares after reverse split paid in cash

   —      (21 )   —  

Shares issued upon conversion of Series A preferred stock

   —      2,592,317     —  

Shares issued upon conversion of Series B preferred stock and Series B cumulative dividends

   —      23,795,362     —  

Shares issued upon initial public offering

   —      14,950,000     —  
               

Shares at end of period

   1,857,477    43,323,270     43,695,286
               

Treasury Stock:

       

Shares at beginning of period

   —      —       —  

Treasury stock acquired

   —      —       124,024
               

Shares at end of period

   —      —       124,024
               

 

F-22


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Accumulated Other Comprehensive Loss. The Company follows the provisions of SFAS No. 130, Reporting Comprehensive Income , which establishes standards for reporting comprehensive income. The components of accumulated other comprehensive loss and related tax effects for the years ended December 31, 2003, 2004 and 2005 were as follows:

 

     Gross    

Tax

Effect

   

Net of

Tax

 
     (in thousands)  

Accumulated other comprehensive loss—December 31, 2002

   $ (552 )   $ 204     $ (348 )

Change in fair value of hedges

     (6,986 )     2,585       (4,401 )

Reclassification adjustment for realized losses on hedges included in net loss

     552       (204 )     348  
                        

Accumulated other comprehensive loss—December 31, 2003

     (6,986 )     2,585       (4,401 )

Change in fair value of hedges

     (5,665 )     2,096       (3,569 )

Reclassification adjustment for realized losses on hedges included in net loss

     6,986       (2,585 )     4,401  
                        

Accumulated other comprehensive loss—December 31, 2004

     (5,665 )     2,096       (3,569 )

Change in fair value of hedges

     (53,490 )     19,792       (33,698 )

Reclassification adjustment for realized losses on hedges included in net income (loss)

     23,105       (8,549 )     14,556  
                        

Accumulated other comprehensive loss—December 31, 2005

   $ (36,050 )   $ 13,339     $ (22,711 )
                        

10. Common Stock, Stock Options and Other Employee Benefits

As described below, we record non-cash stock-based compensation related to two separate equity awards: restricted common stock and stock option awards. Non-cash stock-based compensation is included in general and administrative expense.

Common Stock. On January 30, 2002, the Company issued, subject to restrictions, 1,800,548 shares of common stock to founding management and employees. On March 28, 2002, these common stockholders entered into a stockholders’ agreement to restrict ownership of the shares with the following dual vesting provisions: (1) one share vesting for every $141.62355 received from investors in Series B Preferred Stock (“dollar vesting”), and (2) 20% vesting upon purchase and an additional 20% vesting each year for four years after purchase and continued service with the Company (“time vesting”). The 1,800,548 shares of common stock fully dollar vested in 2004. Vesting ceases upon the occurrence of a liquidation event with respect to the Company, as defined in the agreement, or the sale of the Company. At each measurement date (the date the Company received funds from the investors in Series B preferred, i.e., the shares dollar vested), compensation expense was determined based on the then known number of shares that had dollar vested and, to the extent those shares were time vested, stock-based compensation expense was immediately recorded.

The remaining stock-based compensation expense will be recognized over the remaining time vesting service period in accordance with FIN No. 28. Based on the fair value vested for these common stock issuances, the Company recorded $2.0 million and $0.5 million of stock-based compensation expense in the years ended December 31, 2004 and 2005, respectively; none of the stock-based compensation has been capitalized, and the related tax benefit recognized was less than $0.1 million in each of the respective periods. We will continue to recognize stock-based compensation related to this common stock ratably until January 31, 2006, at which time the shares will be fully vested.

 

F-23


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

A summary of activity for the restricted common stock as of December 31, 2005, and changes during the year then ended, is presented below:

 

     Shares    

Weighted

Average Fair

Value

Nonvested at January 1, 2005

   283,887     $ 3.26

Granted

   —         N/A

Vested

   (262,050 )   $ 1.87

Forfeited or expired

   —         N/A
        

Nonvested at December 31, 2005

   21,837     $ 1.75
        

Stock Options. In January 2002, the Company adopted a stock option plan to benefit key employees, directors and non-employees. This plan was amended and restated in its entirety by the Amended and Restated 2002 Stock Option Plan (the “2002 Option Plan”). The aggregate number of shares which the Company may issue under the 2002 Option Plan may not exceed 1,642,395 shares of the Company’s common stock. Under the 2002 Option Plan, up to 1,180,807 shares are designated as Tranche A and up to 461,588 shares are designated as Tranche B. Until our initial public offering, Tranche A options could be granted with an exercise price of not less than $30.28 per share, and Tranche B options could be granted with an exercise price of not less than $0.20551 per share. Options granted under the 2002 Option Plan expire ten years from the grant date. The options are subject to the following time vesting provisions — 40% on the first anniversary of the date of grant and 20% on subsequent anniversaries of the date of grant subject to the acceleration and other specified occurrences also addressed in Note 9. Options granted on or before February 3, 2003 vested 20% on date of grant and 20% on each of the next four anniversaries of the date of grant. Options granted under the 2002 Stock Option Plan were subject to equity vesting provisions by having all options that are outstanding vest proportionately based on the total number of shares of common stock outstanding assuming the conversion of our outstanding Series A and Series B preferred stock. As of May 12, 2004, all options under the 2002 Stock Option Plan were equity vested.

For options granted before October 1, 2004, on each measurement date (principally, the dates the Company received funds from the investors in Series B, i.e., the shares equity vest), compensation expense was determined based on the then known number of options that had equity vested and to the extent those options were time vested, stock-based compensation expense was immediately recorded. The remaining charge was recorded as deferred compensation within stockholders’ equity and amortized over the remaining time vesting service period in accordance with FIN No. 28.

