Annual Reports

 
Quarterly Reports

 
8-K

 
Other

Bill Barrett 10-K 2006
Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)

 

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

For the fiscal year ended December 31, 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 18th Street, Suite 2300

Denver, Colorado

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

(303) 293-9100

(Registrant’s telephone number, including area code)

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

 

Title of each class

 

Name of each exchange on which registered

Common Stock, $.001 par value

  New York Stock Exchange

Series A Junior Participating Preferred Stock Purchase Rights

  New York Stock Exchange

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. 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 18th 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 CO2 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