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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-K

(Mark one)ý

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2008oro

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period
from                        to


Commission File No. 001-32367

BILL BARRETT CORPORATION(Exact name of registrant as specified in its charter)

Delaware(State or other jurisdiction
of incorporation or organization)

80-0000545(IRS Employer Identification No.)1099 18th Street, Suite 2300
Denver, Colorado(Address of principal executive offices)

80202(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 registeredCommon Stock, $.001 par value

New York Stock ExchangeSeries 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. ý Yes    o 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. o Yes    ý 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. ý Yes    o 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.    o

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

Large accelerated filer ý

Accelerated filer oNon-accelerated filer o (Do not check if a smaller reporting company)

Smaller reporting company o


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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant as of June 30, 2008
based on the $59.41 closing price of our common stock was $2,255,891,746.*

---

As
of January 30, 2009, the registrant had 45,131,023 outstanding shares of $.001 per share par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE:

The
information required in Part III of this Annual Report on Form 10-K is incorporated by reference from the registrant's definitive proxy statement for the
registrant's Annual Meeting of Stockholders to be held in May 2009 to be filed pursuant to Regulation 14A no later than 120 days after the end of the registrant's fiscal year ended
December 31, 2008.



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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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



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

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

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materially
from those anticipated or implied in the forward-looking statements due to the factors listed in "Item 1A. Risk Factors" and elsewhere in this Annual Report on
Form 10-K. All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We undertake no obligation to publicly update or revise
any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on
our behalf.

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PART I

Items 1 and 2.    Business and Properties

BUSINESS

General

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

We
have attempted to fulfill our strategy to profitably grow our reserves and production by drilling low-risk repeatable development wells and finding and developing gas and
oil in the Rocky Mountain region. In addition to low-risk development drilling, we plan to continue evaluating our delineation and exploration prospects on our extensive acreage position
of over 1.2 million net undeveloped acres. Our operating results reflect our development growth and exploration success on our properties.

We
began active natural gas and oil operations in March 2002 with the acquisition of properties in the Wind River Basin. Initially, we increased our activity level and the number of
properties that we operate by acquiring a large inventory of undeveloped leasehold interests through federal and state sales as well as private purchases and trades. We also acquired producing
properties that had large undeveloped acreage positions associated with them. For example, in 2002, we completed two additional acquisitions that included properties in the Uinta, Wind River, Powder
River and Williston Basins; in early 2003, we completed an acquisition of largely undeveloped coalbed methane properties located in the Powder River Basin; in September 2004, we acquired interests in
properties in the Piceance Basin in and around the Gibson Gulch field; and in May 2006, we added to our coalbed methane position in the Powder River Basin. In June 2007, we sold our Williston Basin
properties. There were no major acquisitions or divestitures in 2008.

We
operate in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of our operations are conducted in the United States.
Consequently, we currently report a single industry segment. See "Financial Statements" and the notes to our consolidated financial statements for financial information about this industry segment.
See definitions of oil and natural gas terms below at "Glossary of Oil and Natural Gas Terms."

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The
following table provides information regarding our operations by basin as of December 31, 2008.

Basin/Area

State

Estimated Net
Proved
Reserves(1)
(Bcfe)

December 2008
Average Daily
Net Production
(MMcfe/d)

Net Producing
Wells

Net
Undeveloped
AcreageUinta

UT


328.8


91.5


143.4


191,885
(2)Piceance

CO


372.1


95.9


382.2


10,295Powder River

WY


66.6


24.3


464.0


77,397Wind River

WY


50.8


23.5


148.4


226,636Paradox(3)

CO/UT





0.5


1.1


265,712Montana Overthrust

MT











174,448Big Horn(4)

WY








1.0


64,155Other

Various











192,841Total




818.3


235.7


1,140.1


1,203,369
(2)


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Our Offices

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

Business Strengths

We believe we have the following strengths:



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Business Strategy

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



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Uinta Basin

The Uinta Basin is located in northeastern Utah. Our development operations are conducted in the West Tavaputs area, and we are
currently testing offsets and infill locations to attempt to delineate our Lake Canyon/Blacktail Ridge exploration discoveries. We also have a position in several exploration prospects in the Uinta
Basin.



West Tavaputs

We serve as operator of our interests in the West Tavaputs area. As of December 31, 2008, we had 753 drilling locations and
320.3 Bcfe of estimated proved reserves with a weighted average working interest of 96%. We are actively drilling our shallow program, which targets the gas-productive sands of the Wasatch
and Mesaverde formations at depths down to 8,000 feet. We drilled 60 shallow wells in 2008 and plan to drill up to 16 shallow wells in 2009. The Wasatch and Mesaverde formations are currently being
developed on 40-acre density following testing and analysis of 40-acre pilots in 2007 and 2008. Testing of 20-acre density pilots are also underway having drilled
six 20-acre shallow wells in 2008.

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With 3-D seismic, we also have identified two deeper structures targeting the Jurassic Navajo and Entrada and the Cretaceous Dakota formations at
depths of nearly 15,000 feet. The eastern deep structure has been productive in 7 of 8 wells drilled thus far.

Full
development of the West Tavaputs area requires the completion of an Environmental Impact Statement, or EIS, which we initiated in February 2005. The Record of Decision, or ROD, on
the EIS has been deferred pending the transition of the management of certain positions within the Bureau of Land Management, or BLM, and Department of Interior under President Obama's administration.
Due to the transition, we believe it will be several months before the ROD could be obtained.

We
recently entered into precedent agreements with Questar to subscribe for firm transportation arrangements on an expansion project as well as additional processing that we believe will
provide adequate capability to move anticipated gas volumes from West Tavaputs.

Lake Canyon/Blacktail Ridge

Lake Canyon.In 2004, we and an industry partner entered into a drill-to-earn exploration and development agreement with the
Ute Indian Tribe of the Uintah and Ouray Reservation, or the Ute Tribe and Ute Development Corporation to explore for and develop oil and natural gas on approximately 125,000 of their net undeveloped
acres that are located in Duchesne and Wasatch Counties, Utah. Pursuant to this agreement, we have the right to earn up to a 75% working interest in the Wasatch formation (targeting oil at
approximately 8,000 feet) and deeper horizons, for which we serve as operator, plus up to a 25% interest in the shallower Green River formations. To earn these interests pursuant to this agreement, we
and our partner are required to drill 13 deep wells and 21 shallow wells prior to December 31, 2009. The Ute Tribe has an option to participate in a 25% working interest in wells drilled
pursuant to the agreement. In 2008, we drilled one gross well in Lake Canyon as we continued to evaluate the results from the six wells drilled in previous years.

Blacktail Ridge.In December 2006, we entered into an exploration and development agreement with the Ute Tribe and the Ute Development
Corporation to
explore for and develop oil and natural gas on approximately 51,000 of their net undeveloped acres that are located in Duchesne County, Utah. Pursuant to this agreement, we serve as operator and have
the right to earn a minimum of 50% working interest in all formations. To earn these interests pursuant to this agreement, we were required to drill a five Wasatch well program that began in 2007
followed by eight Wasatch wells per year thereafter. The Ute Tribe has an option to participate in up to 50% working interest in wells drilled pursuant to the agreement. By the end of 2008 we had
commenced the drilling of 14 wells with an average working interest of 60.7%, thus fulfilling both our 2007 and 2008 drilling obligations. Completion results to date indicate we can successfully
extend the known limits of the field, as well as increase the well density inside the current field boundaries, as long as product prices support such activity.

Hook

Hook is a shale gas prospect in the southwestern portion of the Uinta Basin. In late 2007, we sold a 50% working interest in 29,531 net
acres in the deep Manning Canyon area of this prospect. In 2008, we continued to acquire leasehold acreage, drilled a scientific well to gather data and drilled an exploration well to test this
prospect. In 2009, we plan to drill our first
horizontal well to test the Manning Canyon shale, and continue our evaluation of the shallower Juana Lopez shale with a second vertical core well.

Piceance Basin

The Piceance Basin is located in northwestern Colorado. We began operations in the Gibson Gulch area of the Piceance Basin on
September 1, 2004, with the purchase of producing and

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undeveloped
properties from Calpine Corporation and Calpine Natural Gas L.P. for approximately $137.3 million.



The
Gibson Gulch area is a basin-centered gas play along the north side of the Divide Creek anticline at the eastern end of the Piceance Basin's productive Mesaverde (Williams Fork)
trend at depths of 7,500 feet. Through 2006, we drilled on a 20-acre well pattern. Beginning in 2007, we commenced drilling 10-acre pilot programs, and our 2007 and
2008 year-end reserves include proved reserves associated with these pilots. Our natural gas production in this basin is currently gathered through our own gathering system and
EnCana Corporation's and delivered to markets through a variety of pipelines including pipelines owned by Questar Pipeline Company, Northwest Pipeline, Colorado Interstate Gas Rocky Mountains (CIGRM)
and Rockies Express Pipeline LLC. Our natural gas is processed at an Enterprise Products Partners L.P. plant in Meeker, Colorado.

Powder River Basin

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



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

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."

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

Wind River Basin

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



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

Cave Gulch

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

In
January 2008, we signed a joint exploration agreement with two industry partners that provided for the drilling of at least two deep wells in 2008 on a partially promoted basis. The
Cave Gulch 31-32 was drilled to 18,731 feet and tested approximately 1,000 Mcf/d from the Lakota and Muddy formations. We have moved up hole and are currently in the process of completing
in the Frontier section with results expected in the first half of 2009. The East Bullfrog 23-6 well was recently completed in the Muddy and Lakota formations. Outside this joint
exploration area, we are also planning on recompletion of the Frontier formation in the Bullfrog 33-19. This recompletion is expected to take place in the second half of 2009.

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.



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Yellow Jacket

This prospect targets natural gas from the Gothic shale at depths of 4,500 to 6,500 feet. Through 2008, we had drilled four exploratory
vertical science wells to gather rock property data, and three horizontal well bores. Two of these wells were placed on production in December 2008 with a third well waiting on completion of pipeline
facilities. In 2009, we intend to drill at least seven exploratory tests using horizontal well bores in an attempt to further delineate this prospect. We serve as operator in this area and have an
average working interest of 55%.

Green Jacket

This prospect targets natural gas from the Hovenweep shale at depths of 4,500 to 6,500 feet and is directly adjacent to our Yellow
Jacket prospect. We drilled one vertical science well in 2008, which was immediately converted into a horizontal wellbore, and is now waiting on completion plans. We plan to drill one horizontal
exploratory well on this prospect in 2009. We serve as operator in this area where we have a working interest of 100%.

Salt Flank

In the Salt Flank exploration prospect, we are targeting gas fields in stratigraphic and structural traps located on the flanks of salt
diapirs. After sell down to an 80% working interest level, we drilled our first exploratory test on our Pine Ridge prospect in 2008. The well is currently waiting on the lifting of seasonal
restrictions. Testing may only occur between July 5, 2009 and October 31, 2009. No further drilling activity is anticipated in 2009.

Montana Overthrust

We serve as operator and have a 50% working interest in this prospect in southwestern Montana. In 2007, we drilled two exploratory
structural wells, which have been deemed dry holes below the Cody Shale interval. In 2008, we drilled four Cody Shale wells and completed and tested one of those wells. The Pulis 7-15
tested approximately 1,000 Mcf/d with 859 barrels of water per day over a 9 day flow period. In 2009, we plan to test the remaining three wells drilled in 2008 and, depending on the results of
the vertical wells, drill one horizontal test in the Cody Shale.



Big Horn Basin

The Big Horn Basin is located in north central Wyoming. We are in the initial phases of an exploration project targeting both
structural-stratigraphic and basin-centered tight gas plays. Our working interest in this project is 50%. In 2008, we drilled and ran casing on one well to a depth of 10,705 feet in order to test the
Fort Union Formation. We expect to complete and test this well in the second quarter of 2009.



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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, 2008, 2007 and 2006 based on reserve reports prepared by us and reviewed in their entirety by outside independent petroleum engineers. While we are not required
by the SEC or accounting regulations or pronouncements to have our estimates independently reviewed, we are required by our revolving credit agreement with our lenders to have an independent
engineering firm perform an annual review of our estimated reserves. All of our proved reserves included in our reserve reports are located in North America. Through December 31, 2006, Ryder
Scott Company, L.P. reviewed all our reserve estimates except for our reserve estimates in the Powder River Basin, which were reviewed by Netherland, Sewell & Associates, Inc., or
NSAI. NSAI reviewed all of our reserve estimates at December 31, 2007 and 2008. When compared on a well-by-well or lease-by-lease basis, some of
our estimates of net proved reserves are greater and some are less than the estimates of outside independent petroleum engineers. However, in aggregate, the independent petroleum engineer estimates of
total net proved reserves are within 10% of our internal estimates. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than
the SEC in connection with our registration statement for our initial public offering. The Standardized Measure shown in the table is not intended to represent the current market value of our
estimated natural gas and oil reserves.

As of December 31,Proved Reserves:

2008

2007

2006Natural gas (Bcf)


784.3


538.3


377.7Oil (MMBbls)


5.7


3.2


8.5Total proved reserves (Bcfe)(1)


818.3


557.6


428.4Proved developed reserves (Bcfe)


435.1


329.8


248.9Standardized Measure (in millions)(2)

$
858.1

$
941.2

$
529.3


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

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

At
December 31, 2008, we revised our proved reserves upward by 146.4 Bcfe, excluding pricing revisions, primarily as a result of adding increased density proved undeveloped
locations in the Piceance Basin and West Tavaputs area and improved production performance by wells located in each of our major producing basins: Wind River, Uinta, Powder River and Piceance. We
revised our 2008 year-end proved reserves downward by 7.3 Bcfe, as year-end 2008 pricing was $4.61 per MMBtu and $41.00 per barrel of oil, relative to
year-end 2007 pricing of $6.04 per MMBtu and $92.50 per barrel of oil. Year-end prices were adjusted
by lease for quality, transportation fees and regional price differences. At year-end 2007, we revised our proved reserves upward by 34.8 Bcfe, excluding pricing revisions, primarily as a
result of adding increased density proved undeveloped locations in the West Tavaputs area and continued improved performance of wells drilled in the West Tavaputs area and Piceance Basin. At
year-end 2006, we revised our proved reserves upward by 12.4 Bcfe, excluding pricing revisions. This revision was primarily the result of increased performance of wells drilled during the
last half of 2005 and the first half of 2006.

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

For
the year ended December 31, 2008, our outside independent engineer, NSAI, performed a well-by-well review of all of our properties and of our estimates
of proved reserves and then provided us with their review report concerning our estimates. The review completed by NSAI, at our request, is a collective application of a series of procedures performed
by NSAI. These review procedures may be the same or different from those review procedures performed by other independent engineering firms for other oil and gas companies. NSAI's review report does
not state the degree of their concurrence with the accuracy of our estimate for the proved reserves attributable to our interest in any specific basin, property or well.

For
the year ended December 31, 2008, the estimate provided by NSAI was 6.3% below our reserve estimate. Our independent reserve engineers arrived at reserve estimates that were
greater than 10% above or 10% below our estimates for approximately 54% of our wells. This represents approximately 56% of the total proved reserves covered in the review reports. At the material
property

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level,
the independent engineer reserve estimates ranged between 5.8% above our internal reserve estimates to 1.7% below our estimates in the year-end 2008 report. For the year ended
December 31, 2007, the estimate provided by NSAI was 4.5% above our reserve estimate. For the year ended December 31, 2006, in which the review was performed by two independent
engineering firms, Ryder Scott Company, L.P.'s estimate was 6.2% below our reserve estimate, and NSAI's estimate was 7.9% below our reserve estimate. For estimates of proved reserves at
December 31, 2006, our outside independent reserve engineers arrived at reserve estimates that were greater than 10% above or below our own estimates for approximately 52% of our wells. This
represents approximately 45% of the total proved reserves covered in the review reports. At the material property level, the independent engineer reserve estimates ranged between 21.3% above our
internal reserve estimates to 2.4% below our estimates in the year-end 2006 reserve report.

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



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

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

From
time to time, we engage NSAI and Ryder Scott to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well
testing. Neither NSAI nor Ryder Scott nor any of their respective employees has any interest in those properties, and the compensation for these engagements is not contingent on their estimates of
reserves and future cash inflows for the subject properties. During 2008 and 2007, we paid NSAI approximately $220,000 and $216,000, respectively, for reviewing our reserve estimates. We did not
employ NSAI for other consulting services during either year. During 2008 and 2007, we did not employ Ryder Scott to review our reserves or provide other consulting services.

On
December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reserves reporting requirements. Many of the revisions are updates to
definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management system, which is a widely accepted set of evaluation guidelines that are designed to
support assessment processes throughout the resource asset lifecycle. These guidelines were prepared by the Society of Petroleum Engineers, or SPE, Oil and Gas Reserves Committee with cooperation from
many industry organizations. One of the key changes to the previous SEC rules relates to using a 12-month average commodity price to calculate the value of proved reserves versus the
current method of using year-end prices. Other key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, the
opportunity to establish proved undeveloped reserves without the requirement of an adjacent producing well and permitting disclosure of probable and possible reserves. The SEC will require companies
to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009.
Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on the Company's disclosures and financial statements.

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Production and Price History

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

Year Ended December 31,2008

2007

2006Production Data:Natural gas (MMcf)(1)


73,623


57,678


47,928Oil (MBbls)


661


586


696Combined volumes (MMcfe)


77,589


61,194


52,104Daily combined volumes (MMcfe/d)


212.0


167.7


142.8Average Prices(2):Natural gas (per Mcf)

$
7.61

$
5.89

$
6.40Oil (per Bbl)


69.55


59.87


53.50Combined (per Mcfe)


7.81


6.13


6.60Average Costs ($ per Mcfe):Lease operating expense

$
0.57

$
0.68

$
0.57Gathering and transportation expense


0.51


0.38


0.30Production tax expense


0.57


0.37


0.50Depreciation, depletion and amortization(3)


2.66


2.87


2.69General and administrative(4)


0.52


0.52


0.53


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Productive Wells

The following table sets forth information at December 31, 2008 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

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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

OilBasin

Gross
Wells

Net
Wells

Gross
Wells

Net
WellsUinta


146.0


133.0


15.0


10.4Piceance


424.0


382.2





Powder River


666.0


455.1


43.0


8.9Wind River


165.0


148.4





Other


4.0


2.1





Total


1,405.0


1,120.8


58.0


19.3


Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2008 relating to our leasehold acreage.

Developed Acreage(1)

Undeveloped Acreage(2)Basin/Area

Gross

Net

Gross

NetUinta


21,520


19,821


276,856


191,885
(3)Piceance


7,794


6,147


12,540


10,295Powder River


79,325


50,026


119,494


77,397Wind River


9,216


6,372


336,164


226,636Big Horn


801


374


131,507


64,155Paradox


560


461


461,227


265,712Green River








61,914


54,381Montana Overthrust








384,054


174,448Utah Hingeline








26,537


18,208Other


1,241


904


134,548


120,252Total


120,457


84,105


1,944,841


1,203,369
(3)


---

Many
of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage
has been established prior to such date, in which event the lease will remain in effect until the cessation of production. We generally have been able to obtain extensions of the primary terms of our
federal leases for the period in which we have been unable to obtain drilling permits due to a pending Environmental Assessment, Environmental Impact Statement or related legal challenge. The
following table sets forth,

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as
of December 31, 2008, the expiration periods of the gross and net acres that are subject to leases summarized in the above table of undeveloped acreage.