Concurrent with our initial public offering on December 9, 2004, we offered to the 62 employees and directors that held Tranche A options an exchange of their options for new Tranche A options equal in number to 92.6% of their original Tranche A options with a new exercise price equal to the initial public offering price of $25.00 per share and an expiration date of December 9, 2011. The vesting of the exchanged options did not change. All employees accepted this exchange ratio based on a fair value neutral exchange computed using a Black-Scholes model and, as such, the Company recorded no additional stock-based compensation expense.

In December 2003, the Company adopted its 2003 Stock Option Plan (the “2003 Option Plan”) to benefit key employees, directors and non-employees. In April 2004, the 2003 Option Plan was approved by the Company’s stockholders. The aggregate number of shares which the Company may issue under the 2003 Option Plan may not exceed 42,936 shares of the Company’s common stock. Options granted under the 2003 Option Plan expire ten years from the date of grant with an exercise price not less than 100% of the fair market value, as defined in the 2003 Option Plan, of the underlying common shares on the date of grant. Options granted under the 2003 Option Plan vest 25% on the first anniversary of the date of grant, and 25% on each of the next three anniversaries of the date of grant.

 

F-24


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

On December 1, 2004, our shareholders approved the 2004 Stock Incentive Plan (the “2004 Incentive Plan”) for the purpose of enhancing our ability to attract and retain officers, employees, directors and consultants and to provide such persons with an interest in the Company parallel to our stockholders. The 2004 Incentive Plan provides for the grant of stock options (including incentive stock options and non-qualified stock options) and other awards (including performance units, performance shares, share awards, restricted stock, restricted stock units, and stock appreciation rights, or SARs). The maximum number of award that may be granted under the 2004 Incentive Plan is 4,900,000. In addition, the maximum number of awards granted to a participant in any one year is 1,225,000. Options granted under the 2004 Incentive Plan expire seven years from the date of grant and vest 25% on the first anniversary of the date of grant, and 25% on each of the next three anniversaries of the date of grant. Unless terminated earlier by our board of directors, the 2004 Incentive Plan will terminate on June 30, 2014. Upon an event constituting a “change in control” (as defined in the 2004 Incentive Plan) of the Company, all options will become immediately exercisable in full. In addition, in such an event, performance units will become immediately vested and restrictions on restricted stock awards will lapse.

Our compensation committee may grant awards on such terms, including vesting and payment forms, as it deems appropriate in its discretion, however, no award may be exercised more than 10 years after its grant (five years in the case of an incentive stock option granted to an individual who possesses more than 10% of the total combined voting power of all classes of stock of the Company). The purchase price or the manner in which the exercise price is to be determined for shares under each award will be determined by the compensation committee and set forth in the agreement. However, the exercise price per share under each award may not be less than 100% of the fair market value of a share on the date the award is granted (110% in the case of an incentive stock option granted to an eligible individual who possesses more than 10% of the total combined voting power of all classes of stock of the Company).

Currently, our practice is to issue new shares upon stock option exercise, and we do not expect to repurchase any shares in the open market or issue treasury shares to settle any such exercises. For years ended December 31, 2003, 2004 and 2005, we used no cash to repurchase any stock related to any option exercises.

In accordance with SFAS No. 123(R), the fair value of each share-based award under all our plans is estimated on the date of grant using a Black-Scholes pricing model that incorporates the assumptions noted in the following table. Because our common stock has only recently become publicly traded, we have estimated expected volatilities based on an average of volatilities of similar sized Rocky Mountain oil and gas companies whose common stock is or has been publicly traded for a minimum of five years and other similar sized oil and gas companies who recently became publicly traded. For options granted when we were a nonpublic company, we adopted the minimum value method under SFAS No. 123, which uses 0% volatility. Given our stage of growth and requirement for capital investment, we used a 0% expected dividend yield, which is comparable to most of our peers in the industry. The expected term ranges from 1.25 years to 5.0 years based on the 25% on each anniversary date after grant vesting period and factoring in potential blackout dates and historic exercises, with a weighted average of 2.9 years. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect on the date of grant. We estimated a 4% annual compounded forfeiture rate based on historical employee turnover.

 

     Year Ended
December 31,
 
     2003     2004     2005  

Weighted Average Volatility

   0 %   37 %   39 %

Expected Dividend Yield

   0 %   0 %   0 %

Weighted Average Expected Term (in years)

   4.0     3.0     2.9  

Weighted Average Risk-free Rate

   2.5 %   3.1 %   3.7 %

 

F-25


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

A summary of share-based option activity under all our plans as of December 31, 2005, and changes during the year then ended, is presented below:

 

     Shares    

Weighted-average

Exercise Price

  

Weighted-average

remaining

contractual term

  

Aggregate

intrinsic value

Outstanding at January 1, 2005

   2,481,427     $ 21.96      

Granted

   266,700       32.26      

Exercised

   (366,664 )     19.50      

Forfeited or expired

   (46,865 )     22.84      
              

Outstanding at December 31, 2005

   2,334,598     $ 23.51    5.92    $ 35,287,205
              

Exercisable at December 31, 2005

   880,685     $ 23.13    5.83    $ 13,630,416

The per share weighted-average grant-date fair value of awards granted for the years ended December 31, 2003, 2004 and 2005 was $1.31, $7.11 and $9.54, respectively, and the total intrinsic value of awards exercised during the same periods was $0.3 million, $1.5 million and $6.9 million, respectively. Related to stock option exercises, we received less than $0.1 million in each of the years ended December 31, 2003 and 2004 and $3.0 million for the year ended December 31, 2005. The related tax benefit was nominal for the years ended December 31, 2003 and 2004. For the year ended December 31, 2005, the Company recognized a tax benefit of $1.2 million. In addition, no cash was used to settle stock option exercises for the years ended December 31, 2003, 2004, and 2005.

A summary of the Company’s nonvested equity shares of common stock as of December 31, 2005, and changes during the year then ended, is presented below:

 

     Shares    

Weighted-average

Grant Date Fair

Value

Outstanding at January 1, 2005

   —       $ 0.00

Granted

   5,352       32.70

Exercised

   (612 )     32.70

Forfeited or expired

   —         —  
        

Outstanding at December 31, 2005

   4,740     $ 32.70
        

Exercisable at December 31, 2005

   —       $ —  

We recorded non-cash stock-based compensation related to awards of $3.6 million, $3.0 million, and $3.2 million for the years ended December 31, 2003, 2004 and 2005, respectively. Included in the $3.2 million of stock-based compensation for the year ended December 31, 2005 is $0.3 million related to the modification of equity awards for certain employees in which their vesting terms were accelerated. None of the stock-based compensation has been capitalized, and the related tax benefit recognized was less than $0.1 million for the years ended December 31, 2003 and 2004. For the year ended December 31, 2005, the Company recognized a tax benefit of $1.2 million that was charged to stockholder’s equity for the exercise of stock options. As of December 31, 2005, there was $7.3 million of total compensation costs related to nonvested stock option and nonvested equity shares of common stock grants that is expected to be recognized over a weighted-average period of 3.0 years.

Other Employee Benefits-401(k) Savings. The Company has an employee directed 401(k) savings plan (the “401(k) Plan”) for all eligible employees over the age of 21. Employees become eligible the quarter following the beginning of their employment. Under the 401(k) Plan, employees may make voluntary contributions based

 

F-26


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

upon a percentage of their pretax income. Through December 31, 2005, the Company matched 100% of the employee contribution, up to 4% of the employee’s pretax income. The Company made matching cash contributions of $0.2 million, $0.4 million, and $0.6 million for the years ended December 31, 2003, 2004 and 2005 respectively.

Beginning on January 1, 2006, the Company amended the 401(k) Plan to match 100% of the employee contribution, up to 6% of the employee’s pretax income, with 50% of the match made with the Company’s common stock. Shares of common stock are fully vested upon the date of match.

11. Transactions with Related Parties

A director of the Company is a principal at a company affiliated with the lead arranger and agent for the credit facilities noted in Note 5 above and the company that was an underwriter in our initial public offering.

A director of the Company is a managing director of a company affiliated with the company which wholly owns the counterparty to the natural gas swaps noted in Note 7 above, the company that was the sole lead arranger and administrative agent for the senior subordinated credit and guaranty agreement as discussed in Note 5 above, and the company that was the lead underwriter in our initial public offering.

In management’s opinion, the terms obtained in the above transactions were provided on terms at least as favorable to the Company as could be obtained from non-related sources.

12. Significant Customers and Other Concentrations

Significant Customers. During 2003, ONEOK Inc. accounted for 38.6% and two wholly-owned subsidiaries of Xcel Energy Inc., the names of which are Public Service Co. of Colorado and Cheyenne Light, Fuel and Power Co., accounted for a total of 10.2% of the Company’s oil and gas production revenues. During 2004, ONEOK Inc. accounted for 37.5% of the Company’s oil and gas production revenues. During 2005, ONEOK Inc., Xcel Energy Inc., and OGE Energy Resources Inc. accounted for 20.3%, 10.3%, and 10.0%, respectively, of the Company’s oil and gas production revenues. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

Concentrations of Market Risk. The future results of the Company’s oil and gas operations will be affected by the market prices of oil and gas. The availability of a ready market for crude oil, natural gas and liquid products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil, gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

The Company operates in the exploration, development and production phase of the oil and gas industry. Its receivables include amounts due from purchasers of oil and gas production and amounts due from joint venture partners for their respective portions of operating expense and exploration and development costs. The Company believes that no single customer or joint venture partner exposes the Company to significant credit risk. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the natural gas or oil industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations in the long-term. Trade receivables are generally not collateralized. The Company analyzes customers’ and joint venture partners’ historical credit positions and payment history prior to extending credit.

 

F-27


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Concentrations of Credit Risk. Derivative financial instruments that hedge the price of oil and gas are generally executed with major financial or commodities trading institutions which expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. The credit worthiness of counterparties is subject to continuing review and full performance is anticipated. The Company’s policy is to execute financial derivatives only with major financial institutions.

13. Commitments and Contingencies

Transportation Demand and Firm Processing Charges . The Company has entered into contracts which provide firm transportation capacity and processing rights on pipeline systems. The remaining terms on these contracts range from 1 to 13 years and require the Company to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by the Company. The Company paid $0.5 million and $1.7 million of transportation demand charges for the years ended December 31, 2004 and 2005, respectively. There were no firm processing charges paid in 2005 or in years prior, and there were no transportation demand charges paid prior to 2004. All transportation costs including demand charges are included in gathering and transportation expense in the Consolidated Statement of Operations.

Future minimum transportation demand and firm processing charges as of and subsequent to December 31, 2005 are as follows (in thousands):

 

2006

   $ 5,025

2007

     5,622

2008

     14,866

2009

     17,193

2010

     17,604

Thereafter

     134,615
      

Total

   $ 194,925
      

Lease Obligations and Other Commitments. The Company leases office space and certain equipment under non-cancelable operating leases. Office lease expense for the years ended December 31, 2003, 2004 and 2005 was $0.5 million, $0.8 million and $0.9 million, respectively. Additionally, the Company has entered into various long-term agreements for telecommunication service. The Company also has commitments for developing oil and gas properties of $19.9 million, $22.3 million, and $2.3 million for 2006, 2007, and 2008, respectively, which is included in the minimum payment schedule below.

Future minimum annual payments under such leases and agreements as of and subsequent to December 31, 2005 are as follows (in thousands):

 

    

Other

Commitments

  

Office &

Equipment

Leases

2006

   $ 19,920    $ 1,273

2007

     22,265      1,535

2008

     2,345      1,476

2009

     —        1,469

2010

     —        1,521

Thereafter

     —        378
         

Total

   $ 44,530    $ 7,652
             

 

F-28


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

In addition to the commitments above, the Company has commitments for the purchase of facilities equipment as of and subsequent to December 31, 2005 for a total of $39.0 million.