Undeveloped Acres
ExpiringTwelve Months Ending:

Gross

NetDecember 31, 2009


122,187


49,334December 31, 2010


249,416


118,108December 31, 2011


250,678


127,880December 31, 2012


171,513


114,102December 31, 2013 and later(1)


1,182,802


816,077Total


1,976,596


1,225,501


---

Drilling Results

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

Year Ended
December 31,
2008

Year Ended
December 31,
2007(1)

Year Ended
December 31,
2006Gross

Net

Gross

Net

Gross

NetDevelopmentProductive


77.0


67.9


54.0


46.6


48.0


41.1Dry








1.0


0.5





ExploratoryProductive


136.0


120.7


177.0


136.4


121.0


85.2Dry(2)








6.0


2.5


3.0


1.6TotalProductive


213.0


188.6


231.0


183.0


169.0


126.3Dry








7.0


3.0


3.0


1.6


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Operations

General

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

Marketing and Customers

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

During
2008, EnCana Oil & Gas and Sempra Energy Trading Corporation accounted for 16.7% and 16.6%, respectively, of the Company's oil and gas production revenues. During 2007,
Sempra Energy Trading Corporation, EnCana Oil & Gas and United Energy Trading accounted for 20.6%, 15.7% and 8.7%, respectively, of the Company's oil and gas production revenues. During 2006,
Sempra Energy Trading Corporation, Xcel Energy Inc. and ONEOK Inc. accounted for 21.3%, 10.0% and 9.7%, respectively, of the Company's oil and gas production revenues. Management
believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

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

Our
natural gas and oil are transported through our own and third party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our
natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party processor or transporter.
Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other
gas shippers. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected
properties could be adversely affected. In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes. In order to
meet pipeline specifications, we are required, in some cases, to process our gas before we can transport it. We typically contract with third parties in the Piceance, Wind River, Uinta, Powder and
Paradox Basins to process our natural gas. We also may enter into firm sales agreements to ensure that we are selling to a purchaser who has contracted for pipeline

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capacity.
These agreements are subject to the limitations discussed above in this paragraph. The following table sets forth information about material long-term firm transportation
contracts for pipeline capacity and firm processing contracts, both of which typically require a demand charge and firm sales contracts.

Type of Arrangement

Pipeline System / Location

Gross Deliveries (MMBtu/d)

TermFirm Sales

Questar Pipeline


10,000


4/06 - 12/09Firm Sales

Questar Pipeline


8,500


5/05 -   3/10Firm Sales

Cheyenne Hub


7,500


11/08 -   8/11Firm Sales

Cheyenne Hub


7,000


11/08 -   8/11Firm Sales

Rockies Express


30,000


1/08 - 12/09Firm Sales

KMI


7,500


1/09 - 12/09Firm Transport

WIC Medicine Bow


5,000


6/08 -   3/14Firm Transport

WIC Medicine Bow


30,000


11/07 -   3/15Firm Transport

WIC Medicine Bow


25,000


4/09 -   3/19Firm Transport

WIC Medicine Bow


Varies


12/08 -   6/13Firm Transport

WIC Kanda


15,000


12/08 - 11/23Firm Transport

Questar Pipeline


12,000


11/05 - 10/15Firm Transport

Questar Pipeline


25,000


1/07 - 12/16Firm Transport

Cheyenne Plains


9,000


2/05 -   4/17Firm Transport

Cheyenne Plains


5,000


5/17 -   4/18Firm Transport

Questar Pipeline


25,000


11/07 - 10/17Firm Transport

Rockies Express


25,000


1/08 -   6/19Firm Transport

Questar Pipeline


15,000


1/08 -   6/09Firm Transport

Questar Gas


70,000


3/09 -   2/20Firm Processing

Questar Gas


70,000


3/09 -   2/20Firm Processing

Questar Pipeline


50,000


8/06 -   8/16Firm Processing

Questar Pipeline


50,000


4/07 -   6/09


Hedging Activities

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

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of
these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide
basis. These companies are able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit. In addition, these companies have a greater ability to continue exploration activities during periods of low oil and natural gas market prices.
Our larger or integrated competitors are better able to absorb the 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

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environment.
In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil
and natural gas properties.

Title to Properties

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

Seasonal Nature of Business

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

Environmental Matters and Regulation

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



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These
laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas
industry increases the cost of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations,
and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant
impact on our operating costs. We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will
not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of more stringent future laws and
regulations at this time. For the year ended December 31, 2008, we did not incur any material capital expenditures for remediation or retrofit of pollution control equipment at any of our
facilities.

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

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

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

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

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

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

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

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

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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.

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

Other Regulation of the Oil and Gas Industry

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

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



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

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

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

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

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

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

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

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Employees

As of January 30, 2009, we had 274 full time equivalent employees. Of our 274 equivalent full time employees, 163 work in our
Denver office and 111 are in our field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None
of our employees is represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are good.

Offices

As of December 31, 2008, we leased approximately 62,633 square feet of office space in Denver, Colorado at 1099
18th Street, where our principal offices are located. The lease for our Denver office expires in March 2011. We also own field offices in Waltman, Wyoming, Roosevelt, Utah and Silt, Colorado,
and lease a field office in Gillette, Wyoming. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.

Website and Code of Business Conduct and Ethics

Our website address ishttp://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 athttp://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 athttp://www.billbarrettcorp.comand are available in print free
of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our principal office at 1099 18th Street, Suite 2300,
Denver, Colorado 80202. We intend to disclose on our website any amendments or waivers to our Code of Business Conduct and Ethics that are required to be disclosed pursuant to Item 5.05 of
Form 8-K. This Annual Report on Form 10-K and our website contain information provided by other sources that we believe are reliable. We cannot assure you that
the information obtained from other sources is accurate or complete. No information on our website is incorporated by reference herein or deemed to be part of this Annual Report on
Form 10-K.

Annual CEO Certification

As required by New York Stock Exchange rules, on May 19, 2008 we submitted an annual certification signed by our Chief Executive
Officer certifying that he was not aware of any violation by us of New York Stock Exchange corporate governance listing standards as of the date of the certification.

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

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

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

Bcf.Billion cubic feet of natural gas.

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

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

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

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

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

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

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

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

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

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

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

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

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 or EA.An environmental assessment, a study that can be required pursuant to federal law prior to
drilling a well.

Environmental Impact Statement or 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.

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

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

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

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

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

Mcf.Thousand cubic feet of natural gas.

Mcf/d.Mcf per day.

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

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

MMBtu.Million British Thermal Units.

MMcf.Million cubic feet of natural gas.

MMcf/d.MMcf per day.

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

MMcfe/d.MMcfe per day.

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

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

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

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

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

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

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

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

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

Proved undeveloped reserves or 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.

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

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

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

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

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

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

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

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

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

Tcf.Trillion cubic feet (of gas)

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

Working interest.The operating interest that gives the owner the right to drill, produce and conduct operating activities on the
property and
receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

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Item 1A.    Risk Factors

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

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

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

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



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

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

Any or all of the following may occur as a result of the continuing crisis in the U.S. and world financial and securities
markets:



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

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our
business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. To date, we have financed capital expenditures primarily with sales of our
equity 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:



If
our revenues or the borrowing base under our Amended 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 Amended Credit
Facility restricts our ability to obtain new financing. There can be no assurance as to the availability or terms of any additional financing.

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

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

Our drilling activities 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:



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

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

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

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

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

Underground accumulations of oil and natural gas can not be measured in an exact way. Oil and natural gas reserve engineering requires
estimates of underground accumulations
of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and
projections of future production rates and the timing of development expenditures may be incorrect.

Our
estimates of proved reserves are determined at prices and costs at the date of the estimate. Any significant variance from these prices and costs could greatly affect our estimates
of reserves. The pricing revision at year-end 2008 at prices of $4.61 per MMBtu of gas and $41.00 per barrel of oil, relative to year-end 2007 prices of $6.04 per MMBtu and
$92.50 per barrel of oil, was downward 7.3 Bcfe.

We
prepare our own estimates of proved reserves, which are reviewed by independent petroleum engineers. Over time, our internal engineers may make material changes to reserve estimates
taking into account the results of actual drilling, testing and production. For additional information about

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these
risks and their impact on our reserves, see "Items 1 and 2. Business and PropertiesOil and Gas DataProved Reserves" and "Notes to Consolidated Financial
Statements15. Supplementary Oil and Gas Information (unaudited)Analysis of Changes in Proved Reserves" in this Annual Report on Form 10-K.

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

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir
characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2008, production will decline even if those proved undeveloped
reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change
under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent upon our success in efficiently developing and
exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and
future production at acceptable costs.

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

We describe some of our prospects and our plans to explore those prospects in "Items 1 and 2. Business and Properties." A
prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of natural gas or oil. Our prospects are in
various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. However, the use of
seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling and testing whether natural gas or oil will be present
or, if present, whether natural gas or oil will be present in sufficient quantities to recover drilling or completion costs or to be economically viable. If we drill additional wells that we identify
as dry holes in our current and future prospects, our drilling success rate may decline and materially harm our business. The cost of drilling, completing and operating any well is often uncertain,
and new wells may not be productive. Such uncertainties may harm our business and results of operations.

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

The Powder River Basin represents a significant part of our drilling program and production. In the Powder River Basin, nearly all of
our operations are in coalbed methane plays, and our key project areas are located in areas that have been the most active drilling areas in the Rocky Mountain region. As a result, many of our leases
are in areas that may have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these
areas. In addition, activities related to the mining of coal near our operations, including core-hole drilling to determine the aerial extent of coal deposits and the mining of coal, may
introduce oxygen into our producing wells and compressors, causing production to be shut-in, or allow hydrocarbons to escape before they can be recovered. This would lead to a loss of
reserves and revenues.

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

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a
significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory
approvals, natural gas and oil prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled
or if we will be able to produce natural gas or oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified,
which could adversely affect our business. In 2009, we plan to participate in the drilling of up to 163 gross wells depending on budgetary considerations.

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

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

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

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

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

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

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

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in
recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Our
Powder River Basin coalbed methane exploration and production activities result in the discharge of produced groundwater into adjacent lands and waterways. The ratio of methane gas
to produced water varies over the life of the well. The environmental soundness of discharging produced groundwater pursuant to water discharge permits has come under increased scrutiny. Moratoriums
on the issuance of additional water discharge permits or more costly methods of handling these produced waters, may affect future well development. Compliance with more stringent laws or regulations,
more vigorous enforcement policies of the regulatory agencies, difficulties in negotiating required surface use agreements with land owners or receiving other governmental approvals could delay our
Powder River Basin exploration and production activities and/or require us to make material expenditures for the
installation and operation of systems and equipment for 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 BLM failed to fully comply with the National Environmental Policy Act, or NEPA, in granting certain federal leases in the Powder River Basin to Pennaco
Energy, Inc. for coalbed methane development. Other recent decisions in the federal district court in Montana have also held that BLM failed to comply with NEPA when considering coalbed methane
development in the Powder River Basin. While these recent decisions have not had a material direct impact on our current operations or planned exploration and development activities, future litigation
and/or agency responses to such litigation could materially impact our ability to obtain required regulatory approvals to conduct operations in the Powder River Basin.

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

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

Our future Rocky Mountain operations and cost of doing business may be affected by changes in regulations and the ability to obtain
drilling permits. Our properties located in Colorado are subject to the authority of the Colorado Oil and Gas Conservation Commission, or COGCC. The COGCC has the authority to regulate oil and gas
activities to protect public health, safety and welfare, including the environment and wildlife. In 2007, the Colorado legislature approved legislation changing the

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composition
of the COGCC to reduce industry representation and to add the heads of the Colorado Department of Natural Resources, or CDNR, and the Colorado Department of Public Health and Environment,
or CDPHE plus other stakeholders. In addition, the legislation required the COGCC to promulgate rules (1) in consultation with CDPHE, to provide CDPHE an opportunity to provide comments on
public health issues during the COGCC's decision-making process and (2) in consultation with the Colorado Division of Wildlife, or CDOW, to establish standards for minimizing adverse impacts to
wildlife resources affected by oil and gas operations and to ensure the proper reclamation of wildlife habitat during and following such operations. These rules become effective April 1, 2009
for the majority of our Colorado operations area. We believe the revised rules will cause additional costs and may cause delay in our operations in Colorado. The rules require consultation with the
CDOW and CDPHE prior to drilling and completion operations in our Piceance Basin and for the portion of the Paradox Basin located in Colorado. The requirements for this consultation are
open-ended and resulting permit restrictions remain subject to appeal by the CDOW, CDPHE and the surface owner. The CDOW may attempt to prohibit drilling and completion operations for some
period corresponding to wildlife's use of the habitat. CDPHE may choose to impose costly conditions of approval and limit the areas that can be developed. If we are not able to avoid adverse
requirements, our Piceance Basin and, if our Paradox Basin exploratory activities are successful, the Colorado portion of our Paradox Basin production and production growth would be reduced. In
addition, the costs of these and the other proposed rules could add substantial increases in incremental well costs in our Colorado operations. The rules also would impact the ability and extend the
time necessary to obtain drilling permits, which creates substantial uncertainty about our ability to obtain sufficient permits in a timely fashion in order to meet future drilling plans and thus
production and capital expenditure targets. It is also possible that similar rules will be proposed in the other states in which we operate, further impacting our operations.

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

Our operations have been focused on the Rocky Mountain region, which means our current producing properties and new drilling
opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability
may be disproportionately exposed to the effect of
any regional events, including fluctuations in prices of natural gas and oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity
constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells.

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

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

Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations
designed to protect various wildlife. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our
ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic
shortages. These constraints and the resulting shortages or high costs could delay our operations and

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materially
increase our operating and capital costs. For example, we encountered limitations on our activities in the West Tavaputs area of the Uinta Basin earlier than expected in the fourth quarter
of 2004 due to lease stipulations that prevented us from completing wells. In addition, our costs increased due to removal of a drilling rig, incurrence of expenses relating to the reinstallation of
that rig and additional mobilization costs when the winter stipulations ended in the spring of 2005.

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

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

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

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

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

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

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

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



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.

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

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

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

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.

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

39

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Table of Contents

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

Our
current Amended Credit Facility limits the amounts we can borrow up to a borrowing base amount, determined by the lenders in their sole discretion, based upon projected revenues from
the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the Amended 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 Amended Credit Facility.

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

Our credit facility has commitments from 17 banks. With the current turbulent credit markets, the banks may become more restrictive in
their lending practices or unable to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues
as well as limit our projected production and reserve growth, leading and declining production and potentially losses.

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

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

40

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Table of Contents

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 have experienced and 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:



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

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

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

As
of December 31, 2008, we had 45,128,431 shares of common stock outstanding, excluding stock options. All of the outstanding shares are freely tradable, other than shares held
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 5,075,088 of our outstanding shares. This registration may be accomplished quickly by filing prospectus supplements
under an automatically effective shelf registration statement. The resale of a large number of shares could cause our stock price to decline.

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:



41

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Table of Contents



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

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

Warburg Pincus Private Equity VIII, L.P. and Warburg Pincus Private Equity X, L.P. collectively own approximately 13.7%
of our outstanding common stock. Accordingly, these related 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 Warburg Pincus Private Equity X, L.P.

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

Item 1B.    Unresolved Staff Comments

Not applicable.

Item 3.    Legal Proceedings

We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our
business and a matter with the
EPA. In September 2006, the EPA alleged that we and an industry partner failed to comply with air quality and emissions standards for equipment used at our North Hill Creek compressor station in the
Uinta Basin of Utah. In September 2008, we entered into a consent decree with the EPA pursuant to which we and our industry partner agreed to pay a fine of $240,000, of which we agreed to pay
$140,000. The consent decree is subject to the approval of the United States federal court for the District of Utah.

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

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

Not applicable.

42

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Table of Contents

PART II

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



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

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

High

Low2008First Quarter

$
51.20

$
36.26Second Quarter


60.43


47.02Third Quarter


60.87


29.43Fourth Quarter


32.11


14.932007First Quarter

$
32.94

$
24.76Second Quarter


39.25


32.33Third Quarter


40.45


32.12Fourth Quarter


47.14


38.02


On
January 30, 2009, the closing sales price for our common stock as reported by the NYSE was $22.11 per share.

Holders.On January 30, 2009, the number of holders of record of common stock was 397.

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

Issuer Purchases of Equity Securities.We did not have any issuer purchases of equity securities in the fourth quarter ended
December 31,
2008.

43

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Table of Contents



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



Total Return Among Bill Barrett Corporation, the Standard & Poors 500 and the Standard and Poors MidCap  400-Energy Sector

GRAPHIC

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44

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Table of Contents

Item 6.    Selected Financial Data

The following table presents our selected historical financial data for the years ended December 31, 2008, 2007, 2006, 2005 and
2004. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines and other factors. This information should be read in
conjunction with the consolidated financial statements and notes thereto and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations", presented elsewhere
in this Annual Report on Form 10-K.

Selected Historical Financial Information

The consolidated income statement information for the years ended December 31, 2008, 2007 and 2006 and the balance sheet
information as of December 31, 2008 and 2007 are derived from our audited financial statements included elsewhere in this report. The income
statement information for the years ended December 31, 2005 and 2004 and the balance sheet information at December 31, 2006, 2005 and 2004 is derived from audited financial statements
that are not included in this report. The information in this table should be read in conjunction with the consolidated financial statements and accompanying notes and other financial data included
herein.

Year Ended December 31,2008

2007

2006

2005

2004(in thousands, except per share data)Statement of Operations Data:Production revenues(1)

$
605,881

$
374,956

$
344,127

$
284,406

$
165,843Commodity derivative gain


7,920











Other revenues


4,110


15,314


31,202


4,353


4,137Total operating and other revenues


617,911


390,270


375,329


288,759


169,980Operating expenses:Lease operating expense


44,318


41,643


29,768


19,585


14,592Gathering and transportation expense


39,342


23,163


15,721


11,950


5,968Production tax expense


44,410


22,744


25,886


33,465


20,087Exploration expense


8,139


8,755


9,390


10,930


12,661Impairment, dry hole costs and abandonment expense


32,065


25,322


12,824


55,353


24,011Depreciation, depletion and amortization


206,316


172,054


138,549


89,499


68,202General and administrative expense


40,454


32,074


27,752


24,540


18,061Non-cash stock-based compensation expense


16,752


10,154


6,491


3,212


3,031Total operating expenses


431,796


335,909


266,381


248,534


166,613Operating income


186,115


54,361


108,948


40,225


3,367Other income (expense):Interest and other income


2,036


2,391


2,527


1,977


437Interest expense


(15,834
)

(12,754
)

(10,339
)

(3,175
)

(9,945
)Total other income and expense


(13,798
)

(10,363
)

(7,812
)

(1,198
)

(9,508
)Income (loss) before income taxes


172,317


43,998


101,136


39,027


(6,141
)Provision for (benefit from) income taxes


64,670


17,244


39,125


15,222


(875
)Net income (loss)


107,647


26,754


62,011


23,805


(5,266
)Less deemed dividends on preferred stock














(36,343
)Less cumulative dividends on preferred stock














(18,633
)Net income (loss) attributable to common stockholders

$
107,647

$
26,754

$
62,011

$
23,805

$
(60,242
)Income (loss) per common share(2):Basic

$
2.42

$
0.61

$
1.42

$
0.55

$
(15.40
)Diluted

$
2.39

$
0.60

$
1.40

$
0.55

$
(15.40
)Weighted average number of common shares outstanding, basic(3)


44,432.4


44,049.7


43,694.8


43,238.3


3,912.3Weighted average number of common shares outstanding, diluted


45,036.5


44,677.5


44,269.4


43,439.6


3,912.3


45

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Table of Contents



Year Ended December 31,2008

2007

2006

2005

2004(in thousands)Selected Cash Flow and Other Financial Data:Net income (loss)

$
107,647

$
26,754

$
62,011

$
23,805

$
(5,266
)Depreciation, depletion, impairment and amortization


206,316


172,054


138,549


89,499


68,202Other non-cash items


106,988


40,938


37,765


71,168


26,887Change in assets and liabilities


(18,004
)

11,707


(1,427
)

(202
)

(2,941
)Net cash provided by operating activities

$
402,947

$
251,453

$
236,898

$
184,270

$
86,882Capital expenditures(4)(5)

$
601,115

$
443,678

$
501,161

$
347,427

$
347,520


---

As of December 31,2008

2007

2006

2005

2004(in thousands)Balance Sheet Data:Cash and cash equivalents

$
43,063

$
60,285

$
41,322

$
68,282

$
99,926Other current assets


270,311


71,142


97,185


73,036


37,964Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment


1,548,633


1,182,664


951,132


737,992


549,182Other property and equipment, net of depreciation


13,186


10,865


11,967


7,956


2,983Oil and natural gas properties held for sale, net of accumulated depreciation, depletion, amortization and impairment





2,303


75,496





Other assets


119,870


2,428


10,299


1,679


6,103Total assets

$
1,995,063

$
1,329,687

$
1,187,401

$
888,945

$
696,158Current liabilities

$
225,794

$
139,568

$
119,795

$
132,798

$
62,106Long-term debt


426,500


274,000


188,000


86,000


Other long-term liabilities


254,971


142,608


123,209


39,364


14,320Stockholders' equity


1,087,798


773,511


756,397


630,783


619,732Total liabilities and stockholders' equity

$
1,995,063

$
1,329,687

$
1,187,401

$
888,945

$
696,158


46

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Table of Contents

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

Introduction

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

Overview

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

We
intend to increase stockholder value by profitably growing reserves and production, primarily through drilling our development properties. We seek high quality exploration and
development projects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of natural gas
and oil production at market prices and the settlement of commodity hedges. Approximately 95% of our December 2008 production volume was natural gas.

We
were formed in January 2002. Since inception, we substantially increased our activity level and the number of properties that we operate. Our operating results reflect this growth. We
began active natural gas and oil operations in March 2002 upon the acquisition of properties in the Wind River Basin. Also in 2002, we completed two additional acquisitions of properties in the Uinta,
Wind River, Powder River and Williston Basins. In early 2003, we completed an acquisition of largely undeveloped coalbed methane properties located in the Powder River Basin. In September 2004, we
acquired properties in the Piceance Basin in or around the Gibson Gulch field (the "Piceance Basin Acquisition Properties"). In May 2006, we acquired additional coalbed methane properties in the
Powder River Basin of Wyoming. In June 2007, we sold our Williston Basin properties. 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

$
74Uinta Basin

April 2002


8Wind River, Powder River and Williston Basins

December 2002


62Powder River Basin

March 2003


35Piceance Basin

September 2004


137Powder River Basin

May 2006


79


47

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Table of Contents

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

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

As
of December 31, 2008, we had 818 Bcfe of estimated net proved reserves with a Standardized Measure of $858.1 million (at $4.61 CIGRM and $41.00 WTI). As of
December 31, 2007, we had 558 Bcfe of estimated net proved reserves with a Standardized Measure of $941 million (at $6.04 CIGRM and $92.50 WTI), while at December 31, 2006, we had
428 Bcfe of estimated net proved reserves with a Standardized Measure of $529 million (at $4.46 CIGRM and $61.06 WTI).

The
average sales prices received for natural gas, before the effects of hedging contracts, for the years ended December 31, 2008, 2007 and 2006 were $7.05 per Mcf, $4.37 per Mcf
and $5.94 per Mcf, respectively, and for oil $83.27 per Bbl, $61.18 per Bbl and $59.39 per Bbl, respectively. After the effects of all hedging contracts, the average sales prices received for natural
gas for the years ended December 31, 2008, 2007 and 2006 were $7.61 per Mcf, $5.89 per Mcf and $6.40 per Mcf, respectively, and for oil $69.55 per Bbl, $59.87 per Bbl and $53.50 per Bbl,
respectively.

Oil
and natural gas prices, particularly in the Rockies, are inherently volatile and are influenced by many factors outside of our control. We plan our activities and capital budget
using a conservative sales price assumption and our existing hedge position. It is our board-approved strategic objective to hedge at least 50%-70% of our anticipated production on a
forward 12-month basis. We focus our efforts on increasing natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations.
Our future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production.

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

48

---



Table of Contents

Results of Operations

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

2007 to 2008
Increase
(Decrease)



2006 to 2007
Increase
(Decrease)Year Ended
December 31,
2008

Year Ended
December 31,
2007

Year Ended
December 31,
2006Amount

Percent

Amount

Percent(in thousands, except per unit data)Operating Results:Operating RevenuesOil and gas production

$
605,881

$
230,925


62
%
$
374,956

$
30,829


9
%
$
344,127Commodity derivative gain


7,920


7,920


100
%







0
%

Other


4,110


(11,204
)

(73
)%

15,314


(15,888
)

(51
)%

31,202Total operating and other revenues

$
617,911

$
227,641


58
%
$
390,270

$
14,941


4
%
$
375,329Operating ExpensesLease operating expense


44,318


2,675


6
%

41,643


11,875


40
%

29,768Gathering and transportation expense


39,342


16,179


70
%

23,163


7,442


47
%

15,721Production tax expense


44,410


21,666


95
%

22,744


(3,142
)

(12
)%

25,886Exploration expense


8,139


(616
)

(7
)%

8,755


(635
)

(7
)%

9,390Impairment, dry hole costs and abandonment expense


32,065


6,743


27
%

25,322


12,498


97
%

12,824Depreciation, depletion and amortization


206,316


34,262


20
%

172,054


33,505


24
%

138,549General and administrative expense


40,454


8,380


26
%

32,074


4,322


16
%

27,752Non-cash stock-based compensation expense(1)


16,752


6,598


65
%

10,154


3,663


56
%

6,491Total operating expenses

$
431,796

$
95,887


29
%
$
335,909

$
69,528


26
%
$
266,381Production Data:Natural gas (MMcf)


73,623


15,945


28
%

57,678


9,750


20
%

47,928Oil (MBbls)


661


75


13
%

586


(110
)

(16
)%

696Combined volumes (MMcfe)


77,589


16,395


27
%

61,194


9,090


17
%

52,104Daily combined volumes (MMcfe/d)


212


44


26
%

168


25


17
%

143Average Prices(2):Natural gas (per Mcf)

$
7.61

$
1.72


29
%
$
5.89

$
(0.51
)

(8
)%
$
6.40Oil (per Bbl)


69.55


9.68


16
%

59.87


6.37


12
%

53.50Combined (per Mcfe)


7.81


1.68


27
%

6.13


(0.47
)

(7
)%

6.60Average Costs (per Mcfe):Lease operating expense

$
0.57

$
(0.11
)

(16
)%
$
0.68

$
0.11


19
%
$
0.57Gathering and transportation expense


0.51


0.13


34
%

0.38


0.08


27
%

0.30Production tax expense


0.57


0.20


54
%

0.37


(0.13
)

(26
)%

0.50Depreciation, depletion and amortization(3)


2.66


(0.21
)

(7
)%

2.87


0.18


7
%

2.69General and administrative expense(4)


0.52





0
%

0.52


(0.01
)

(2
)%

0.53


---

49

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Table of Contents

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

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

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

Year Ended December 31, 2008

Year Ended December 31, 2007

% Increase (Decrease)Oil

Natural Gas

Total

Oil

Natural Gas

Total

Oil

Natural Gas

Total(MBbls)

(MMcf)

(MMcfe)

(MBbls)

(MMcf)

(MMcfe)

(MBbls)

(MMcf)

(MMcfe)Piceance Basin


402


29,075


31,487


292


19,031


20,783


38
%

53
%

52
%Uinta Basin


201


26,999


28,205


49


25,536


25,830


310
%

6
%

9
%Wind River Basin


28


9,395


9,563


36


7,156


7,372


(22
)%

31
%

30
%Powder River Basin





8,111


8,111





5,828


5,828





39
%

39
%Williston Basin(1)











184


74


1,178


(100
)%

(100
)%

(100
)%Other


30


43


223


25


53


203


20
%

(19
)%

10
%Total


661


73,623


77,589


586


57,678


61,194


13
%

28
%

27
%


---

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

50

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

Commodity Derivative Gain.During the year ended December 31, 2008, we determined that the forecasted transactions to which
certain
Mid-continent natural gas hedges had been designated were no longer probable of occurring within the specified time periods. We therefore discontinued hedge accounting for these hedges in
accordance with SFAS No. 133. In addition, we entered into basis only swaps for natural gas production in the Rocky Mountain region, which do not qualify for cash flow hedge accounting during
the period. The change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting is recognized in the line item titled "commodity derivative gain" in the
Condensed Consolidated Statements of Operations.

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

Year Ended December 31,2008

2007(in thousands)Realized gains on derivatives not designated as cash flow hedges

$
62

$
Unrealized ineffectiveness recognized on derivatives designated as cash flow hedges


6,803


Unrealized gains on derivatives not designated as cash flow hedges


1,055


Total commodity derivative gain

$
7,920

$



Other Operating Revenues.Other operating revenues decreased to $4.1 million for the year ended December 31, 2008 from
$15.3 million for the year ended December 31, 2007. Other operating revenues for 2008 primarily consisted of gains realized from the sale of properties, gathering and rental fees and the
sale of seismic data. Other operating revenues for 2007 primarily consisted of a gain realized on the sale of the Williston Basin properties, along with gains realized from joint exploration
agreements entered into in the Paradox and Uinta Basins.

Lease Operating Expense.The decrease in lease operating expense to $0.57 per Mcfe in 2008 from $0.68 per Mcfe in 2007 was
primarily the result of
decreased expenses on a Mcfe basis in the Piceance, Powder River and Wind River Basins offset by an increase in the Uinta Basin. The following table displays the lease operating expense per Mcfe by
basin:

Year Ended December 31, 2008

Year Ended December 31, 2007

% Increase/(Decrease)($ in thousands)

($ per Mcfe)

($ in thousands)

($ per Mcfe)

($ per Mcfe)Piceance Basin

$
10,525

$
0.33

$
10,680

$
0.51


(35
)%Uinta Basin


15,762


0.56


10,715


0.41


37
%Wind River Basin


6,831


0.71


7,131


0.97


(27
)%Powder River Basin


10,554


1.30


9,614


1.65


(21
)%Williston Basin








2,732


2.32


(100
)%Other


646


2.90


771


3.80


(24
)%Total

$
44,318


0.57

$
41,643


0.68


(16
)%


51

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

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

Year Ended December 31, 2008

Year Ended December 31, 2007

% Increase/(Decrease)($ in thousands)

($ per Mcfe)

($ in thousands)

($ per Mcfe)

($ per Mcfe)Piceance Basin

$
15,034

$
0.48

$
8,012

$
0.39


23
%Uinta Basin


14,497


0.51


7,413


0.29


76
%Wind River Basin


268


0.03


155


0.02


50
%Powder River Basin


9,556


1.18


7,542


1.29


(9
)%Other


(13
)

(0.06
)

41


0.03


(300
)%Total

$
39,342

$
0.51

$
23,163

$
0.38


34
%


We
have entered into long-term firm transportation contracts for a portion of our production to guarantee capacity on major pipelines and reduce the risk and impact related
to possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production in the Piceance,
Uinta and Powder River Basins where we expect to allocate a significant portion of our capital expenditure program in future years. In addition, we have entered into long-term firm
processing contracts on a portion of our production in the Piceance and Uinta Basins. Included in the above gathering and transportation expense are $0.12 and $0.09 per Mcfe of firm transportation
expense and $0.04 and $0.06 per Mcfe of firm processing expense from long-term contracts for the years ended December 31, 2008 and 2007, respectively.

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

Production Tax Expense.Total production taxes increased to $44.4 million in 2008 from $22.7 million in 2007. The
increase in
production tax expense was primarily related to the increase in

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natural
gas and oil revenues before the effects of hedging. Production taxes as a percentage of natural gas and oil revenues before the effects of hedging were 7.7% for 2008 and 7.9% for 2007.
Production taxes are primarily based on the wellhead values of production and the tax rates that vary across the different areas in which we operate. As the proportion of our production changes from
area to area, our production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect.

Exploration Expense.Exploration expense decreased to $8.1 million in 2008 from $8.8 million in 2007.
Exploration expense for 2008 consisted of $3.9 million for seismic programs, principally in the Big Horn, Uinta and Paradox Basins, $1.0 million for delay rentals and $3.2 million
for two scientific wells drilled for data gathering purposes. The expense for 2007 consisted of $7.3 million for seismic programs, principally in the Montana Overthrust, Paradox and Big Horn
Basins, along with $1.5 million for delay rentals and other exploration costs.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense increased to
$32.1 million in 2008
from $25.3 million in 2007. During 2008, impairment expense was $25.3 million, abandonment expense was $2.0 million, dry hole costs included $3.4 million for a well drilled
in the Uinta Basin and $1.4 million for additional costs on wells that were deemed to be uneconomic in prior years. The $3.4 million for dry hole costs were associated with the Peters
Point 7-1-13-16 Ultra Deep well, which was completed in June 2008 and was tested and determined to be non-commercial in the Pennsylvanian Weber
sandstone and Mississippi Leadville zones. Therefore, a proportionate share of the well cost was expensed. During 2007, impairment expense was $2.3 million, abandonment expenses were
$2.7 million and dry holes and partial dry holes in the Wind River (non-operated), Paradox and Uinta Basins were $12.6 million. In 2007, we also expensed $7.7 million
related to two wells in the Montana Overthrust area that were tested and determined to be non-commercial in the zones below the Cody Shale; thus, a proportionate share of the well costs
were expensed.

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

Unevaluated
oil and gas properties are also assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results,
reservoir performance, commodity price outlooks or future plans to develop existing acreage. During the year ended December 31, 2008, we recognized a non-cash impairment charge of
$4.3 million primarily on the carrying value of unevaluated oil and gas properties in the Talon field, which is also located in the Wind River Basin. Both the Cooper Reservoir and Talon fields
are not considered strategic areas for future operations.

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

We
account for oil and gas exploration and production activities using the successful efforts method of accounting under which we capitalize exploratory well costs until a determination
is made as to whether or not the wells have found proved reserves. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense. Otherwise, the
costs remain capitalized and are depleted as production occurs. The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and
gas properties as

53

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Table of Contents

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

Time Elapsed Since Drilling Completed0-3
Months

4-6
Months

7-12
Months

> 12
Months

Total(in thousands)Wells for which drilling has been completed

$
31,407

$
30,009

$
14,881

$
39,137

$
115,434


The
majority of the $39.1 million of exploratory well costs that have been capitalized for a period greater than one year are for wells located in the Powder River Basin. In this
basin, we drill wells into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting from a few to 24 months, or in some cases longer, is required prior to
obtaining sufficient gas production to justify capital expenditures for compression and gathering and to classify the reserves as proved.

In
addition to our wells in the Powder River Basin, we have six wells that have been capitalized for greater than one year located in the Montana Overthrust area, and in the Paradox, Big
Horn and Uinta Basins. The two wells located in the Montana Overthrust area are under economic evaluation for possible development, as we are assessing and conducting appraisal operations to determine
whether economic reserves can be attributed to this area. In the Paradox Basin, we have one well that will be re-entered and converted to a horizontal well, and completion work is planned
for the second well during the second quarter of 2009. The well located in the Big Horn Basin is pending upgrades of production gathering and processing facilities. The well located in the Uinta Basin
is pending the development of a gas gathering infrastructure.

Depreciation, Depletion and Amortization.DD&A was $206.3 million in 2008 compared to $172.1 million in 2007. The
increase of
$34.3 million was a result of increased production for 2008 compared to 2007, partially offset by a decrease in the DD&A rate. The decrease in the DD&A rate is primarily attributable to
additional reserves booked on our year-end reserve report as the result of our ongoing development programs. The increase in production accounted for $50.3 million of additional
DD&A expense, offset by $16.0 million related to an overall decrease in the DD&A rate.

During
2008, the weighted average DD&A rate was $2.66 per Mcfe. During 2007, the weighted average DD&A rate was $2.87 per Mcfe. The DD&A rate for 2007 excluded production of 1,198 MMcfe
associated with our properties held for sale in the Williston and DJ Basins. Under successful efforts accounting, DD&A expense is separately computed for each producing area based on geologic and
reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average DD&A rate for
current production. Future DD&A rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

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

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

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

Year Ended December 31,2008

2007(in thousands)Stock options and nonvested equity shares of common stock

$
15,789

$
9,372Shares issued for 401(k) plan


733


619Shares issued for directors' fees


230


163Total

$
16,752

$
10,154


Interest Expense.Interest expense increased to $15.8 million in 2008 from $12.8 million in 2007. The increase was due
to higher
average outstanding debt balances in order to fund exploration and development activities. Our weighted average outstanding debt balance, including our Amended Credit Facility and 5% Convertible
Senior Notes ("Convertible Notes") issued in March 2008, was $325.4 million for the year ended December 31, 2008 compared to $196.0 million in 2007.

Interest
cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended
use. The weighted average interest rates used to capitalize interest for the years ended December 31, 2008 and 2007 were 5.9% and 7.1%, respectively, which included interest on both our
Convertible Notes and Amended Credit Facility, commitment fees paid on the unused portion of our Amended Credit Facility, amortization of deferred financing and debt issuance costs and the effects of
interest rate hedges. We capitalized interest costs of $2.0 million and $1.6 million for the years ended December 31, 2008 and 2007, respectively.