14. Supplementary Oil and Gas Information (unaudited)

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion per equivalent unit-of-production were as follows:

 

     Year Ended December 31,
     2003    2004    2005
     (in thousands, except
amortization data)

Acquisition costs:

        

Unproved properties

   $ 17,581    $ 73,469    $ 25,689

Proved properties

     30,979      79,440      1,288

Exploration costs

     41,846      98,751      218,586

Development costs

     94,637      93,304      95,236

Asset retirement obligation

     2,936      7,153      10,650
                    

Total costs incurred

   $ 187,979    $ 352,117    $ 351,449
                    

Amortization per Mcfe of production

   $ 1.63    $ 2.12    $ 2.20

Supplemental Oil and Gas Reserve Information. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2003, 2004, and 2005 that were prepared by internal petroleum engineers in accordance with guidelines established by the Securities and Exchange Commission and were reviewed by Ryder Scott Company and Netherland, Sewell & Associates, Inc., independent petroleum engineering firms.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

 

F-29


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Analysis of Changes in Proved Reserves. The following table sets forth information regarding the Company’s estimated net total proved and proved developed oil and gas reserve quantities, excluding reserves for oil and gas properties held for sale:

 

    

Oil

(MBbls)

   

Gas

(MMcf)

 

Proved reserves:

    

Balance, December 31, 2002

   2,884     101,775  

Purchases of oil and gas reserves in place

   918     31,798  

Extension, discoveries and other additions

   754     100,024  

Revisions of previous estimates

   (342 )   (33,902 )

Sales of reserves

   —       (2,506 )

Production

   (328 )   (16,315 )
            

Balance, December 31, 2003

   3,886     180,874  

Purchases of oil and gas reserves in place

   201     48,949  

Extension, discoveries and other additions

   1,846     87,098  

Revisions of previous estimates

   440     (28,490 )

Sales of reserves

   (161 )   (1,691 )

Production

   (474 )   (28,864 )
            

Balance, December 31, 2004

   5,738     257,876  
            

Purchases of oil and gas reserves in place

   5     3,274  

Extension, discoveries and other additions

   4,292     91,614  

Revisions of previous estimates

   (3,676 )   (9,989 )

Sales of reserves

   (2 )   (517 )

Production

   (523 )   (36,286 )
            

Balance, December 31, 2005

   5,834     305,972  
            

Proved developed reserves:

    

December 31, 2003

   3,166     108,569  

December 31, 2004

   4,249     153,118  

December 31, 2005

   4,283     182,777  

Standardized Measure. Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities . Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

Future cash inflows are computed by applying year-end prices of oil and gas relating to the Company’s proved reserves to the year-end quantities of those reserves. Year-end calculations were made using prices of $32.98, $43.46 and $61.04 per Bbl for oil and $5.81, $5.52, and $7.72 per Mcf for gas for 2003, 2004, and 2005, respectively. The Company also records an overhead expense of $100 per month per operated well in the calculation of its future cash flows.

The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

 

F-30


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.

A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves.

 

     December 31,  
     2003     2004     2005  
     (in thousands)  

Future cash inflows

   $ 1,179,562     $ 1,722,369     $ 2,882,165  

Future production costs

     (281,355 )     (502,269 )     (638,004 )

Future development costs

     (112,452 )     (211,464 )     (362,424 )

Future income taxes

     (176,850 )     (223,884 )     (487,992 )
                        

Future net cash flows

     608,905       784,752       1,393,745  

10% annual discount

     (204,085 )     (318,643 )     (611,267 )
                        

Standardized measure of discounted future net cash flows

   $ 404,820     $ 466,109     $ 782,478  
                        

A summary of changes in the standardized measure of discounted future net cash flows is as follows:

 

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

Standardized measure of discounted future net cash flows, beginning of period

   $ 153,548     $ 404,820     $ 466,109  

Sales of oil and gas, net of production costs and taxes

     (61,017 )     (137,606 )     (243,717 )

Extensions, discoveries and improved recovery, less related costs

     268,258       237,683       303,751  

Quantity revisions

     (116,979 )     (70,074 )     (130,275 )

Price revisions

     128,745       (22,382 )     396,299  

Net changes in estimated future development costs

     (1,625 )     9,316       (25,191 )

Accretion of discount

     17,866       52,082       59,206  

Purchases of reserves in place

     50,717       83,171       11,260  

Sales of reserves

     (3,650 )     (4,535 )     (1,138 )

Changes in production rates (timing) and other

     59,852       (76,425 )     87,349  

Net changes in future income taxes

     (90,895 )     (9,941 )     (141,175 )
                        

Standardized measure of discounted future net cash flows, end of period

   $ 404,820     $ 466,109     $ 782,478  
                        

 

F-31


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

15. Quarterly Financial Data (unaudited)

The following is a summary of the unaudited financial data for each quarter presented. The income (loss) before income taxes, net income (loss), and net income (loss) per common share for each of the quarters for the years ended December 31, 2004 and 2005.

 

     First
Quarter
   Second
Quarter
    Third
Quarter
    Fourth
Quarter
 
     (in thousands, except per share data)  

Year ended December 31, 2004:

         

Total revenues

   $ 36,441    $ 42,399     $ 42,675     $ 48,465  

Income (loss) before income taxes

     8,187      5,251       (6,103 )     (13,476 )

Net income (loss)

     4,737      3,035       (3,940 )     (9,098 )

Net income (loss) per common share, basic

     0.01      (0.03 )     (6.08 )     (4.33 )

Net income (loss) per common share, diluted

     0.01      (0.03 )     (6.08 )     (4.33 )

 

     First
Quarter
   Second
Quarter
    Third
Quarter
   Fourth
Quarter
     (in thousands, except per share data)

Year ended December 31, 2005:

          

Total revenues

   $ 51,906    $ 54,449     $ 71,237    $ 111,167

Income (loss) before income taxes

     5,305      (24,765 )     20,555      37,932

Net income (loss)

     3,054      (15,871 )     13,297      23,325

Net income (loss) per common share, basic

     0.07      (0.37 )     0.31      0.54

Net income (loss) per common share, diluted

     0.07      (0.37 )     0.30      0.53

 

F-32

Exhibit 10.19

BILL BARRETT CORPORATION

STOCK OPTION AGREEMENT

(2004 Stock Option Plan—Incentive Stock Options)

THIS STOCK OPTION AGREEMENT (the “Agreement”) is made and entered into as of the “Grant Date” listed on Exhibit 1 (the “Date of Grant”) by and between Bill Barrett Corporation, a Delaware corporation (the “Company”), and the person listed as “Granted To” on Exhibit 1 (the “Optionee”).

WITNESSETH:

WHEREAS, effective as of Date of Grant, the Optionee received a stock option to purchase shares of the Company’s Common Stock pursuant to the Company’s 2004 Stock Incentive Plan (as amended, restated or otherwise modified from time to time, the “2004 Plan”) in order to provide the Optionee with an opportunity for investment in the Company and additional incentive to pursue the success of the Company, and this option is to be for the number of shares, at the price per share and on the terms set forth in this Agreement;

WHEREAS, pursuant to the 2004 Plan the Company may issue options and other equity interests covering up to 4,900,000 shares of Common Stock;

WHEREAS, the Company intends that the stock option granted pursuant to this Agreement qualify as an incentive stock option (an “Incentive Option”) to the full extent permitted pursuant to Section 422 of the Internal Revenue Code of 1986, as amended (the “Code”), and that to the extent the stock option does not qualify as an Incentive Stock Option, it shall be considered a non-qualified stock option (a “Non-Qualified Option”); and

WHEREAS, the Optionee desires to receive an option on the terms and conditions set forth in this Agreement.

NOW, THEREFORE, the parties agree as follows:

1. Grant Of Option . The Company hereby grants to the Optionee, as a matter of separate agreement and not in lieu of salary or any other compensation for services, the right and option (the “Option”) to purchase all or any part of an aggregate of the “Number of Shares” listed on Exhibit 1 of the authorized and unissued $.001 par value common stock of the Company (the “Option Shares”) pursuant to the terms and conditions set forth in this Agreement.

2. Option Price . At any time when shares are to be purchased pursuant to the Option, the purchase price for each Option Share shall be the “Exercise Price Per Share” listed on Exhibit 1 (the “Option Price”).

3. Exercise Period .

(a) The exercise period shall commence on the Date of Grant and terminate at 5:00 p.m., Denver, Colorado time, on the “Option Expiration Date” listed on Exhibit 1, unless earlier terminated as provided in this Agreement. The number of Option Shares that may be purchased upon the exercise of a portion of the Option at any time during the exercise period shall be equal to the number of Option Shares for which Time Vesting (as described in Section 3(b) below) has occurred, reduced by the number of Option Shares previously purchased upon the exercise of a portion of the Option. No portion of the Option shall be exercisable except to the extent that Time Vesting described in Section 3(b) has occurred.


(b) “Time Vesting” shall occur based on the following schedule so that on each date set forth under the column “Date”, Time Vesting shall have occurred with respect to the percentage of the total number of Option Shares subject to the Option set forth under the column “Time Vested Portion Of Option”:

 

Date

   Time Vested Portion Of Option  

First Anniversary of Date of Grant

   25 %

Second Anniversary of Date of Grant

   50 %

Third Anniversary of Date of Grant

   75 %

Fourth Anniversary of Date of Grant

   100 %

Notwithstanding the foregoing, the Option shall become fully Time Vested upon a Change In Control (as defined in the Plan) or immediately prior thereto to the extent set forth in the Plan if but only if the Optionee is employed by the Company or any of its subsidiaries immediately prior to such Change In Control.

(c) The Option shall be considered an Incentive Option to the full extent permitted pursuant to Section 422 of the Code. To the extent that the Option does not qualify as an Incentive Option, it shall be considered a Non-Qualified Option. Optionee acknowledges and agrees that the Company is making no representation or warranty that this Option qualifies as an Incentive Option and that the Company is not obligated to take any action or refrain from taking any action in order to cause this Option to qualify or continue to qualify as an Incentive Option.

4. Exercise Of Option.

(a) To the extent exercisable pursuant to Section 3(a), the Option may be exercised in whole or in part by delivering to the Treasurer of the Company (i) notice of exercise of option (which shall be in the form prescribed by the Company and which may be modified at any time by the Company in its discretion), specifying the number of Option Shares with respect to which the Option is exercised, and (ii) full payment, in the manner described in Section 5 of this Agreement, of the Option Price for such shares. The Option may not be exercised in part unless the purchase price for the Option Shares purchased is at least $1,000 or unless the entire remaining vested portion of the Option is being exercised. In addition, if the Stockholders’ Agreement is in effect at the time of the Optionee’s exercise of the Option, the Optionee shall sign and deliver to the Company a counterpart of the Stockholders’ Agreement as then in effect.

(b) Promptly upon receipt of the Notice And Agreement Of Exercise Of Option together with the full payment of the Option Price, and a counterpart of the Stockholders’ Agreement signed by the Optionee, if applicable, the Company shall deliver to the Optionee a properly executed certificate or certificates representing the Option Shares being purchased.

(c) During the lifetime of the Optionee, the Option shall be exercisable only by the Optionee; provided, that in the event of the death of the Optionee, the personal representative or estate of the Optionee may exercise the Option; provided, further, that in the event of the legal disability of the Optionee, the guardian or personal representative of the Optionee may exercise the Option if such guardian or personal representative obtains a ruling from the Internal Revenue Service or an opinion of counsel to the effect that neither the grant nor the exercise of such power is violative of Section 422(b)(5), or its successor provision, of the Internal Revenue Code of 1986, as amended (the “Code”). Any opinion of counsel must be acceptable to the Option Committee both with respect to the counsel rendering the opinion and with respect to the form of opinion.