Income Tax Expense.Our effective tax rates were 37.5% and 39.2% in 2008 and 2007, respectively. Our effective tax rate differs
from the statutory
rates primarily because we recorded stock-based compensation expense under SFAS No. 123 (revised 2004),Share-Based Payment("SFAS
No. 123R"), and other operating expenses that are not deductible for income tax purposes. Due to the tax deductions created by our drilling activities, we expect that we will incur cash income
tax liabilities relating only to the alternative minimum tax, or AMT, in the next year. At December 31, 2008, we had approximately $68.0 million of federal tax net operating loss
carryforwards, or NOLs, which expire through 2027. We also have a federal AMT credit carryforward of $1.6 million, which has no expiration date. We believe it is more likely than not that we
will use these NOLs to offset and reduce current tax liabilities in future years.

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

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

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Table of Contents

decreases
in product prices significantly reduced our revenues from existing properties. See "Item 7A. Quantitative and Qualitative Disclosure about Market Risk."

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

Year Ended December 31, 2007

Year Ended December 31, 2006

% Increase (Decrease)Oil

Natural Gas

Total

Oil

Natural Gas

Total

Oil

Natural Gas

Total(MBbls)

(MMcf)

(MMcfe)

(MBbls)

(MMcf)

(MMcfe)

(MBbls)

(MMcf)

(MMcfe)Uinta Basin


49


25,536


25,830


43


16,195


16,453


14
%

58
%

57
%Piceance Basin


292


19,031


20,783


193


13,377


14,535


51
%

42
%

43
%Wind River Basin


36


7,156


7,372


46


11,156


11,432


(22
)%

(36
)%

(36
)%Powder River Basin





5,828


5,828





7,002


7,002





(17
)%

(17
)%Williston Basin(1)


184


74


1,178


389


145


2,479


(53
)%

(49
)%

(52
)%Other


25


53


203


25


53


203








Total


586


57,678


61,194


696


47,928


52,104


(16
)%

20
%

17
%


---

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

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

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

Lease Operating Expense.The increase in lease operating expense to $0.68 per Mcfe in 2007 compared to $0.57 in 2006 is
primarily the result of
increased expenses in the Powder River, Wind River and Piceance Basins. Lease operating expense increased in the Powder River Basin to $1.65 per

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Table of Contents

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

Year Ended December 31, 2006

Year Ended December 31, 2007

% Increase/(Decrease)($ in thousands)

($ per Mcfe)

($ in thousands)

($ per Mcfe)

($ per Mcfe)Uinta Basin

$
10,715

$
0.41

$
5,805

$
0.35


17
%Piceance Basin


10,680


0.51


5,172


0.36


42
%Powder River Basin


9,614


1.65


7,363


1.05


57
%Wind River Basin


7,131


0.97


6,861


0.60


62
%Williston Basin


2,732


2.32


3,730


1.50


55
%Other


771


3.80


837


4.12


(8
)%Total

$
41,643


0.68

$
29,768


0.57


19
%


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

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

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

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

57

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exploration
costs. Exploration costs for 2006 consisted of $8.1 million for seismic programs, principally in the Montana Overthrust, Wind River, Paradox and DJ Basins, and $1.3 million
for delay rentals and other costs.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense increased to
$25.3 million in 2007
from $12.8 million in 2006. During 2007, impairment expense was $2.3 million, abandonment expenses were $2.7 million and dry holes and partial dry holes in the Wind River
(non-operated), Paradox and Uinta Basins were $12.6 million. In addition, we also expensed $7.7 million related to two wells in the Montana Overthrust area that were tested
and determined to be non-commercial in the zones below the Cody Shale; thus, a proportionate share of the well costs were expensed. During 2006, impairment expense was $1.2 million,
abandonment expenses were $1.6 million and dry hole costs were $10.0 million for wells drilled primarily in the Uinta and Williston Basins. For our Tri-State properties
within the DJ Basin, based upon our fair value analysis, we recognized a $2.3 million non-cash impairment charge in 2007. We sold these properties in early 2008.

The
following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of December 31, 2007
pending determination of whether the wells will be assigned proved reserves. The following table does not include $8.6 million related to exploratory wells in progress for which drilling had
not been completed at December 31, 2007:

Time Elapsed Since Drilling Completed0-3
Months

4-6
Months

7-12
Months

> 12
Months

Total(in thousands)Wells for which drilling has been completed

$
29,315

$
19,317

$
12,523

$
12,421

$
73,576


The
majority of the $12.4 million of exploratory well costs that have been capitalized for a period greater than one year are located in the Powder River Basin.

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

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

Non-cash
charges for stock-based compensation were $10.2 million in 2007 compared to $6.5 million in 2006. Non-cash stock-based compensation for
2007 and 2006 is related to vesting of our

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

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

Year Ended December 31,2007

2006(in thousands)Restricted common stock

$


$
38Stock options and nonvested equity shares of common stock


9,372


5,938Shares issued for 401(k) plan


619


515Shares issued for directors' fees


163


Total

$
10,154

$
6,491


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

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

Income Tax Expense.Our effective tax rates were 39.2% and 38.7% in 2007 and 2006, respectively. For both the 2007 and 2006
periods, our effective
tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense under Accounting Principles Board ("APB") Opinion No. 25, Accounting for Stock Issued to Employees, and SFAS No. 123R, that is not deductible for income tax purposes. We have a significant deferred tax
asset associated with NOLs. It is more likely than not that we will use these NOLs to offset and minimize current tax liabilities, including AMT, in future years.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been sales and other issuances of equity securities, net cash
provided by operating activities, bank credit facilities, convertible senior notes, proceeds from joint exploration agreements and sales of interests in properties. Our primary use of capital has been
for the exploration, development and acquisition of natural gas and oil properties. As we pursue profitable reserve and production growth, we continually monitor the capital resources, including
issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves
and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. Currently, the debt and equity markets are under considerable
stress and dislocation making financing transactions difficult and expensive to complete if they can be completed at all. However, we believe that we have significant liquidity available to us under
our Amended Credit Facility for our planned uses of capital. In addition, our strong hedge position

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provides
relative certainty on a significant portion of our cash flows from operations even upon a decline in the price of natural gas and oil resulting from decreased demand and the market crisis in
general. See below, "Trends and UncertaintiesDeclining Commodity Prices." We actively review acquisition opportunities on an ongoing basis. If we were to make significant
additional acquisitions for cash, we may need to obtain additional equity or debt financing, which under current market conditions we may not be able to obtain on terms acceptable to us or at all.

At
December 31, 2008, our balance sheet reflected a cash and cash equivalents balance of $43.1 million with a balance of $254.0 million of borrowings outstanding
under our Amended Credit Facility. At December 31, 2008, the borrowing base under our Amended Credit Facility (after a reduction for our Convertible Notes outstanding) was
$600.0 million, with commitments from over seven banks totaling $592.8 million.

Cash Flow from Operating Activities

Net cash provided by operating activities was $402.9 million, $251.5 million and $236.9 million in 2008, 2007 and
2006, respectively. The increases in net cash provided by operating activities were primarily due to an increase in oil and gas revenues, along with the changes in current assets and liabilities,
which were offset by increased expenses, as discussed above in "Results of Operations." Changes in current assets and liabilities increased cash flow from operations by
$18.0 million and $11.7 million in 2008 and 2007, respectively, and reduced cash flow from operations by $1.4 million in 2006.

Our
operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas and oil production. Prices for these commodities are
determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors influence market conditions
for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see "Item 7A.
Quantitative and Qualitative Disclosure about Market Risk" below.

To
mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices, we have entered into financial commodity swap and collar contracts to
receive fixed prices for a portion of our natural gas and oil production. We typically hedge a fixed price for natural gas at our sales points (New York Mercantile Exchange ("NYMEX") less basis) to
mitigate the risk of differentials to the NYMEX Henry Hub Index. At December 31, 2008, we had in place natural gas and crude oil financial collars and swaps covering portions of our 2009, 2010
and 2011 production.

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

All
derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value in accordance with SFAS
No. 157 and are included in the Consolidated Balance Sheets as assets or liabilities. As required under SFAS No. 157, all fair values are adjusted for non-performance risk.
For derivative instruments that qualify and are designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the
forecasted transaction occurs. The ineffective portion of hedge derivatives is reported in commodity derivative gain or loss in the Consolidated Statements of Operations. Realized gains and losses on
cash flow hedges are transferred from other comprehensive income and recognized in earnings and included within oil and gas production revenues in the Consolidated Statements of Operations as the
associated production occurs.

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If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time period, the hedging
instrument loses cash flow hedge accounting treatment in accordance with SFAS No. 133. All current mark-to-market gains and losses are recorded in earnings and all
accumulated gains or losses recorded in other comprehensive income related to the hedging instrument are also reclassified to earnings. Due to our limited ability to sell our natural gas out of the
Rocky Mountain region to the Mid-continent region at index prices, and due to an unexpected pipeline curtailment on Rockies Express that restricted our ability to transport to the
Mid-continent, a portion of our Mid-continent gas derivatives no longer qualified for hedge accounting during the year ended December 31, 2008. We therefore discontinued
hedge accounting for certain hedges during 2008. We recognized $1.0 million in unrealized net gain within commodity derivative gain in the Consolidated Statements of Operations for the year
ended December 31, 2008, attributable to hedges that no longer qualified for hedge accounting. While such derivative contracts no longer qualify for hedge accounting as of December 31,
2008, we believe that these contracts remain a valuable component of our commodity price risk management program.

Some
of our derivatives do not qualify for hedge accounting under SFAS No. 133 but are, to a degree, an economic offset to our commodity price exposure. If a derivative instrument
does not qualify as a cash flow hedge or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative gain or loss in the Consolidated
Statements of Operations. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash
flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument contract is settled by making or receiving a payment to or
from the counterparty. Realized
gains and losses of derivative instruments that do not qualify as cash flow hedges are recognized in commodity derivative gain or loss in the Consolidated Statements of Operations and are reflected in
cash flows from operations on the Consolidated Statements of Cash Flows.

During
the year ended December 31, 2008, in addition to the swaps and collars discussed above, we entered into basis only swaps. With a basis only swap, we have hedged the
difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. Although we believe this is a sound economic hedging strategy, the basis
only swaps do not qualify for hedge accounting under SFAS No. 133 because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments
are recorded in earnings. As of December 31, 2008, we had basis only hedges in place for a portion of our anticipated natural gas production in 2009, 2010 and 2011 for a total of 23,600,000
MMBtu. We recognized $0.04 million in unrealized net gain within commodity derivative gain in the Consolidated Statements of Operations for the year ended December 31, 2008 attributable
to these basis only swaps.

At
December 31, 2008, the estimated fair value of all of our commodity derivative instruments was a net asset of $313.8 million comprised of current and noncurrent assets,
including a fair value net asset of $0.04 million for basis only swaps. We will reclassify the appropriate cash flow hedge amounts to gains or losses included in natural gas and oil production
operating revenues as the hedged production quantities are produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of
December 31, 2008 to be reclassified from other comprehensive income to earnings in the next 12 months would be a gain of approximately $122.0 million. Any actual increase or
decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. We anticipate that all originally forecasted transactions related to our
derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods.

The
hedge instruments designated as cash flow hedges are at highly liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale,
which may result in ineffectiveness in accordance with SFAS No. 133. Ineffectiveness related to our cash flow

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derivative
instruments for the year ended December 31, 2008 was $6.8 million, which was reported in commodity derivative gain the Consolidated Statements of Operations. Although those
derivatives may not achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving our risk management objectives.
Ineffectiveness for the prior year periods was de minimis.

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

Year Ended December 31,2008

2007(in thousands)Realized gains on derivatives designated as cash flow hedges(1)

$
31,900

$
86,917Realized gains on derivatives not designated as cash flow hedges

$
62

$
Unrealized ineffectiveness recognized on derivatives designated as cash flow hedges


6,803


Unrealized gains on derivatives not designated as cash flow hedges


1,055


Total commodity derivative gain(2)

$
7,920

$







We
have in place the following swap contracts and cashless collars (purchased put options and written call options) as of December 31, 2008 in order to hedge a portion of our
natural gas and oil production for 2009 and 2010 and a portion of our natural gas for 2011. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and
oil production. During 2008, in addition to the swaps and collars, we also entered into basis only swaps. With a basis only swap, we

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have
hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location.

Contract

Total
Hedged
Volumes

Quantity
Type

Weighted
Average
Floor Price

Weighted
Average
Ceiling Price

Weighted
Average
Fixed Price

Basis
Differential

Index
Price(1)

Fair
Market Value(in thousands)Cashless Collars:2009Natural gas


6,375,000

MMBtu

$
7.00

$
9.94


N/A


N/A

CIGRM

$
17,506Natural gas


5,160,000

MMBtu

$
6.52

$
11.29


N/A


N/A

NWPL

$
12,965Oil


200,750

Bbls

$
86.82

$
143.51


N/A


N/A

WTI

$
6,8212010Natural gas


6,080,000

MMBtu

$
6.00

$
10.41


N/A


N/A

NWPL

$
9,122Natural gas


2,140,000

MMBtu

$
7.00

$
11.00


N/A


N/A

TCO

$
1,737Oil


109,500

Bbls

$
90.00

$
163.00


N/A


N/A

WTI

$
3,327Swap Contracts:2009Natural gas


47,120,000

MMBtu


N/A


N/A

$
7.18


N/A

CIGRM

$
141,145Natural gas


5,425,000

MMBtu


N/A


N/A

$
7.91


N/A

PEPL

$
16,569Natural gas


610,000

MMBtu


N/A


N/A

$
6.56


N/A

NWPL

$
1,299Oil


136,875

Bbls


N/A


N/A

$
74.41


N/A

WTI

$
2,6772010Natural gas


32,495,000

MMBtu


N/A


N/A

$
6.95


N/A

CIGRM

$
67,952Natural gas


3,040,000

MMBtu


N/A


N/A

$
6.52


N/A

NWPL

$
4,982Natural gas


1,666,000

MMBtu


N/A


N/A

$
7.74


N/A

PEPL

$
2,681Natural gas


2,140,000

MMBtu


N/A


N/A

$
9.43


N/A

DA

$
4,6952011Natural gas


7,300,000

MMBtu


N/A


N/A

$
7.64


N/A

CIGRM

$
14,650Natural gas


2,140,000

MMBtu


N/A


N/A

$
7.75


N/A

NWPL

$
5,607Basis Only Swap Contracts(2):2009Natural gas


2,750,000

MMBtu


N/A


N/A


N/A

$
(2.14
)
NWPL

$
(182
)Natural gas


610,000

MMBtu


N/A


N/A


N/A

$
(1.75
)
CIGRM

$
5012010Natural gas


6,690,000

MMBtu


N/A


N/A


N/A

$
(2.49
)
NWPL

$
(1,927
)Natural gas


6,250,000

MMBtu


N/A


N/A


N/A

$
(2.34
)
CIGRM

$
(108
)2011Natural gas


7,300,000

MMBtu


N/A


N/A


N/A

$
(1.72
)
NWPL

$
1,756


The following table includes all hedges entered into subsequent to December 31, 2008 through January 30, 2009.

Contract

Total
Hedged
Volumes

Quantity
Type

Weighted
Average
Floor Price

Weighted
Average
Ceiling Price

Weighted
Average
Fixed Price

Basis
Differential

Index
PriceSwap Contracts:2011Natural gas


2,140,000

MMBtu

N/A

N/A

$
4.92


N/A

CIGRMBasis Only Swap Contracts(2):2012Natural gas


7,320,000

MMBtu

N/A

N/A


N/A

$
(1.22
)
NWPL


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By removing the price volatility from a portion of our natural gas and oil production for 2009 and 2010 and a portion of our natural gas production for 2011 and
2012, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these
derivative contracts also limit the benefits we would receive from increases in commodity prices.

By
using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit
risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe
us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial
institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have hedges in place with eight different
counterparties, of which all but one are lenders in our Amended Credit Facility. As of December 31, 2008, JP Morgan Chase & Company, J. Aron & Company and Bank of Montreal
accounted for 43.6%, 22.8% and 15.1%, respectively, of the net fair market value of our derivative asset. We believe all of these institutions currently are acceptable credit risks. We are not
required to provide credit support or collateral to any of our counterparties under current contracts, nor are they required to provide credit support to us. As of January 30, 2009, we have no
past due receivables from any of our counterparties.

Capital Expenditures

Our capital expenditures are summarized in the following tables:

Year Ended December 31,Basin/Area

2008

2007

2006(in millions)Uinta

$
223.7

$
166.4

$
120.0Piceance


249.8


180.3


138.2Powder River


36.9


39.3


148.0Wind River


33.0


10.5


35.3Paradox


30.6


18.2


12.4Other


27.1


29.0


47.3Total

$
601.1

$
443.7

$
501.2




Year Ended December 31,2008

2007

2006(in millions)Acquisitions of proved and unevaluated properties and other real estate

$
38.5

$
23.9

$
159.3
(1)Drilling, development, exploration and exploitation of natural gas and oil properties(2)


542.9


383.4


318.5Geologic and geophysical costs and exploratory dry holes and abandonment costs


14.8


31.8


21.0Furniture, fixtures and equipment


4.9


4.6


2.4Total(3)

$
601.1

$
443.7

$
501.2


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Total
unevaluated properties increased $78.9 million to $315.2 million at December 31, 2008, from $236.3 million at December 31, 2007. The increase was
principally from an increase in wells in progress resulting from increased development and exploratory drilling activity during the year ended December 31, 2008.

Our
Board of Directors has approved a capital budget of $500 million for 2009; however, due to current commodity price forecasts and capital markets constraints, we plan to align
capital spending with cash flow from operations. Our current estimate is for a capital budget of up to $350 million, which may be adjusted throughout the year as business conditions warrant. We
expect that we have sufficient available liquidity through 2009 with the Amended Credit Facility, our hedge position and cash flow from operations. Future cash flows are subject to a number of
variables, including our level of natural gas and oil production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient
amounts of cash flow to maintain planned levels of capital expenditures.

The
amount, timing and allocation of capital expenditures is generally discretionary and within our control. If natural gas and oil prices decline to levels below our acceptable levels
or costs increase to levels above our acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and
uses of liquidity 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, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory
approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control.

Financing Activities

Credit Facility.Our Amended Credit Facility, which matures on March 17, 2011, has commitments of $592.8 million and,
based on
mid-year 2008 reserves and our hedge positions, a
borrowing base of $600.0 million (after a reduction related to our Convertible Notes outstanding). Future borrowing bases will be computed based on proved natural gas and oil reserves, hedge
positions and estimated future cash flows from those reserves, as well as any other outstanding debt. The borrowing base is required to be redetermined at least twice per year. The Amended Credit
Facility bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate ("LIBOR") plus applicable margins ranging from 1.25% to 2.00% or an alternate base rate,
based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.00% plus applicable margins ranging from 0.25% to 1.00%. We pay commitment
fees ranging from 0.35% to 0.50% of the unused borrowing base. The Amended Credit Facility is secured by natural gas and oil properties representing at least 80% of the value of our proved reserves
and the pledge of all of the stock of our subsidiaries. For information concerning the effect of changes in interest rates on interest payments under this facility, see "Item 7A. Quantitative
and Qualitative Disclosure about Market RiskInterest Rate Risks" below.