 

(d)

(1) If for any reason (other than the termination of Optionee’s employment because of Optionee’s death or legal disability or the termination of Optionee’s employment by the Company for Cause (as defined in the Plan)), the Optionee ceases to be employed by the Company, then the Option may be

 

2


 

exercised within three (3) months after such termination of the Optionee’s employment, or, if the Optionee dies during the three-month period immediately following such termination, within one year after Optionee’s death, but, in each case, to the extent that (A) the Option was exercisable pursuant to Section 3(a) on the date of termination of the Optionee’s employment, and (B) the period for exercise of the Option, as set forth in Section 3(b), has not terminated as of the date of exercise. Upon termination of the respective periods set forth in the previous sentence, any unexercised portion of an Option shall expire.

(2) If the Optionee’s employment with the Company is terminated because of the Optionee’s death or legal disability, the Option may be exercised within one (1) year after termination, but only to the extent that (A) the Option was exercisable pursuant to Section 3(a) on the date of termination of the Optionee’s employment, and (B) the period for exercise of the Option, as set forth in Section 3(b), has not terminated as of the date of exercise. Upon termination of the respective periods set forth in the previous sentence, any unexercised portion of an Option shall expire.

(3) If the Optionee’s employment by the Company is terminated for Cause (as defined in the Plan), (A) the Option shall expire upon delivery to the Optionee of notice of termination, which may be oral or in writing, and all rights to purchase shares pursuant to the Option shall terminate immediately, and (B) at the Company’s option, all Option Shares acquired by Optionee shall be immediately forfeit without any action on the part of the Company or Optionee, and the Company shall promptly reimburse Optionee the aggregate purchase price actually paid by Optionee for such Option Shares (excluding any Common Stock or conversion of Option Shares used as payment for such purchase price).

5. Payment For Option Shares . If payment for the Option Price is made other than by a method described in Sections 5(a), 5(b) or 5(c), the Option Price shall be paid in cash, certified funds, or Optionee’s check. Payment shall be considered made when the Treasurer of the Company receives delivery of the payment at the Company’s address, provided that a payment made by check is honored when first presented to the Optionee’s bank. Payment for the exercise of an Option may be made pursuant to the following methods:

(a) If the Option Price of the Option Shares purchased by Optionee at any one time exceeds $1,000, the Company, in its sole discretion, upon request by Optionee, may permit all or part of the Option Price to be paid by delivery to the Company for cancellation shares of Common Stock previously owned by Optionee (“Previously Owned Shares”) with a Fair Market Value (as defined in the Plan) as of the date of the payment equal to the portion of the Option Price for the Option Shares that Optionee does not pay in cash. Notwithstanding the above, Optionee may be permitted to exercise the Option by delivering Previously Owned Shares only if (i) Optionee has held, and provides appropriate evidence of such, the Previously Owned Shares for more than six months prior to the date of exercise, or (ii) the Previously Owned Shares were acquired by Optionee in an arm’s length, open market transaction, or (iii) the Previously Owned Shares consist of a combination of shares meeting the criteria described in either of the immediately preceding clauses (i) and (ii). This period described in clause (i) of the preceding sentence (the “Holding Period”) may be extended by the Company acting in its sole discretion as is necessary, in the opinion of the Company, so that, under generally accepted accounting principles, no compensation shall be considered to have been or to be paid to Optionee as a result of the exercise of the Option in this manner. At the time the Option is exercised, Optionee shall provide an affidavit, and such other evidence and documents as the Company shall request, to establish that the requirements of clauses (i), (ii) or (iii) above have been satisfied. As indicated above, Optionee may deliver shares of Common Stock as part of the purchase price only if the Company, in its sole discretion, agrees, on a case by case basis, to permit this form of payment.

(b) Optionee also may pay the Option Price by delivering to the Company and to a broker-dealer, which broker-dealer shall be subject to approval by the Option Committee at the Option Committee’s sole discretion, a written notice of exercise, in the form prescribed by the Option Committee, together with the Optionee’s irrevocable instructions to the broker-dealer to promptly deliver to the Company certified funds

 

3


representing the Option Price, which certified funds may be the result of the broker-dealer’s sale of some or all of the Option Shares received upon exercise or the result of a loan from the broker-dealer to the Optionee.

(c) The Company, in its sole discretion, upon request by Optionee, may permit Optionee to convert a portion of the Option into Option Shares (the “Conversion Shares”) in the manner provided in this Section 5(c). In the event that Optionee elects to convert a portion of the Option into Conversion Shares, Optionee shall assign to the Company and convert into Conversion Shares the portion of the Option that represents the right to purchase Option Shares that have an aggregate Option Fair Market Value (determined in accordance with this Section 5(c)) equal to Exercise Price for the Conversion Shares. The Option Fair Market Value on a particular date for each Option Share issuable upon the exercise of the Option shall be equal to the amount by which the Fair Market Value (as determined in accordance with the 2004 Plan) of the Option Share on that date exceeds the Option Price for that Option Share. In order to exercise Optionee’s right to convert pursuant to this Section 5(c), Optionee shall deliver to the Company such notices and documents as the Company shall request setting forth the number of Conversion Shares to be issued upon conversion and the number of Option Shares underlying the Option to be surrendered therefor. As indicated above, Optionee may convert a portion of the Options into Conversion Shares only if the Company, in its sole discretion, agrees, on a case by case basis, to permit payment through this conversion.

6. Withholding Taxes . The Company may take such steps as it deems necessary or appropriate for the withholding of any taxes which the Company is required by any law or regulation or any governmental authority, whether federal, state or local, domestic or foreign, to withhold in connection with the Option including, but not limited to, the withholding of all or any portion of any payment owed by the Company to the Optionee or the withholding of issuance of Option Shares to be issued upon the exercise of the Option.

7. Securities and Tax Laws Requirements .

(a) Optionee shall report all sales of Option Shares to the Company in writing on a form prescribed by the Company.

(b) If and so long as Optionee is subject to reporting requirements under Section 16(a) of the 1934 Act, Optionee shall (i) be aware that any sale by Optionee or Optionee’s immediate family of shares of the Company’s common stock or any of the Option Shares within six months before or after any transaction deemed to be a “purchase” of an equity security of the Company may create liability for Optionee under Section 16(b) of the 1934 Act, (ii) consult with Optionee’s counsel regarding the application of Section 16(b) of the 1934 Act prior to any exercise of the Option, and prior to any sale of shares of the Company’s common stock or the Option Shares, (iii) furnish the Company with a copy of each Form 4 filed by Optionee, and (iv) timely file all reports required under the federal securities laws.

(c) Optionee shall immediately notify the Company in writing of any sale, transfer, assignment or other disposition (or action constituting a disqualifying disposition within the meaning of Section 421 of the Code) of any Option Shares, within two (2) years after the Date of Grant or within one (1) year after the acquisition of such Option Shares, setting forth the date and manner of disposition, the number of Option Shares disposed of and the price at which such shares were disposed. The Company shall be entitled to withhold from any compensation or other payments then or thereafter due to the Optionee such amounts as may be necessary to satisfy any withholding requirements of Federal or state law or regulation and, further, to collect from the Optionee any additional amounts which may be required for such purpose. The Company may, in its discretion, require Option Shares acquired by a Optionee upon exercise of the Option to be held in an escrow arrangement for the purpose of enabling compliance with the provisions of this section.

8. Transferability Of Option . No Option shall be transferable by the Optionee otherwise than by will or by the laws of descent and distribution or, in the case of a Non-Qualified Option, pursuant to a domestic relations

 

4


order (within the meaning of Rule 12a-12 promulgated under the Exchange Act), and Options shall be exercisable during the lifetime of an Optionee only by the Optionee or the Optionee’s guardian or legal representative. Notwithstanding the foregoing, with advance written consent of the Company, Non-Qualified Options may be transferred to Permitted Transferees (as defined below) of the Optionee, and for purposes of this Agreement, a Permitted Transferee of an Optionee shall be deemed to be the Optionee. The terms of an Option shall be final, binding and conclusive upon the beneficiaries, executors, administrators, heirs and successors of the Optionee. A “Permitted Transferee” means (i) the spouse of the Optionee, (ii) a trust, or family partnership, the sole beneficiary of which is the Optionee, the spouse of or, any person related by blood or adoption to, the Optionee; provided, that any such transfers to a Permitted Transferee do not conflict with or constitute a violation of state or federal securities laws.

9. Adjustment By Stock Split, Stock Dividend, Etc. In the event that each of the outstanding shares of Common Stock (other than shares held by dissenting stockholders which are not changed or exchanged) of the Company should be changed into, or exchanged for, a different number or kind of shares of stock or other securities of the Company, or if further changes or exchanges of any stock or other securities into which the Common Stock shall have been changed, or for which it shall have been exchanged, shall be made (whether by reason of merger, consolidation, reorganization, recapitalization, stock dividends, reclassification, split-up, combination of shares or otherwise), then the Option Shares shall be subject to adjustment as provided in the Plan.

10. Change in Control; Subsequent Change in Control . In the event of a Change in Control or a Subsequent Change in Control (each as defined in the Plan), the Option and the Option Shares shall be governed by the provisions of Section 20 of the Plan.

11. Common Stock To Be Received Upon Exercise . Optionee understands that the Company is under no obligation to register the issuance of the Option Shares or the resale of the Option Shares under the Securities Act of 1933, as amended (the “Act”), and that in the absence of any such registration, the Option Shares cannot be sold unless they are sold pursuant to an exemption from registration under the Act. The Company is under no obligation to comply, or to assist the Optionee in complying, with any exemption from such registration requirement, including supplying the Optionee with any information necessary to permit routine sales of the Option Shares under Rule 144 of the Securities and Exchange Commission. Optionee also understands that with respect to Rule 144, routine sales of securities made in reliance upon such Rule can be made only in limited amounts in accordance with the terms and conditions of the Rule, and that in cases in which the Rule is inapplicable, compliance with either Regulation A or another disclosure exemption under the Act will be required. Thus, the Option Shares will have to be held indefinitely in the absence of registration under the Act or an exemption from registration.

Furthermore, the Optionee fully understands that issuance of the Option Shares may not be registered under the Act and that if their issuance is not registered, they will be issued in reliance upon an exemption which is available only if Optionee acquires such shares for investment and not with a view to distribution. Optionee is familiar with the phrase “acquired for investment and not with a view to distribution” as it relates to the Act and the special meaning given to such term in various releases of the Securities And Exchange Commission.

12. Privilege Of Ownership . Optionee shall not have any of the rights of a stockholder with respect to the shares covered by the Option except to the extent that one or more certificates for such shares shall be delivered to him upon exercise of the Option.

13. Relationship To Employment Or Position . Nothing contained in this Agreement (i) shall confer upon the Optionee any right with respect to continuance of Optionee’s employment by, or position or affiliation with, or relationship to, the Company, or (ii) shall interfere in any way with the right of the Company at any time to terminate the Optionee’s employment by, position or affiliation with, or relationship to, the Company.