As
of December 31, 2008 and 2007, borrowings outstanding under the Amended Credit Facility totaled $254.0 and $274.0 million, respectively. The Amended Credit Facility also
contains certain

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financial
covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants for all prior periods.

In
December 2006, we entered into two interest rate derivative contracts to manage our exposure to changes in interest rates. The first contract was a
floating-to-fixed interest rate swap for a notional amount of $10.0 million and the second was a floating-to-fixed interest rate collar for a
notional amount of $10.0 million, both to terminate on December 12, 2009. Under the swap, we will make payments to (or receive payments from) the contract counterparty when the variable
rate of one-month LIBOR falls below (or exceeds) the fixed rate of 4.70%. Under the collar, we will make payments to (or receive payments from) the contract counterparty when the variable
rate falls below the floor rate of 4.50% or exceeds the ceiling rate of 4.95%. Our interest rate derivative instruments have been designated as cash flow hedges in accordance with SFAS No. 133.
Changes in fair value of the interest rate swaps or collars are reported in other comprehensive income, to the extent the hedge is effective, until the forecasted transaction occurs, at which time
they are recorded as adjustments to interest expense. Ineffectiveness related to such derivative instruments was de minimis for both the years ended December 31, 2008 and 2007.

During
the year ended December 31, 2008, net settlement payments on the interest rate derivative contracts, which were included in interest expense, were $0.3 million. We
anticipate that all originally forecasted transactions will occur by the end of the originally specified time periods. As of December 31, 2008, based on current projected interest rates, the
amount to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be a reduction of approximately $0.3 million. At December 31, 2008,
the estimated fair value of the interest rate derivatives was a liability of $0.5 million.

Convertible Notes.On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. The
full
$172.5 million principal amount of the Convertible Notes is currently outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed, or purchased by us.
The conversion price is approximately $66.33 per share of our common stock, equal to the applicable conversion rate of 15.0761 shares of our common stock, subject to adjustment upon certain events.
Upon conversion of the Convertible Notes, holders will receive, at our election, cash, shares of common stock, or a combination of cash and shares of common stock. The Convertible Notes bear interest
at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year, beginning September 15, 2008. The Convertible Notes are not
traded on a public exchange. Therefore, based on market-based parameters of the various components of the Convertible Note, the estimated fair value was approximately $120.4 million as of
December 31, 2008.

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

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

Holders
may convert their Convertible Notes into cash, shares of our common stock, or a combination of cash and shares of our common stock, as elected by us, at any time prior to the
close of business on September 20, 2027, if any of the following conditions are satisfied: (1) if the closing price

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of
our common stock reaches specified thresholds or the trading price of the Convertible Notes falls below specified thresholds; (2) if the Convertible Notes have been called for redemption;
(3) if we make certain significant distributions to holders of our common stock, or (4) we enter into specified corporate transactions, none of which occurred during 2008 or through the
date of the filing of this Form 10-K. After September 20, 2027, holders may surrender their Convertible Notes for conversion at any time prior to the close of business on the
business day immediately preceding the maturity date regardless of whether any of the foregoing conditions have been satisfied.

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

Contractual Obligations.A summary of our contractual obligations as of and subsequent to December 31, 2008 is provided in
the following
table.

Payments Due By Year2009

2010

2011

2012

2013

After 2014

Total(in thousands)Notes payable(1)

$


$


$
254,000

$


$


$


$
254,000Convertible Notes(2)


8,625


8,625


8,625


174,536








200,411Purchase commitments(3)(7)


8,161


8,161


7,050











23,372Drilling rig commitments(4)(7)


23,629


16,389


2,250











42,268Office and office equipment leases and other


2,554


2,554


743











5,851Firm transportation and processing agreements(7)


25,818


29,816


50,569


54,236


53,950


323,962


538,351Asset retirement obligations(5)


506


9,037


2,462


1,640


939


32,609


47,193Derivative liability(6)


509

















509Total

$
69,802

$
74,582

$
325,699

$
230,412

$
54,889

$
356,571

$
1,111,955


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

Trends and Uncertainties



Our future Rocky Mountain operations and cost of doing business may be affected by changes in regulations and the ability to obtain
drilling permits. Our properties located in Colorado are subject to the authority of the COGCC. The COGCC has the authority to regulate oil and gas activities to protect public health, safety and
welfare, including the environment and wildlife. In 2007, the Colorado legislature approved legislation changing the composition of the COGCC to reduce industry representation and to add the heads of
the CDNR and the CDPHE plus other stakeholders. In addition, the legislation required the COGCC to promulgate rules (1) in consultation with CDPHE, to provide CDPHE an opportunity to provide
comments on public health issues during the COGCC's decision-making process and (2) in consultation with the CDOW, to establish standards for minimizing adverse impacts to wildlife resources
affected by oil and gas operations and to ensure the proper reclamation of wildlife habitat during and following such operations. These rules become effective April 1, 2009 for the majority of
our operations area. We believe the revised rules will cause additional costs and may cause delay in our operations in Colorado. The rules require consultation with the CDOW and CDPHE prior to
drilling and completion operations in our Piceance Basin and for the portion of the Paradox Basin located in Colorado. The requirements for this consultation are open-ended and resulting
permit restrictions remain subject to appeal by the CDOW, CDPHE and the surface owner. The CDOW may attempt to prohibit drilling and completion operations for some period corresponding to wildlife's
use of the habitat. CDPHE may choose to impose costly conditions of approval and limit the areas that can be developed. If we were not able to avoid adverse requirements, our Piceance Basin and, if
our Paradox Basin exploratory activities are successful, the Colorado portion of our Paradox Basin production and production growth would be reduced. In addition, the costs of these and the other
proposed rules could add substantial increases in incremental well costs in our Colorado operations. The rules also would impact the ability and extend the time necessary to obtain drilling permits,
which creates substantial uncertainty about our ability to obtain sufficient permits in a timely fashion in order to meet future drilling plans and thus production and capital expenditure targets. It
is also possible that similar rules will be proposed in the other states in which we operate, further impacting our operations.

The
regulatory environment continues to become more restrictive, which limits our ability and increases the cost to conduct our operations. Areas in which we operate are subject to
federal, state, local and tribal regulations. All these jurisdictions have imposed additional and more restrictive regulations recently and there are initiatives underway to implement additional
regulations and prohibitions on oil and gas activities.

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Federal.At the federal level, the new presidential administration and its appointees to the Department of Interior and other
posts have made public
statements that indicate a more restrictive regulatory environment for oil and gas activities is in effect and that additional restrictions can be expected. Secretary of the Interior Salazar ordered
the review of many actions undertaken under the previous administration and directed the BLM not to issue oil and gas leases in Utah that were auctioned in December 2008 and to return the bid money
paid for those leases. As a result, we will not receive leases on prospective leases near our West Tavaputs project for which we were the high bidder. The auction of these leases also was challenged
by environmental groups in a court action filed in federal court in Washington, D.C. and a temporary injunction previously was issued barring the issuance of the leases. This lawsuit also seeks review
of federal resource management plans prepared by the BLM for areas of Utah, including areas in which we operate. If this challenge is successful, it could impact our ability to operate and the
issuance of the EIS for our West Tavaputs full field development. Based on public statements by environmental groups and their fundraising efforts, we expect additional litigation seeking to halt our
and other companies' exploration and development activities in the West Tavaputs area and throughout the Rocky Mountain Region. The BLM and the U.S. Forest Service also have withdrawn parcels from
planned lease sales in other states near our areas of operations. Legislative proposals of the previous congress to regulate hydraulic fracturing under the Clean Drinking Water Act, cause expiration
of undeveloped leases, eliminate funding for processing of Federal drilling permits, and to eliminate categorical exclusions for oil and gas activities are likely to be reintroduced. Based on the
actions of the Secretary of Interior and other officials, we expect additional restrictions, delays or prohibitions to be implemented. In addition, the issuance of the record of decision to approve
the environmental impact study prepared over the past four years for our West Tavaputs full field development has been delayed pending the appointment of new management at the BLM and Department of
Interior as part of the transition of the administration of President Obama.

State.We also are experiencing increased attempts to more strictly regulate oil and gas activities at the state level. Recent
regulation includes
changes in the makeup of the Colorado Oil and Gas Conservation Commission, or COGCC, and new rules imposed by the COGCC as described above under "Regulatory", and proposals in the
Colorado, Wyoming and Utah legislatures affecting oil and gas activities. Legislation has been introduced in other states that mimics that passed in Colorado and several states have proposed severance
tax increases

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

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

Potential Impacts of Regulatory Trends.The increase in regulatory burdens and potential for continued lawsuits seeking to block
activities as
described above is likely to cause delays to our planned activities and could prevent some of these activities. This is expected to increase our costs and could result in lower production and reserves
as our properties naturally decline without replacement production and reserves from new wells as well as a reduction in the value of our accumulated leases, especially federal leases which make up
approximately 50% of our leasehold. We currently are unable to estimate the magnitude of these potential losses.

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In the last several months, we have experienced steep declines in natural gas and oil prices. If this trend continues, or the current
relatively low prices persist, it could increase the likelihood of impairments and write-downs of properties, reduce our reserves and thus the borrowing base of our Amended Credit Facility and have a
significant negative impact on our cash flows used to fund operations and capital expenditures.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements,
which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and
uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We
evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the
results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these
estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We
believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 of the Notes to the
Consolidated Financial Statements for a discussion of additional accounting policies and estimates made by management.

Oil and Gas Properties

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

The
application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory,
which will ultimately determine the proper accounting treatment of the costs incurred. In addition to development on exploratory wells, we may drill scientific wells that are only used for data
gathering purposes. The costs associated with these scientific wells are expensed as incurred as geological and geographical expense. The results from a drilling operation can take considerable time
to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience.

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

Unevaluated
oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. Proceeds from sales of partial
interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unevaluated oil and gas properties are assessed periodically for
impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage.
During the year ended December 31, 2008, we recognized a non-cash impairment charge of $4.3 million primarily on the carrying value of unevaluated oil and gas properties in
the Talon field located in the Wind River Basin.

We
review our proved natural gas and oil properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have
occurred. We estimate the expected future cash flows of our gas and oil properties and compare these future cash flows to the carrying amount of the gas and oil properties to determine if the carrying
amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the natural gas and oil properties to fair value. The factors
used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs
using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk associated with
realizing the expected cash flows projected. For 2008, our impairment testing required us to take a non-cash impairment charge to our proved oil and gas properties in the Cooper Reservoir
field, located in the Wind River Basin, of $21.0 million, which was primarily the result of geologic and engineering reevaluations, as well as lower oil and gas prices. Both the Talon and
Cooper Reservoir fields are not considered strategic areas for future operations. In 2007, based upon our fair value analysis, we recognized a $2.3 million non-cash impairment
charge associated with our Tri-State properties within the DJ Basin. We sold these properties in 2008.

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

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

The
recognition of an asset retirement obligation, or ARO, requires that management make numerous estimates, assumptions and judgments regarding such factors as amounts, future advances
in technology, timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. In periods subsequent to initial measurement of the ARO, we must recognize
period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate

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of
undiscounted cash flows or changes in inflation factors and changes to our credit-adjusted risk-free rate as market conditions warrant. Any such changes that result in upward or
downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our DD&A expense in
future periods.

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

Oil and Gas Reserve Quantities

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

Reserves
and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made
concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent
engineering firms 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.

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

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

As
of December 31, 2007, we revised our proved reserves upward by 34.8 Bcfe, excluding pricing revisions, primarily as a result of adding increased density proved undeveloped
locations in the West Tavaputs field and continued improved performance of wells drilled in the West Tavaputs and Piceance

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fields.
We also revised our 2007 year-end proved reserves upward by 19.4 Bcfe, as year-end 2007 pricing was $6.04 per MMBtu and $92.50 per barrel of oil, relative to
year-end 2006 at prices of $4.46 per MMBtu of gas and $61.06 per barrel of oil. Year-end prices were adjusted by lease for quality, transportation fees and regional price
differences.

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

Revenue Recognition

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

We
may have an interest with other producers in certain properties, in which case we use the sales method to account for natural gas imbalances. Under this method, revenue is recorded on
the basis of natural gas actually sold by us. In addition, we record revenue for our share of natural gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient
remaining reserves. We also reduce revenue for other owners' natural gas sold by us 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, 2008 and 2007 were not significant.

Derivative Instruments and Hedging Activities

We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas and oil production by
reducing our exposure to price fluctuations. We also enter into derivative contracts to mitigate the risk of interest rate fluctuations. For the year ended December 31, 2008, these transactions
included swaps, basis only swaps and cashless collars. We account for these activities pursuant to SFAS No. 133, as amended. This statement establishes accounting and reporting standards
requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or
liabilities.

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

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.

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

The
estimates of the fair values of our derivative instruments require substantial judgment. These values are based upon, among other things, option pricing models, futures prices,
volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other
factors, many of which are beyond our control.

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

As
of December 31, 2008, the fair value of all of our derivative instruments, including basis only swaps and interest rate derivatives, was a net asset of $313.3 million,
comprised of current and noncurrent assets and liabilities. The deferred income tax effect on the fair value of the cash flow hedge derivatives at December 31, 2008 totaled
$113.3 million, which is recorded in current and noncurrent deferred tax liabilities.

Income Taxes and Uncertain Tax Positions

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently
payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities
represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax
credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statement and income tax
reporting. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized
under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in
the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). There can be no assurance that
facts and circumstances will not materially change and require us to establish deferred tax asset valuation allowances in a future period.

Stock-based Compensation

We account for stock-based compensation in accordance with SFAS No. 123R, which revised SFAS No. 123, Accounting for Stock-Based
Compensation, and supersedes APB Opinion No. 25,Accounting for Stock Issued to
Employees. This statement requires us to record expense associated with the fair value of stock-based compensation. However, for awards granted before we were a public company
(i.e. those granted prior to April 16, 2004, which is defined by SFAS No. 123R as the date we became a public company as a result of filing our Form S-1
registration statement with the SEC) we continue to use the minimum value method described under APB Opinion No. 25. For awards granted after we were a public company (i.e. those granted
subsequent to April 16, 2004), and for new, modified, repurchased,

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or
cancelled awards on or subsequent to our adoption of SFAS No. 123R on October 1, 2004, we recognized share-based employee compensation cost based on the fair value as computed under
SFAS No. 123R.

We
continue to account for certain stock options under the original provisions of APB Opinion No. 25 because those options were issued prior to April 16, 2004. Under APB
Opinion No. 25, we recognize compensation expense only to the extent that the exercise price of the options granted exceeds the market value of the underlying common stock on the date of grant.

In
applying the provisions of SFAS No. 123R, judgments and estimates are made regarding, among other things, the appropriate valuation methodology to follow in valuing stock
compensation awards and the related inputs required by those valuation methodologies. Assumptions regarding expected volatility of our common stock, the risk-free interest rates, expected
term of the awards and other valuation inputs are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized.

In
total, under APB Opinion No. 25 and SFAS No. 123R, we recorded non-cash stock-based compensation of $16.8 million, $9.9 million, and
$6.5 million in 2008, 2007 and 2006, respectively, for option grants, option modifications, nonvested equity shares of common stock and nonvested performance-based equity shares of common
stock.

Acquisitions

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

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

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

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

We
also apply these same general principles in arriving at the fair value of unevaluated properties acquired in an acquisition. These unevaluated properties generally represent the value
of probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more

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imprecise
than those of proved reserves. To compensate for the inherent risk of estimating and valuing probable and possible reserves, we apply a risk-weighting factor to probable and
possible volumes to reduce the estimated reserve volumes. Additionally, we increase the discount factor,
compared to proved reserves, to recognize the additional uncertainties related to determining the value of probable and possible reserves.

New Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. SFAS
No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement. We partially adopted SFAS No. 157 as of
January 1, 2008, pursuant to FASB Staff Position ("FSP") No. FAS 157-2,Effective Date of FASB Statement No. 157, which
delayed the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after
November 15, 2008. With partial adoption, we applied SFAS No. 157 to recurring fair value measurements of financial and non-financial instruments, which affected the fair
value disclosures of our financial derivatives within the scope of SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.
See Footnote 7 for fair value disclosures.

As
of January 1, 2009, we fully adopted SFAS No. 157, requiring fair value measurements of nonfinancial assets and nonfinancial liabilities, including nonfinancial
long-lived assets measured at fair value for an impairment assessment under SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived
Assets, and asset retirement obligations initially measured at fair value under SFAS No. 143,Accounting for Asset Retirement
Obligations. The full adoption of SFAS No. 157 is not expected to have a material impact on our financial statements.

In
February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities, which permits
entities to choose to measure many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair
value option. We adopted this statement as of January 1, 2008; however, we did not elect the fair value option for any eligible financial instruments or other items. Therefore, the adoption of
this statement did not impact our financial statements.

In
December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations("SFAS No. 141R"), which replaces FASB
Statement No. 141,Business Combinations. This statement requires an acquirer to recognize the assets acquired, the liabilities assumed and any
noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified in the statement. This includes the measurement of the
acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for pre-acquisition gain and loss contingencies, the
recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs
and the recognition of changes in the acquirer's income tax valuation allowance and deferred taxes. This statement applies prospectively and was effective for us beginning January 1, 2009. SFAS
No. 141R will only impact us if and when we become party to a business combination.

In
March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities. This statement is
intended to improve financial reporting about derivative instruments and hedging activities by requiring companies to enhance disclosure about how these instruments and activities affect their
financial position, performance and cash flows. SFAS No. 161 seeks to achieve these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses
in a tabular format. It also seeks to improve the transparency of the location and amounts of derivative instruments in a company's financial statements and how they are accounted

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for
under SFAS No. 133. This statement was effective for us beginning January 1, 2009. The adoption of SFAS No. 161 is not expected to have a material impact on our financial
statements.

In
May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles. This statement is intended to
improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with
GAAP for nongovernmental entities. Prior to the issuance of SFAS No. 162, GAAP hierarchy was defined in the American Institute of Certified Public Accountants ("AICPA") Statement on Auditing
Standards ("SAS") No. 69,The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. SFAS No. 162 was
effective November 15, 2008 and did not have a material impact on our financial statements.

In
May 2008, the FASB adopted FSP APB 14-1,Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (including
Partial Cash Settlement). FSP APB 14-1 states that the accounting treatment for certain convertible debt instruments that may be settled in cash, shares of
common stock or any portion thereof at the election of the issuing company be accounted for utilizing a bifurcation model under which the value of the debt instrument would be determined without
regard to the conversion feature. The difference between the issuance amount of the debt instrument and the value determined pursuant to FSP APB 14-1 will be recorded as an equity
contribution. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. FSP
APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008. We adopted FSP APB 14-1 effective
January 1, 2009 as early adoption was not permitted. FSP APB 14-1 must be applied retrospectively to all periods presented for any instrument within the scope of FSP
APB 14-1 that was outstanding during any of the periods presented. FSP APB 14-1 changes the accounting treatment for our Convertible Notes which were issued in
March 2008. At adoption, FSP APB 14-1 will retrospectively reduce the Company's long-term debt and increase the Company's stockholders' equity by approximately
$23 million and increase the Company's non-cash interest expense by approximately $4 million and $6 million for the years ended December 31, 2008 and 2009,
respectively.