 

5


14. Notices . All notices, requests, demands, directions and other communications (“Notices”) concerning this Agreement shall be in writing and shall be mailed or delivered personally or sent by telecopier or facsimile to the applicable party at the address of such party set forth below in this Section 14. When mailed, each such Notice shall be sent by first class, certified mail, return receipt requested, enclosed in a postage prepaid wrapper, and shall be effective on the fifth business day after it has been deposited in the mail. When delivered personally, each such Notice shall be effective when delivered to the address for the respective party set forth in this Section 14, provided that it is delivered on a business day and further provided that it is delivered prior to 2:00 p.m., local time of the party to whom the notice is being delivered, on that business day; otherwise, each such Notice shall be effective on the first business day occurring after the Notice is delivered. When sent by telecopier or facsimile, each such Notice shall be effective on the day on which it is sent provided that it is sent on a business day and further provided that it is sent prior to 2:00 p.m., local time of the party to whom the Notice is being sent, on that business day; otherwise, each such Notice shall be effective on the first business day occurring after the Notice is sent. Each such Notice shall be addressed to the party to be notified as shown below:

 

(a) if to the Company:

Bill Barrett Corporation

1099 18th Street

Suite 2300

Denver, Colorado 80202

Facsimile No. (303) 291-0420

Attention: Treasurer

 

(b) if to the Optionee:

Address of file with Company’s payroll records

Either party may change its respective address for purposes of this Section 14 by giving the other party Notice of the new address in the manner set forth above.

15. General Provisions . This instrument (a) contains the entire agreement between the parties, (b) may not be amended nor may any rights hereunder be waived except by an instrument in writing signed by the party sought to be charged with such amendment or waiver, (c) shall be construed in accordance with, and governed by the laws of the state in which the Company is then incorporated, and (d) shall be binding upon and shall inure to the benefit of the parties and their respective personal representatives and assigns, except as above set forth. All pronouns contained herein and any variations thereof shall be deemed to refer to the masculine, feminine or neuter, singular or plural as the identity of the parties hereto may require.

 

6

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-121642 and 333-130787 on Form S-8 and Registration Statement No. 333-131385 on Form S-3 of our reports dated March 1, 2006, relating to the financial statements of Bill Barrett Corporation and subsidiaries (which report expresses an unqualified opinion and includes an explanatory paragraph for the adoption of Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payments”), and management’s report on the effectiveness of internal control over financial reporting appearing in the Annual Report on Form 10-K of Bill Barrett Corporation for the year ended December 31, 2005.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado

March 1, 2006

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references to our firm, in the context in which they appear, and to our reserve estimates as of December 31, 2005, included in the Annual Report on Form 10-K of Bill Barrett Corporation for the fiscal year ended December 31, 2005, as well as in the notes to the financial statements included therein. We also hereby consent to the incorporation by reference of the references to our firm, in the context in which they appear, to our reserve estimates as of December 31, 2005, into Bill Barrett Corporation’s previously filed Registration Statements on Form S-8 (No. 333-121642 and No. 333-130787) and Registration Statement on Form S-3 (No. 333-131385), in accordance with the requirements of the Securities Act of 1933, as amended.

Ryder Scott Company, L.P.

/ S / R YDER S COTT C OMPANY , L.P.

 

Denver, Colorado

March 2, 2006

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references to our firm, in the context in which they appear, and to our reserve estimates as of December 31, 2005, included in the Annual Report on Form 10-K of Bill Barrett Corporation for the fiscal year ended December 31, 2005, as well as in the notes to the financial statements included therein. We also hereby consent to the incorporation by reference of the references to our firm, in the context in which they appear, to our reserve estimates as of December 31, 2005, into Bill Barrett Corporation’s previously filed Registration Statements on Form S-8 (No. 333-121642 and No. 333-130787) and Registration Statement on Form S-3 (No. 333-131385), in accordance with the requirements of the Securities Act of 1933, as amended.

 

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:   / S / F REDERIC D. S EWELL
 

Frederic D. Sewell

Chairman and Chief Executive Officer

Dallas, Texas

March 2, 2006

EXHIBIT 31.1

CERTIFICATION

I, Fredrick J. Barrett, certify that:

 

  1. I have reviewed this annual report on Form 10-K of Bill Barrett Corporation;

 

  2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

  3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

  4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

  a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

 

  c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

  5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

  a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

  b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2006

 

/ S /     F REDRICK J. B ARRETT        

Fredrick J. Barrett

Chairman and Chief Executive Officer

(Principal Executive Officer)

EXHIBIT 31.2

CERTIFICATION

I, Thomas B. Tyree, Jr. , certify that:

 

  1. I have reviewed this annual report on Form 10-K of Bill Barrett Corporation;

 

  2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

  3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

  4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

  a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

 

  c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

  5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

  a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

  b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2006

 

/ S /    T HOMAS B. T YREE , J R .        

Thomas B. Tyree, Jr.

Chief Financial Officer

(Principal Financial Officer)

EXHIBIT 32.1

BILL BARRETT CORPORATION

SARBANES-OXLEY ACT SECTION 906 CERTIFICATION

In connection with this annual report on Form 10-K of Bill Barrett Corporation for the fiscal year ended December 31, 2005, I, Fredrick J. Barrett, Chairman and Chief Executive Officer of Bill Barrett Corporation, hereby certify pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

 

  1. This Form 10-K for the fiscal year ended December 31, 2005 fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

  2. The information contained in this Form 10-K for the fiscal year ended December 31, 2005 fairly presents, in all material respects, the financial condition and results of operations of Bill Barrett Corporation for the periods presented therein.

Date: March 2, 2006

 

/ S /    F REDRICK J. B ARRETT        

Fredrick J. Barrett

Chairman and Chief Executive Officer

(Principal Executive Officer)

EXHIBIT 32.2

BILL BARRETT CORPORATION

SARBANES-OXLEY ACT SECTION 906 CERTIFICATION

In connection with this annual report on Form 10-K of Bill Barrett Corporation for the fiscal year ended December 31, 2005, I, Thomas B. Tyree, Jr., Chief Financial Officer of Bill Barrett Corporation, hereby certify pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

 

  1. This Form 10-K for the fiscal year ended December 31, 2005 fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

  2. The information contained in this Form 10-K for the fiscal year ended December 31, 2005 fairly presents, in all material respects, the financial condition and results of operations of Bill Barrett Corporation for the periods presented therein.

Date: March 2, 2006

 

/ S /    T HOMAS B. T YREE , J R .        

Thomas B. Tyree, Jr.

Chief Financial Officer

(Principal Financial Officer)