In
October 2008, the FASB issued FSP No. FAS 157-3,Determining the Fair Value of a Financial Asset When the Market for That Asset is Not
Active. FSP No. FAS 157-3 clarifies
the application of SFAS No. 157 as it relates to the valuation of financial assets in a market that is not active for those financial assets. This FSP is effective immediately and includes
those periods for which financial statements have not been issued. We currently do not have any financial assets that are valued using inactive markets, and as a result, we were not impacted by the
issuance of FSP No. FAS 157-3.

On
December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reserves reporting requirements. Many of the revisions are updates to
definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which is a widely accepted set of evaluation guidelines that are designed to
support assessment processes throughout the resource asset lifecycle. These guidelines were prepared by the Society of Petroleum Engineers, or SPE, Oil and Gas Reserves Committee with cooperation from
many industry organizations. One of the key changes to the previous SEC rules relates to using a 12-month average commodity price to calculate the value of proved reserves versus the
current method of using year-end prices. Other key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, the
opportunity to establish proved undeveloped reserves without the requirement of an adjacent producing well and permitting disclosure of probable and possible reserves. The SEC will require companies
to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009.
Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on the Company's disclosures and financial statements.

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Item 7A.    Quantitative and Qualitative Disclosure About Market Risk

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

Commodity Price Risk

Our primary market risk exposure is in the price we received for our natural gas and oil production. Realized pricing is primarily
driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and
unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in
the differences between product prices at sales points and the applicable index price. Based on our average daily production and our price swap and collar contracts in place during 2008, our annual
income before income taxes for the year ended December 31, 2008 would have decreased by approximately $1.6 million for each $0.10 decrease per MMBtu in natural gas prices and
approximately $0.2 million for each $1.00 per barrel decrease in crude oil prices.

We
routinely enter into and anticipate entering into financial hedging activities with respect to a portion of our projected natural gas and oil production through various financial
transactions which hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the
contract counterparty and cashless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and
ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference. These financial hedging activities are intended to support natural gas and oil
prices at targeted levels and to manage our exposure to natural gas and oil price fluctuations. In addition to the swaps and collars discussed above, we also entered into basis only swaps. With a
basis only swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location to protect against the risk of large
differences between NYMEX (Henry Hub) and our primary sales point, CIG. Large basis differentials have occurred recently due to pipeline infrastructure issues.

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

For
the calendar year 2009, we currently have financial hedges in place for 64,690,000 MMBtu of natural gas production and 337,625 Bbls of oil production. As of January 30, 2009,
we have hedges in place for 47,561,000 MMBtu of natural gas production and 109,500 Bbls of oil production for 2010 and 11,580,000 MMBtu of natural gas production for 2011. In addition, we have basis
only swaps in place for 3,360,000 MMBtu of natural gas for 2009, 12,940,000 MMBtu of natural gas for 2010, 7,300,000 MMBtu of natural gas for 2011 and 7,320,000 MMBtu of natural gas for 2012. These
hedges are summarized in the table presented under "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of OperationsCapital Resources and LiquidityCash Flow from Operating Activities."

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Commodity Hedges

Through a price swap, we have fixed the price we will receive on a portion of our natural gas and oil production. In a swap
transaction, the counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required
to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price.

Through
a basis only swap, we have fixed the price differential on our natural gas production between NYMEX and a specific delivery location. In a basis only swap, the counterparty is
required to make a payment to us if the price differential is greater than the fixed price. We are required to make a payment to the counterparty if the price differential is less than the fixed
price. We intend to enter into hedge transactions based on a NYMEX price in the future with a volume equal to the volume for our basis only swaps, thereby effectively fixing a price for CIGRM.

Through
cashless collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas and oil production. In a cashless 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 prices. These hedges are summarized in the table presented under "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of OperationsCapital Resources and LiquidityCash Flow from Operating Activities."

Interest Rate Risks

At December 31, 2008, we had debt outstanding under our Amended Credit Facility of $254.0 million, which bears interest
at floating rates in accordance with our Amended Credit Facility. The average annual interest rate incurred on this debt for the years ended December 31, 2008 and 2007 was 5.5% and 6.3%,
respectively. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the year ended December 31, 2008 would have resulted in an estimated $1.4 million increase in
interest expense for the year ended December 31, 2008. We also had $172.5 million principal amount of Convertible Notes outstanding at December 31, 2008, which have a fixed cash
interest rate of 5.0% per annum.

Interest Rate Hedges

Through interest rate derivative contracts, we have attempted to mitigate exposure to changes in interest rates. We entered into an
interest rate swap for a notional amount of $10.0 million for a fixed LIBOR rate of 4.70% through December 2009. We also entered into an interest rate collar for a notional amount of
$10.0 million in which the interest rate has fixed minimum and maximum LIBOR rates of 4.50% and 4.95%, respectively, through December 2009.

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.

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Item 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures.Based on an evaluation carried out under the supervision and with the participation
of our
management, including our Chief Executive Officer and Chief Financial Officer, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures, as defined
in Securities Exchange Act Rules 13a-15(e) and 15d-15(e), were, as of December 31, 2008, effective.

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



Management
is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f)
and 15d-15(f). Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, our management conducted an evaluation of
the effectiveness of our internal control over financial reporting based on the framework in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission. Based on its evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2008.

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

Changes in Internal Controls.There has been no change in our internal control over financial reporting during the fourth fiscal
quarter of 2008 that
has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To
the Board of Directors and Stockholders of
Bill Barrett Corporation Denver, Colorado

We
have audited the internal control over financial reporting of Bill Barrett Corporation and subsidiaries (the "Company") as of December 31, 2008, based on criteria established
inInternal ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's
management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the
accompanyingManagement's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal
control over financial reporting based on our audit.

We
conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and
performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In
our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal ControlIntegrated
Frameworkissued 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, 2008 of the Company and our report dated February 24, 2009, expressed an unqualified opinion on those financial statements.

/s/
Deloitte & Touche LLP

Denver,
Colorado
February 24, 2009

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Item 9B.    Other Information

Not applicable.

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PART III

Item 10.    Directors, Executive Officers and Corporate Governance

Information regarding our directors and executive officers will be included in an amendment to this Form 10-K or in
the "Directors and Executive Officers" section of the proxy statement for the 2009 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2008,
and is incorporated by reference to this report.

Item 11.    Executive Compensation

Information regarding executive compensation will be included in an amendment to this Form 10-K or in the "Executive
Compensation" section of the proxy statement for the 2009 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2008, and is incorporated by
reference to this report.

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

Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the "Beneficial
Owners of Securities" section of the proxy statement for the 2009 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2008, and is incorporated
by reference to this report.

Equity Compensation Plan Information

The following table provides aggregate information presented as of December 31, 2008 with respect to all compensation plans
under which equity securities are authorized for issuance.

Plan Category

(a)
Number of Securities
to Be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights

(b)
Weighted Averaged
Exercise Price of
Outstanding
Options, Warrants
and Rights

(c)
Number of Securities
Remaining Available
for Future Issuance
(Excluding Securities
Reflected in Column (a))Equity compensation plans approved by shareholders


3,970,347

$
31.92
(1)

3,814,166Equity compensation plans not approved by shareholders








Total


3,970,347

$
31.92


3,814,166


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Item 13.    Certain Relationships and Related Transactions and Director Independence

Information regarding certain relationships and related transactions will be included in an amendment to this
Form 10-K or in the "Transactions Between the Company and Related Parties" and "Directors and Executive Officers" section of the proxy statement for the 2009 annual meeting of
stockholders, in either case, to be filed within 120 days after December 31, 2008, and is incorporated by reference to this report.

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Item 14.    Principal Accounting Fees and Services

Information regarding principal accounting fees and services will be included in an amendment to this Form 10-K or
in the "Fees to Independent Auditors" section of the proxy statement for the 2009 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2008, and
is incorporated by reference to this report.

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PART IV

Item 15.    Exhibits, Financial Statement Schedules

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

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

(a)(3) Exhibits.

Exhibit
Number

Description of Exhibits1.1

Underwriting Agreement, dated March 4, 2008, among Bill Barrett Corporation and Deutche Bank Securities Inc., Banc of America Securities LLC, and J.P. Morgan Securities Inc., as representatives of the
several underwriters identified therein. [Incorporated by reference to Exhibit 1.1 of our Current Report on Form 8-K filed with the Commission on March 10, 2008.]3.1

Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 of our Current Report on Form 8-K filed with the Commission on December 20, 2004.]3.2

Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.5 of our Current Report on Form 8-K filed with the Commission on December 20, 2004.]4.1(a)

Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20,
2004.]4.1(b)

Indenture, dated March 12, 2008, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed
with the Commission on March 12, 2008.]4.2(a)

Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 of Amendment No. 2 to our Registration
Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]4.2(b)

First Supplemental Indenture, dated March 12, 2008, by and between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 5% Convertible Senior Notes due 2028).
[Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]4.3

Stockholders' Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to Amendment No. 2 to our
Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]4.4

Form of Rights Agreement concerning Shareholder Rights Plan, which includes, as Exhibit A thereto, the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation,
 and, as Exhibit B thereto, the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]


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Exhibit
Number

Description of Exhibits4.5

Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our
Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]4.6

Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20,
2004.]10.1(a)

Second Amended and Restated Credit Agreement, dated March 17, 2006, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our Current Report on
Form 8-K filed with the Commission on March 22, 2006.]10.1(b)

First Amendment to Second Amended and Restated Credit Agreement dated as November 6, 2007 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our Current
Report on Form 8-K filed with the Commission on November 7, 2007.]10.1(c)

Second Amendment to Second Amended and Restated Credit Agreement, dated as of March 4, 2008, among Bill Barrett Corporation, as borrower, the Guarantors, JPMorgan Chase Bank, N.A., as administrative agent, and
the lenders party thereto. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on March 10, 2008.]10.1(d)

Third Amendment to Second Amended and Restated Credit Agreement, dated as of October 20, 2008, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our
Current Report on Form 8-K filed with the Commission on October 21, 2008.]10.2

Stock Purchase Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 10.2 to Amendment No. 2 to our Registration
Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]10.3(a)*

Form of Indemnification Agreement dated April 15, 2004, between Bill Barrett Corporation and each of the directors and certain executive officers of the Company. [Incorporated by reference to Exhibit 10.10(a)
 to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]10.3(b)*

Schedule of officers and directors party to Indemnification Agreements dated April 15, 2004 with Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.10(b) to Amendment No. 2 to our
Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]10.4*

Amended and Restated 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.12 to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the
Commission on August 31, 2004.]10.5(a)*

Form of Tranche A Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(a) to Amendment No. 4 to our Registration Statement on Form S-1 (Registration
No. 333-114554) filed with the Commission on October 13, 2004.]


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Exhibit
Number

Description of Exhibits10.5(b)*

Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(b) to Amendment No. 4 to our Registration Statement on Form S-1 (Registration
No. 333-114554) filed with the Commission on October 13, 2004.]10.6*

2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to Amendment No. 3 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on
September 22, 2004.]10.7*

Form of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554)
filed with the Commission on October 13, 2004.]10.8

Form of Management Rights Agreement between Bill Barrett Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to Amendment No. 4 to our Registration Statement on Form S-1
(Registration No. 333-114554) filed with the Commission on October 13, 2004.]10.9

Regulatory Sideletter, dated March 28, 2002, between J.P. Morgan Partners (BHCA), L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.17 to Amendment No. 4 to our
Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]10.10*

Form of Change in Control Severance Protection Agreement, revised as of November 16, 2006, for named executive officers. [Incorporated by reference to Exhibit 10.10 to our Annual Report on Form 10-K for
the year ended December 31, 2006.]10.11*

2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on
October 13, 2004.]10.12*

Revised Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.19 to our Annual Report on Form 10-K for the year ended December 31, 2005.]10.13*

Form of Restricted Common Stock Award Agreement for 2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10-19 to our Annual Report on Form 10-K for the year ended December 31,
2005.]10.14*

Form of Performance Vesting Restricted Stock Agreement for 2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10-19 to our Annual Report on Form 10-K for the year ended December 31,
2005.]10.15*

2008 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on May 16, 2008.]10.16* **

Form of Stock Option Agreement for 2008 Stock Incentive Plan.10.17*

Severance Plan. [Incorporated by reference to Exhibit 10.23 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13,
2004.]14

Code of Business Conduct and Ethics [Incorporated by reference to Exhibit 14 to our Annual Report on Form 10-K for the year ended December 31, 2004.]21.1**

Subsidiaries of the Registrant.23.1**

Consent of Deloitte & Touche LLP.


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Exhibit
Number

Description of Exhibits23.2**

Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers.31.1**

Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.31.2**

Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.32**

Section 1350 Certification of Chief Executive Officer and Chief Financial Officer.


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SIGNATURES

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

BILL BARRETT CORPORATIONDate: February 24, 2009

By:

/s/FREDRICK J. BARRETT Fredrick J. Barrett Chairman and Chief Executive Officer


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

Signature

Title

Date/s/ FREDRICK J. BARRETT Fredrick J. Barrett

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

February 24, 2009/s/ ROBERT W. HOWARD Robert W. Howard

Chief Financial Officer and Treasurer (Principal Financial Officer)

February 24, 2009/s/ JOSEPH N. JAGGERS Joseph N. Jaggers

Director; Chief Operating Officer and President

February 24, 2009/s/ DAVID R. MACOSKO David R. Macosko

Vice PresidentAccounting (Principal Accounting Officer)

February 24, 2009/s/ JAMES M. FITZGIBBONS James M. Fitzgibbons

Director

February 24, 2009/s/ RANDY A. FOUTCH Randy A. Foutch

Director

February 24, 2009/s/ JEFFREY A. HARRIS Jeffrey A. Harris

Director

February 24, 2009


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Signature

Title

Date/s/ JIM W. MOGG Jim W. Mogg

Director

February 24, 2009/s/ RANDY STEIN Randy Stein

Director

February 24, 2009/s/ MICHAEL E. WILEY Michael E. Wiley

Director

February 24, 2009


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FINANCIAL STATEMENTS        INDEX TO FINANCIAL STATEMENTS



Bill Barrett CorporationReport of Independent Registered Public Accounting Firm

F-2Consolidated Balance Sheets, December 31, 2008 and 2007

F-3Consolidated Statements of Operations, for the years ended December 31, 2008, 2007
and 2006

F-4Consolidated Statements of Stockholders' Equity and Comprehensive Income, for the years ended
December 31, 2008, 2007 and 2006

F-5Consolidated Statements of Cash Flows, for the years ended December 31, 2008, 2007 and
2006

F-6Notes to Consolidated Financial Statements

F-7


F-1

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To
the Board of Directors and Stockholders of
Bill Barrett Corporation
Denver, Colorado

We
have audited the accompanying consolidated balance sheets of Bill Barrett Corporation and subsidiaries (the "Company") as of December 31, 2008 and 2007, and the related
consolidated statements of operations, stockholders' equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008. These financial
statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.

In
our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Bill Barrett Corporation and subsidiaries as of
December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting
principles generally accepted in the United States of America.

We
have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of
December 31, 2008, based on the criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our
report dated February 24, 2009 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/
Deloitte & Touche LLP

Denver,
Colorado
February 24, 2009

F-2

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BILL BARRETT CORPORATION        CONSOLIDATED BALANCE SHEETS

As of December 31,2008

2007(in thousands, except share and per share data)Assets:Current Assets:Cash and cash equivalents

$
43,063

$
60,285Accounts receivable, net of allowance for doubtful accounts of $840 and $303 as of December 31, 2008 and 2007, respectively


66,427


50,380Prepayments and other current assets


3,924


3,425Derivative assets


199,960


17,337Total current assets


313,374


131,427Property and EquipmentAt cost, successful efforts method for oil and gas properties:Proved oil and gas properties


1,977,535


1,472,834Unevaluated oil and gas properties, excluded from amortization


315,239


231,521Oil and gas properties held for sale, net, excluded from amortization





2,303Furniture, equipment and other


20,971


16,1132,313,745


1,722,771Accumulated depreciation, depletion, amortization and impairment


(751,926
)

(526,939
)Total property and equipment, net


1,561,819


1,195,832Derivative Assets


113,815


Deferred Financing Costs and Other Noncurrent Assets


6,055


2,428Total

$
1,995,063

$
1,329,687Liabilities and Stockholders' Equity:Current Liabilities:Accounts payable and accrued liabilities

$
100,552

$
84,773Amounts payable to oil and gas property owners


17,067


22,209Production taxes payable


36,236


24,819Derivative liability and other current liabilities


511


2,414Deferred income taxes


71,428


5,353Total current liabilities


225,794


139,568Note Payable to Bank


254,000


274,000Convertible Senior Notes


172,500


Asset Retirement Obligations


46,687


35,003Liabilities Associated with Assets Held for Sale





45Deferred Income Taxes


207,397


99,149Derivatives and Other Noncurrent Liabilities


887


8,411Stockholders' Equity:Common stock, $0.001 par value; authorized 150,000,000 shares; 45,128,431 and 44,760,955 shares issued and outstanding at December 31, 2008 and 2007,
respectively, with 590,098 and 564,100 shares subject to restrictions, respectively


45


44Additional paid-in capital


761,829


742,492Retained earnings


133,852


26,205Treasury stock, at cost: zero shares at December 31, 2008 and December 31, 2007





Accumulated other comprehensive income


192,072


4,770Total stockholders' equity


1,087,798


773,511Total

$
1,995,063

$
1,329,687


See notes to consolidated financial statements.

F-3

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Table of Contents



BILL BARRETT CORPORATION        CONSOLIDATED STATEMENTS OF OPERATIONS

Year Ended December 31,2008

2007

2006(in thousands, except share and per share amounts)Operating and Other Revenues:Oil and gas production

$
605,881

$
374,956

$
344,127Commodity derivative gain


7,920





Other


4,110


15,314


31,202Total operating and other revenues


617,911


390,270


375,329Operating Expenses:Lease operating expense


44,318


41,643


29,768Gathering and transportation expense


39,342


23,163


15,721Production tax expense


44,410


22,744


25,886Exploration expense


8,139


8,755


9,390Impairment, dry hole costs and abandonment expense


32,065


25,322


12,824Depreciation, depletion and amortization


206,316


172,054


138,549General and administrative expense


57,206


42,228


34,243Total operating expenses


431,796


335,909


266,381Operating income


186,115


54,361


108,948Other Income and Expense:Interest and other income


2,036


2,391


2,527Interest expense


(15,834
)

(12,754
)

(10,339
)Total other income and expense


(13,798
)

(10,363
)

(7,812
)Income before Income Taxes


172,317


43,998


101,136Provision for Income Taxes


64,670


17,244


39,125Net Income

$
107,647

$
26,754

$
62,011Net Income Per Common Share, Basic

$
2.42

$
0.61

$
1.42Net Income Per Common Share, Diluted

$
2.39

$
0.60

$
1.40Weighted Average Common Shares Outstanding, Basic


44,432,383


44,049,662


43,694,781Weighted Average Common Shares Outstanding, Diluted


45,036,545


44,677,467


44,269,445


See
notes to consolidated financial statements.

F-4

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Table of Contents



BILL BARRETT CORPORATION        CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME        For the years ended December 31, 2006, 2007, and
2008

Convertible
Preferred
Stock

Common
Stock

Additional
Paid-In
Capital

(Accumulated
Deficit)
Retained
Earnings

Treasury
Stock

Accumulated
Other
Comprehensive
Income (Loss)

Total
Stockholders'
Equity

Compre-
hensive
Income(in thousands)BalanceDecember 31, 2005

$


$
44

$
721,145

$
(62,515
)
$
(5,180
)
$
(22,711
)
$
630,783Exercise of options








9,644





(5,059
)




4,585

$
Tax benefit from option exercises








6,944











6,944


Stock-based compensation








(10,239
)




10,239








Other








(8
)










(8
)

Comprehensive income:Net income











62,011








62,011


62,011Effect of derivative financial instruments, net of $30,775 of taxes

















52,082


52,082


52,082Total comprehensive income






















$
114,093BalanceDecember 31, 2006

$


$
44

$
727,486

$
(504
)
$


$
29,371

$
756,397Cumulative effect of adoption of Financial Accounting Standards Board Interpretation No. (FIN) 48











(45
)







(45
)
$
Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding








7,602





(3,319
)




4,283


Stock-based compensation








10,723











10,723


Retirement of treasury stock








(3,319
)




3,319








Comprehensive income:Net income











26,754








26,754


26,754Effect of derivative financial instruments, net of $14,604 of taxes

















(24,601
)

(24,601
)

(24,601
)Total comprehensive income






















$
2,153BalanceDecember 31, 2007

$


$
44

$
742,492

$
26,205

$


$
4,770

$
773,511Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding





1


4,615





(3,051
)




1,565

$
Stock-based compensation








17,773











17,773


Retirement of treasury stock








(3,051
)




3,051








Comprehensive income:Net income











107,647








107,647


107,647Effect of derivative financial instruments, net of $110,505 of taxes

















187,302


187,302


187,302Total comprehensive income






















$
294,949BalanceDecember 31, 2008

$


$
45

$
761,829

$
133,852

$


$
192,072

$
1,087,798


See notes to consolidated financial statements.

F-5

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Table of Contents



BILL BARRETT CORPORATION        CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31,2008

2007

2006(in thousands)Operating Activities:Net Income

$
107,647

$
26,754

$
62,011Adjustments to reconcile to net cash provided by operations:Depreciation, depletion and amortization


206,316


172,054


138,549Deferred income taxes


64,060


17,270


38,631Impairments, dry hole costs and abandonment expense


32,065


25,322


12,824Unrealized derivative gain


(7,858
)




Stock compensation and other non-cash charges


18,117


11,284


7,089Amortization of deferred financing costs


1,736


482


556Gain on sale of properties


(1,132
)

(13,420
)

(21,335
)Change in operating assets and liabilities:Accounts receivable


(16,047
)

5,900


(320
)Prepayments and other assets


(324
)

(875
)

4,335Accounts payable, accrued and other liabilities


(7,908
)

(4,065
)

3,904Amounts payable to oil and gas property owners


(5,142
)

8,276


(5,764
)Production taxes payable


11,417


2,471


(3,582
)Net cash provided by operating activities


402,947


251,453


236,898Investing Activities:Additions to oil and gas properties, including acquisitions


(568,445
)

(414,925
)

(438,476
)Additions of furniture, equipment and other


(4,752
)

(4,640
)

(3,177
)Proceeds from sale of properties


2,405


96,450


78,339Net cash used in investing activities


(570,792
)

(323,115
)

(363,314
)Financing Activities:Proceeds from debt


319,800


164,000


151,000Principal payments on debt


(167,300
)

(78,000
)

(55,495
)Proceeds from sale of common stock


4,082


5,098


4,929Deferred financing costs and other


(5,959
)

(473
)

(978
)Net cash provided by financing activities


150,623


90,625


99,456(Decrease) Increase in Cash and Cash Equivalents


(17,222
)

18,963


(26,960
)Beginning Cash and Cash Equivalents


60,285


41,322


68,282Ending Cash and Cash Equivalents

$
43,063

$
60,285

$
41,322


See
notes to consolidated financial statements.

F-6

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Table of Contents



BILL BARRETT CORPORATION        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        For the years ended December 31, 2008, 2007 and 2006

1. Organization

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

2. Summary of Significant Accounting Policies

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

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

The
most significant areas requiring the use of assumptions, judgments and estimates relate to volumes of natural gas and oil reserves used in calculating depletion, the amount of
expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates
also are required in determining future abandonment obligations, impairments of undeveloped properties, income taxes and estimating fair values of derivative instruments.

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

Oil and Gas Properties.The Company's oil and gas exploration and production activities are accounted for using the successful
efforts method. Under
this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an
exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash
Flows pursuant to Statement of Financial Accounting Standards ("SFAS") No. 19,Financial Accounting and Reporting by Oil and Gas Producing
Companies. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized. Interest cost is
capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. The weighted average
interest rates used to capitalize interest for the years ended December 31, 2008 and 2007 were 5.9% and 7.1%, respectively, which include interest on both the Company's 5% Convertible Senior
Notes due 2028 ("Convertible Notes") and its credit facility, commitment fees paid on the unused portion of its credit facility, amortization of deferred financing

F-7

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

2. Summary of Significant Accounting Policies (Continued)

and
debt issuance costs and the effects of interest rate hedges. The Company capitalized interest costs of $2.0 million and $1.6 million for the years ended December 31, 2008 and
2007, respectively.

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

Unevaluated
oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. Proceeds from sales of partial
interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unevaluated oil and gas properties are assessed periodically for
impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage.
During the year ended December 31, 2008, the Company recognized a non-cash impairment charge of $4.3 million primarily on the carrying value of unevaluated oil and gas
properties in the Talon field located in the Wind River Basin.

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

The
following table sets forth the net capitalized costs and associated accumulated depreciation, depletion and amortization, and non-cash impairments relating to the
Company's natural gas and oil producing activities, including net capitalized costs associated with properties that were held for sale at December 31, 2007 of $0.3 million in total
proved properties and $2.0 million in total unevaluated properties, both of which were net of $2.2 million of accumulated depreciation, depletion, amortization

F-8

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

2. Summary of Significant Accounting Policies (Continued)

and
non-cash impairment (see Note 4 for further information on properties held for sale). There were no properties held for sale as of December 31, 2008.

As of December 31,2008

2007(in thousands)Proved properties

$
415,641

$
369,976Wells and related equipment and facilities


1,381,861


974,005Support equipment and facilities


170,058


123,020Materials and supplies


9,975


6,132Total proved oil and gas properties


1,977,535


1,473,133Accumulated depreciation, depletion, amortization and impairment


(744,139
)

(521,691
)Total proved oil and gas properties, net

$
1,233,396

$
951,442Unevaluated properties

$
105,665

$
106,996Wells and equipment in progress


209,574


126,529Total unevaluated oil and gas properties, excluded from amortization

$
315,239

$
233,525


Net
changes in capitalized exploratory well costs for the years ended December 31, 2008, 2007 and 2006 are reflected in the following table:

Year Ended December 31,2008

2007

2006(in thousands)Beginning of period

$
82,214

$
69,596

$
61,530Additions to capitalized exploratory well costs pending the determination of proved reserves


332,270


227,290


211,290Reclassifications to wells, facilities and equipment based on the determination of proved reserves


(288,512
)

(193,618
)

(192,337
)Exploratory well costs charged to dry hole costs and abandonment expense(1)


(5,881
)

(21,054
)

(10,887
)End of period

$
120,091

$
82,214

$
69,596


---

F-9

---



Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

2. Summary of Significant Accounting Policies (Continued)

The
following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of gross wells for which exploratory well costs
have been capitalized for a period greater than one year since the completion of drilling:

Year Ended December 31,2008

2007

2006(in thousands)Capitalized exploratory well costs that have been capitalized for a period of one year or less

$
80,954

$
69,793

$
48,417Capitalized exploratory well costs that have been capitalized for a period greater than one year


39,137


12,421


21,179End of period balance

$
120,091

$
82,214

$
69,596Number of exploratory wells that have costs capitalized for a period greater than one year


163


75


173


As
of December 31, 2008, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling were $39.1 million, of which
$24.2 million was related to exploratory wells located in the Powder River Basin. In this basin, the Company drills wells into various coal seams. In order to produce gas from the coal seams, a
period of dewatering lasting up to 24 months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering and
to classify the reserves as proved.

In
addition to its wells in the Powder River Basin, the Company has six wells for a total of $14.9 million that have been capitalized for greater than one year located in the
Montana Overthrust area and in the Paradox, Big Horn and Uinta Basins. The two wells located in the Montana Overthrust area are under economic evaluation for possible development as we are assessing
and conducting appraisal operations to determine whether economic reserves can be attributed to this area. In the Paradox Basin, the Company has one well that will be re-entered and
converted to a horizontal well, and completion work is planned for the second well during the second quarter of 2009. The well located in the Big Horn Basin is pending upgrades of production gathering
and processing facilities. The well located in the Uinta Basin is pending the development of a gas gathering infrastructure.

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

F-10

---



Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

2. Summary of Significant Accounting Policies (Continued)

During
the years ended December 31, 2008, 2007 and 2006, the Company recognized non-cash impairment charges of $25.3 million, $2.3 million and
$1.2 million, respectively, included within impairment, dry hole costs and abandonment expense. During the year ended December 31, 2008, the Company's impairment testing required it to
take a $21.0 million non-cash impairment charge on proved oil and gas properties in the Cooper Reservoir field, located in the Wind River Basin, primarily as the result of geologic
and engineering reevaluations, as well as lower oil and gas prices at December 31, 2008. During the year ended December 31, 2007, the Company recognized a $2.3 million
non-cash impairment charge based on its fair value analysis of the Tri-State exploration project in the DJ Basin. These properties were subsequently sold in early 2008 for an
immaterial gain. The non-cash impairment expense during 2006 was a $1.2 million non-cash impairment charge to the Company's Cedar Camp and Tumbleweed properties within
the Uinta Basin, which were subsequently sold during the fourth quarter of 2006.

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. Estimated future dismantlement, restoration and abandonment
costs, which are net of estimated salvage values, are taken into consideration.

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

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

As of December 31,2008

2007(in thousands)Accrued drilling and facility costs

$
79,823

$
58,005Accrued lease operating and gathering and transportation expenses


10,485


6,036Accrued general and administrative expenses


9,744


7,358Trade payables and other


500


13,374Total accounts payable and accrued liabilities

$
100,552

$
84,773


Environmental Liabilities.Environmental expenditures that relate to an existing condition caused by past operations and that do
not contribute to
current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of
December 31, 2008 and 2007, the Company has not accrued for nor been fined or cited for any environmental violations that would have a material adverse effect upon capital expenditures,
operating results or the competitive position of the Company.

F-11

---



Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

2. Summary of Significant Accounting Policies (Continued)

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

The
Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records
revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners' gas
sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company's remaining over- and under-produced gas balancing positions
are considered in the Company's proved oil and gas reserves. Gas imbalances at December 31, 2008 and 2007 were not material.

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

Derivative Instruments and Hedging Activities.The Company periodically uses derivative financial instruments to achieve a more
predictable cash flow
from its gas and oil production by reducing its exposure to price fluctuations. The Company also enters into derivative contracts to mitigate the risk of interest rate fluctuations.

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

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

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

The
Company utilizes derivative financial instruments which have not been designated as cash flow hedges under SFAS No. 133 because they still protect the Company from changes in
commodity prices

F-12

---



Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

2. Summary of Significant Accounting Policies (Continued)

or
interest rate fluctuations. These instruments are marked to market with the resulting changes in fair value recorded in earnings. For additional discussion of derivatives, please see Note 8.

Deferred Financing Costs.Costs incurred in connection with the execution or modification of the Company's credit facility and
Convertible Notes are
capitalized and amortized over the life, or expected life, of the debt using the straight-line method, which approximates the effective interest method.

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

On
January 1, 2007, the Company adopted Financial Accounting Standards Board ("FASB") Interpretation No. 48 ("FIN No. 48"),Accounting for
Uncertainty in Income Taxesan interpretation of FASB Statement No. 109("SFAS No. 109"), which clarifies the accounting for uncertainty in income
taxes recognized in an enterprise's financial statements in accordance with SFAS No. 109. FIN No. 48 also prescribes a recognition threshold and measurement standard for the financial
statement recognition and measurement of an income tax position taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not
recognition threshold at the effective date may be recognized or continue to be recognized upon adoption. In addition, FIN No. 48 provides guidance on derecognition, classification, interest
and penalties, accounting in interim periods, disclosure and transition.

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

Repurchases and Retirements of Capital Stock.The Company records treasury stock acquisitions at cost. Upon retirement of
treasury shares, the excess
of purchase or contribution cost over associated common stock par value is allocated to additional paid-in capital. The allocation to additional paid-in capital is based on the
per-share amount of capital in excess of par value for all shares.

Stock-Based Compensation.The Company accounts for stock-based compensation in accordance with SFAS No. 123 (revised 2004), Share-Based Payment("SFAS No. 123R"), which revised SFAS

F-13

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

2. Summary of Significant Accounting Policies (Continued)

No. 123, Accounting for Stock-Based Compensation, and superseded Accounting Principles Board ("APB") Opinion No. 25, Accounting for Stock Issued to
Employees. SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges
its equity instruments for goods and services, focusing primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R
also addresses transactions in which an entity incurs liabilities in exchange for goods and services that are based on the fair value of the entity's equity instruments or that may be settled by the
issuance of those equity instruments.

For
awards granted before the Company became a public company (i.e. those granted prior to April 16, 2004, which is defined by SFAS No. 123R as the date the Company
became a public company as a result of the filing of the Company's Form S-1 registration statement with the Securities and Exchange Commission ("SEC")), the Company continues to use
the minimum value method described under APB Opinion No. 25. For awards granted subsequent to April 16, 2004 and for new, modified, repurchased or cancelled awards on or subsequent to
the Company's adoption of SFAS No. 123R on October 1, 2004, the Company recognizes share-based employee compensation cost based on the fair value as computed under SFAS No. 123R.
The Company continues to account for certain stock options under the original provisions of APB Opinion No. 25 because those options were issued prior to April 16, 2004, when the Company
was considered a nonpublic entity as defined by SFAS No. 123R.

Earnings Per Share.Basic net income per share of common stock is calculated by dividing net income attributable to common stock
by the weighted
average of common shares outstanding during each period. Diluted net income attributable to common stockholders is calculated by dividing net income attributable to common stockholders by the weighted
average of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations consist of nonvested equity shares of common stock,
in-the-money outstanding stock options to purchase the Company's common stock and shares into which the Convertible Notes are convertible.

In
satisfaction of its obligation upon conversion of the Convertible Notes, the Company may elect to deliver, at its option, cash, shares of its common stock or a combination of cash and
shares of its common stock. The Company currently intends to settle the Convertible Notes in cash at or near the initial redemption date of March 26, 2012; therefore, the treasury stock method
was used to measure the potentially dilutive impact of shares associated with that conversion feature. The Convertible Notes issued March 12, 2008 have not been dilutive since their issuance,
and therefore, do not impact the diluted earnings per share calculation for the year ended December 31, 2008.

F-14

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

2. Summary of Significant Accounting Policies (Continued)

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

Year Ended December 31,2008

2007

2006(in thousands, except per share amounts)Net income

$
107,647

$
26,754

$
62,011Basic weighted-average common shares outstanding in period


44,432.4


44,049.7


43,694.8Add dilutive effects of stock options and nonvested equity shares of common stock


604.1


627.8


574.6Diluted weighted-average common shares outstanding in period


45,036.5


44,677.5


44,269.4Basic income per common share

$
2.42

$
0.61

$
1.42Diluted income per common share

$
2.39

$
0.60

$
1.40


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

New Accounting Pronouncements.In September 2006, the FASB issued SFAS No. 157,Fair Value
Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement. The
Company partially adopted SFAS No. 157 as of January 1, 2008, pursuant to FASB Staff Position ("FSP") No. FAS 157-2,Effective Date of FASB
Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial
liabilities until fiscal years beginning after November 15, 2008. With partial adoption, the Company applied SFAS No. 157 to recurring fair value measurements of financial and
non-financial instruments, which affected the fair value disclosures of the Company's financial derivatives within the scope of SFAS No. 133. See Note 7 for fair value
disclosures.

As
of January 1, 2009, the Company fully adopted SFAS No. 157, requiring fair value measurements of nonfinancial assets and nonfinancial liabilities, including nonfinancial
long-lived assets measured at fair value for an impairment assessment under SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived
Assets, and asset retirement obligations initially measured at fair value under SFAS No. 143,Accounting for Asset Retirement
Obligations. The full adoption of SFAS No. 157 is not expected to have a material impact on the Company's financial statements.

In
February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities,which permits
entities to choose to measure many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair
value option. The Company adopted this statement as of January 1, 2008; however, the Company did not elect the fair value option for any eligible financial instruments or other items.
Therefore, the adoption of this statement did not impact the Company's financial statements.

F-15

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

2. Summary of Significant Accounting Policies (Continued)

In
December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations("SFAS No. 141R"), which replaces FASB
Statement No. 141,Business Combinations. This statement requires an acquirer to recognize the assets acquired, the liabilities assumed and any
noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified in the statement. This includes the measurement of the
acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for pre-acquisition gain and loss contingencies, the
recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs
and the recognition of changes in the acquirer's income tax valuation allowance and deferred taxes. This statement applies prospectively and was effective for the Company beginning January 1,
2009. SFAS No. 141R will only impact the Company if and when the Company becomes party to a business combination.

In
March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities. This statement is
intended to improve financial reporting about derivative instruments and hedging activities by requiring companies to enhance disclosure about how these instruments and activities affect their
financial position, performance and cash flows. SFAS No. 161 seeks to achieve these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses
in a tabular format. It also seeks to improve the transparency of the location and amounts of derivative instruments in a company's financial statements and how they are accounted for under SFAS
No. 133. This statement was effective for the Company beginning January 1, 2009. The adoption of SFAS No. 161 is not expected to have a material impact on the Company's financial
statements.

In
May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles. This statement is intended to
improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with
GAAP for nongovernmental entities. Prior to the issuance of SFAS No. 162, GAAP hierarchy was defined in the American Institute of Certified Public Accountants ("AICPA") Statement on Auditing
Standards ("SAS") No. 69,The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. SFAS No. 162 was
adopted by the Company effective November 15, 2008. The adoption of SFAS No. 162 did not have a material impact on the Company's financial statements.

In
May 2008, the FASB adopted FSP APB 14-1,Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (including
Partial Cash Settlement). FSP APB 14-1 states that the accounting treatment for certain convertible debt instruments that may be settled in cash, shares of
common stock or any portion thereof at the election of the issuing company be accounted for utilizing a bifurcation model under which the value of the debt instrument would be determined without
regard to the conversion feature. The difference between the issuance amount of the debt instrument and the value determined pursuant to FSP APB 14-1 will be recorded as an equity
contribution. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. FSP
APB 14-1 was effective for financial statements issued for fiscal years beginning after December 15, 2008. The Company adopted FSP APB 14-1 effective
January 1, 2009 as early adoption was not permitted. FSP APB 14-1 must be applied retrospectively to

F-16

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

2. Summary of Significant Accounting Policies (Continued)

all
periods presented for any instrument within the scope of FSP APB 14-1 that was outstanding during any of the periods presented. FSP APB 14-1 changes the
accounting treatment for the Company's Convertible Notes which were issued in March 2008. At adoption, FSP APB 14-1 will retrospectively reduce the Company's long-term
debt and increase the Company's stockholders' equity by approximately $23 million and increase the Company's non-cash interest expense by approximately $4 million and
$6 million for the years ended December 31, 2008 and 2009, respectively.

In
October 2008, the FASB issued FSP No. FAS 157-3,Determining the Fair Value of a Financial Asset When the Market for That Asset is Not
Active. FSP No. FAS 157-3 clarifies the application of SFAS No. 157 as it relates to the valuation of financial assets in a market that is not active
for those financial assets. This FSP was effective immediately and includes those periods for which financial statements have not been issued. The Company currently does not have any financial assets
that are valued using inactive markets, and as a result, the Company was not impacted by the issuance of FSP No. FAS 157-3.

On
December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reserves reporting requirements. Many of the revisions are updates to
definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which is a widely accepted set of evaluation guidelines that are designed to
support assessment processes throughout the
resource asset lifecycle. These guidelines were prepared by the Society of Petroleum Engineers ("SPE") Oil and Gas Reserves Committee with cooperation from many industry organizations. One of the key
changes to the previous SEC rules relates to using a 12-month average commodity price to calculate the value of proved reserves versus the current method of using year-end
prices. Other key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, the opportunity to establish proved undeveloped
reserves without the requirement of an adjacent producing well and permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure
requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. The
Company is currently assessing the impact that the adoption will have on the Company's disclosures and financial statements.

F-17

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

3. Supplemental Disclosures of Cash Flow Information:

Supplemental cash flow information is as follows:

Year Ended December 31,2008

2007

2006(in thousands)Cash paid for interest, net of amount capitalized

$
12,057

$
11,260

$
9,625Cash paid for income taxes, net of refunds received


1,068


22


500Supplemental disclosures of non-cash investing and financing activities:Exchange of oil and gas properties for equipment and other properties








9,304Assumption of debt and deferred tax liabilityPowder River Basin properties acquisition purchase price allocation








43,298Reduction of deferred tax liabilityPowder River Basin properties acquisition purchase price allocation





1,635


Current liabilities that are reflected in investing activities


85,145


65,340


6,818Current liabilities that are reflected in financing activities


34





Net change in asset retirement obligations


(9,491
)

(340
)

6,612Treasury stock acquired for employee stock option exercises and collection of employee payroll taxes on vesting of restricted stock


3,051


3,319


5,059Retirement of treasury stock


3,051


3,319


10,239


4. Acquisitions, Disposition, and Property Held for Sale



On May 8, 2006, the Company acquired 100% of the outstanding stock of CH4 Corporation ("CH4") for $74.2 million in cash
and agreed to pay $6.5 million of indebtedness of CH4. The acquisition was funded with borrowings under the Company's credit facility. The primary assets of CH4 consisted of approximately
84,300 gross (52,000 net) acres of oil and gas leasehold interests in coal bed methane properties in the Powder River Basin of Wyoming and an estimated 11.0 Bcfe of proved reserves.

The
CH4 acquisition was recorded using the purchase method of accounting, and the results of operations from the CH4 properties acquired are included with the results of the Company from
the May 6, 2006 date of closing. The total purchase price of the transaction was allocated to the assets acquired and the liabilities assumed based on fair values at the acquisition date. The
Company finalized the purchase price allocation during the quarter ended June 30, 2007 when all amounts related to

F-18

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

4. Acquisitions, Disposition, and Property Held for Sale (Continued)

receivables
and payables were determined with certainty. The table below summarizes the final allocation (in thousands):

Purchase Price:Cash paid, net of cash received

$
72,547Debt assumed


6,495Total

$
79,042Allocation of Purchase Price:Working capital

$
(327
)Proved oil and gas properties


40,164Unevaluated oil and gas properties


74,888Other non-current assets


122Deferred income taxes


(35,168
)Asset retirement obligation


(637
)Total

$
79,042


Pro
forma financial information is not provided because the CH4 acquisition was not considered a material business combination to the Company, and the results of operations from those
properties are insignificant.



During 2006, the Company completed the sale of approximately 17,000 net acres of certain coalbed methane properties that were acquired
with the CH4 acquisition. Proceeds from the sale were $30.7 million and a loss of $0.1 million was recorded due to various purchase price adjustments incurred in the normal course of
business. The Company also completed the sale of the Cedar Camp and Tumbleweed properties within the Uinta Basin. Total proceeds from the sale were $3.8 million, which resulted in a gain of
$0.1 million.

In
addition, the Company entered into joint exploration agreements and completed other property sales in the Powder River, Paradox, Williston, Wind River, Big Horn, Montana Overthrust,
DJ and Uinta Basins resulting in gains recognized of $30.5 million for the year ended December 31, 2006.

During
2007, the Company completed the sale of its oil and gas properties in the Williston Basin. The Company received approximately $81.4 million in cash proceeds and recognized
a $10.0 million pre-tax gain after various purchase price adjustments incurred in the normal course of business. Through the closing date of the sale on June 22, 2007, total
production volumes associated with the Williston Basin properties of 1.2 Bcfe were included in the Company's financial statements. In addition, the Company completed the sale of a portion of its
unevaluated properties in the DJ Basin. The Company received approximately $0.5 million in cash proceeds and recognized a $0.2 million pre-tax gain.

The
Company also entered into joint exploration agreements and completed other property sales in the Powder River, Paradox, Big Horn and Wind River Basins resulting in gains recognized
of $3.1 million for the year ended December 31, 2007.

F-19

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

4. Acquisitions, Disposition, and Property Held for Sale (Continued)

During 2008, the Company completed the sale of all of its remaining properties in the DJ Basin. The Company received approximately $1.4 million in cash proceeds and recognized a
$0.3 million pre-tax gain.

Under
EITF 03-13,Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued
Operations, the Company determined that all of these sales did not qualify for discontinued operations reporting. All gains and losses recognized from property sales and joint
exploration agreements are included in other operating revenues in the Consolidated Statements of Operations.



Assets are classified as held for sale when the Company commits to a plan to sell the assets and completion of the sale is probable and
expected to occur within one year. Upon classification as held-for-sale, long-lived assets are no longer depreciated or depleted and a loss is recognized, if any,
based upon the excess of carrying value over fair value less costs to sell. Previous losses may be reversed up to the original carrying value as estimates are revised; however, gains are recognized
only upon disposition.

At
December 31, 2007, the Company had properties held for sale in its Tri-State exploration project in the DJ Basin and its Hingeline Prospect in the Uinta Basin. In
accordance with SFAS No. 144 these properties were carried at the lower of historical cost or fair value, less cost to sell, and were reclassified to oil and gas properties held for sale on the
Consolidated Balance Sheets. Any liabilities related to those properties were also reclassified to liabilities associated with assets held for sale on the Consolidated Balance Sheets. Under
EITF 03-13, the Company determined that these sales did not qualify for discontinued operations reporting.

During
the year ended December 31, 2008, all remaining properties held for sale in the DJ Basin were sold for an immaterial gain. However, given the current market conditions, the
Company was unable to sell its unevaluated oil and gas properties in the Hingeline Prospect. Accordingly, the properties that were previously classified as held for sale were reclassified into
unevaluated oil and gas properties on the Consolidated Balance Sheets. Based upon its analysis, the Company believes that the carrying value of $1.1 million remains less than the estimated fair
value and no impairment was determined necessary.

5. Long-Term Debt



On October 20, 2008, the Company amended its credit facility (the "Amended Credit Facility"). The Amended Credit Facility, which
matures on March 17, 2011, has commitments of $592.8 million and, based on mid-year 2008 reserves and hedge positions, a borrowing base of $600.0 million (after a
reduction related to the Company's Convertible Notes outstanding). Future borrowing bases will be computed based on proved natural gas and oil reserves, hedge positions and estimated future cash flows
from those reserves, as well as any other outstanding debt of the Company. The borrowing base is required to be redetermined at least twice per year. The Amended Credit Facility bears interest, based
on the borrowing base usage, at the applicable London Interbank Offered Rate ("LIBOR") plus

F-20

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

5. Long-Term Debt (Continued)

applicable
margins ranging from 1.25% to 2.00% or an alternate base rate, based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus
1.00%, plus applicable margins ranging from 0.25% to 1.00%. The average annual interest rates incurred on the Amended Credit Facility were 5.5% and 6.3% for the years ended December 31, 2008
and 2007, respectively. The Company pays annual commitment fees ranging from 0.35% to 0.50% of the unused borrowing base. The Amended Credit Facility is secured by natural gas and oil properties
representing at least 80% of the value of the Company's proved reserves and the pledge of all of the stock of the Company's subsidiaries. The Amended Credit Facility also contains certain financial
covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants for all prior periods.

As
of December 31, 2008, borrowings outstanding under the Amended Credit Facility totaled $254.0 million.



On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. The Convertible
Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by the Company. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all
of the Company's existing and future senior indebtedness; senior in right of payment to all of the Company's future subordinated indebtedness; and effectively subordinated to all of the Company's
secured indebtedness, with respect to the collateral securing such indebtedness. The Convertible Notes will be structurally subordinated to all present and future secured and unsecured debt and other
obligations of the Company's subsidiaries that do not guarantee the Convertible Notes. As of December 31, 2008, the Convertible Notes are not guaranteed by any of the Company's subsidiaries.

The
conversion price is approximately $66.33 per share of the Company's common stock, equal to the applicable conversion rate of 15.0761 shares of common stock, subject to adjustment,
for each $1,000 face amount of Convertible Note. Upon conversion of the Convertible Notes, holders will receive, at the Company's election, cash, shares of common stock or a combination of cash and
shares of common stock. If the conversion value exceeds $1,000, the Company will also deliver, at its election, cash, shares of common stock or a combination of cash and shares of common stock with
respect to the remaining value deliverable upon conversion. Currently, it is the Company's intention to net cash settle the Convertible Notes. However, the Company has not made a formal legal
irrevocable election to net cash settle and reserves the right to settle the Convertible Notes in any manner allowed under the indenture for the Convertible Notes as business conditions warrant.

The
Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year, beginning
September 15, 2008.

On
or after March 26, 2012, the Company may redeem for cash all or a portion of the Convertible Notes at a redemption price equal to 100% of the principal amount of the
Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, up to, but excluding, the applicable redemption date.

F-21

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

5. Long-Term Debt (Continued)

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

Holders
may convert their Convertible Notes into cash, shares of the Company's common stock or a combination of cash and shares of common stock, as elected by the Company, at any time
prior to the close of business on September 20, 2027, if any of the following conditions are satisfied: (1) if the closing price of the Company's common stock reaches specified
thresholds or the trading price of the Convertible Notes falls below specified thresholds; (2) if the Convertible Notes have been called for redemption; (3) if the Company makes certain
significant distributions to holders of the Company's common stock; or (4) the Company enters into specified corporate transactions, none of which occurred during 2008. After
September 20, 2027, holders may surrender their Convertible Notes for conversion at any time prior to the close of business on the business day immediately preceding the maturity date
regardless of whether any of the foregoing conditions have been satisfied.

In
addition, following certain corporate transactions that constitute a qualifying fundamental change, the Company is required to increase the applicable conversion rate for a holder who
elects to convert its Convertible Notes.

There
is no active, public market for the Convertible Notes. Therefore, based on market-based parameters of the various components of the Convertible Notes, the aggregate estimated fair
value of the Convertible Notes was approximately $120.4 million as of December 31, 2008.

6. Asset Retirement Obligations

The Company accounts for its asset retirement obligations in accordance with SFAS No. 143,Accounting for Asset Retirement
Obligations. This statement generally applies to legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset.

F-22

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

6. Asset Retirement Obligations (Continued)

A
reconciliation of the Company's asset retirement obligations for the years ended December 31, 2008, 2007 and 2006, which includes $0.05 million associated with assets
that were held for sale in 2007, are as follows (in thousands):

Year Ended December 31,2008

2007

2006(in thousands)Beginning of period

$
35,849

$
32,598

$
23,733Liabilities incurred


2,654


3,829


3,433Liabilities settled


(1,392
)

(3,599
)

(1,586
)Accretion expense


3,162


2,999


2,593Revisions to estimate


6,920


22


4,425End of period

$
47,193

$
35,849

$
32,598Less: current asset retirement obligations


506


801


Long-term asset retirement obligations

$
46,687

$
35,048

$
32,598


7. Fair Value Measurements

The Company's financial instruments, including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the
short-term maturity of these instruments. The recorded value of the Amended Credit Facility, as discussed in Note 5, approximates its fair value due to its floating rate structure.
The Convertible Notes are recorded at cost, and the estimated fair value is disclosed in Note 5.

Effective
January 1, 2008, the Company partially adopted SFAS No. 157 pursuant to FSP No. FAS 157-2, which delayed the effective date of SFAS
No. 157 for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008. As of January 1,
2009, SFAS No. 157 was fully effective for the Company. Therefore, the Company applied SFAS No. 157 to recurring fair value measurements of its financial derivatives as of
January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement.

As
defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants
at the measurement date (exit price). The Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) for valuation as a practical
expedient for assigning fair value. The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can
be readily observable, market corroborated or generally unobservable. The Company primarily applies the market and income approaches for recurring fair value measurements and utilizes the best
available information. Given the Company's historical market transactions, its markets and instruments are fairly liquid. Therefore, the Company has been able to classify fair value balances based on
the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest

F-23

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

7. Fair Value Measurements (Continued)

priority
to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements).



The
following table sets forth by level within the fair value hierarchy the Company's financial assets and financial liabilities that were accounted for at fair value on a recurring
basis as of December 31, 2008. As required by SFAS No. 157, financial assets and financial liabilities are classified in their
entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires
judgment and may affect the valuation of assets and liabilities and their placement within the fair value hierarchy levels.

Level 1

Level 2

Level 3

Total(in thousands)AssetsCommodity Derivatives

$


$
313,775

$


$
313,775LiabilitiesInterest Rate Derivatives





(509
)




(509
)


As
required under SFAS No. 157, all fair values reflected in the table above and on the Consolidated Balance Sheets have been adjusted for non-performance risk. For
applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. SFAS No. 157 also states
that the fair value measurement of a

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

7. Fair Value Measurements (Continued)

liability
must reflect the nonperformance risk of the Company. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.



8. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable, economic cash flow from its natural gas and oil production
by reducing its exposure to price fluctuations. The Company has entered into financial commodity swap and collar contracts to fix the floor and ceiling prices received for a portion of the Company's
natural gas and oil production. The Company does not enter into derivative instruments for speculative or trading purposes. The Company's natural gas and oil derivative financial instruments are
accounted for in accordance with SFAS No. 133. As of December 31, 2008, the Company had hedges in place for a portion of its anticipated production through 2011 for a total of 447,125
Bbls of crude oil and 121,691,000 MMBtu of natural gas.

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

The
Company also has two interest rate derivative contracts to manage the Company's exposure to changes in interest rates. The first contract is a
floating-to-fixed interest rate swap for a notional amount of $10.0 million, and the second is a floating-to-fixed interest rate collar for a
notional amount

F-25

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

8. Derivative Instruments (Continued)

of
$10.0 million, both to terminate on December 12, 2009. The Company's interest rate derivative instruments have been designated as cash flow hedges in accordance with SFAS
No. 133. Under the swap, the Company will make payments to, or receive payments from, the contract counterparty when the variable rate of one-month LIBOR falls below, or exceeds,
the fixed rate of 4.70%. Under the collar, the Company will make payments to, or receive payments from, the contract counterparty when the variable LIBOR rate falls below the floor rate of 4.50% or
exceeds the ceiling
rate of 4.95%. The payment dates of both the swap and the collar match exactly with the interest payment dates of the corresponding portion of the Company's Amended Credit Facility.

All
derivative instruments, other than those that meet the normal purchase and normal sale exception, as mentioned above, are recorded at fair market value in accordance with SFAS
No. 157 and included in the Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative instruments in the
Consolidated Balance Sheets as of December 31, 2008:

Asset Derivatives

Liability DerivativesBalance Sheet Location

Fair Value

Balance Sheet Location

Fair Value(in thousands)Derivatives Designated as Cash Flow Hedges Under SFAS No. 133CurrentInterest Rate Contracts

N/A

$


Derivative Liability and Other Current Liabilities

$
509Commodity Contracts

Derivative Assets


198,982

N/A


Long TermCommodity Contracts

Derivative Assets


115,016

N/A


Total derivatives designated as hedging instruments under SFAS No. 133



$
313,998



$
509Derivatives Not Designated as Cash Flow Hedges Under SFAS No. 133CurrentCommodity Contracts

Derivative Assets

$
978

Derivative Assets

$
659Long TermCommodity Contracts

Derivative Assets


5,587

Derivative Assets


6,129Total derivates not designated as hedging instruments under SFAS No. 133



$
6,565



$
6,788Total Derivatives



$
320,563



$
7,297


For derivative instruments that qualify and are designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are
recognized in other comprehensive income until the forecasted transaction occurs. The Company will reclassify the appropriate cash flow hedge amounts from other comprehensive income to gains or losses
in the Consolidated Statements of Operations as the hedged production quantity is produced or the interest rate derivative is settled. Based on projected

F-26

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

8. Derivative Instruments (Continued)

market
prices as of December 31, 2008, the amount to be reclassified from other comprehensive income to net income in the next 12 months would be an after-tax net gain of
approximately $121.7 million. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. The Company
anticipates that all originally forecasted transactions related to the Company's derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified
time periods.

The
commodity hedge instruments designated as cash flow hedges are at highly liquid trading locations but may contain slight differences compared to the delivery location of the
forecasted sale, which may result in ineffectiveness in accordance with SFAS No. 133. Although those derivatives may not achieve 100% effectiveness for accounting purposes, the Company believes
that its derivative instruments continue to be highly effective in achieving its risk management objectives. The ineffective portion of commodity hedge derivatives is reported in commodity derivative
gain or loss in the Consolidated Statements of Operations. Ineffectiveness on interest rate derivatives was de minimis for the year ended December 31, 2008. The following table summarizes the
cash flow hedge gains and losses and their locations on the Consolidated Balance Sheets and Consolidated Statements of Operations for the year ended December 31, 2008:

Derivatives in SFAS No. 133
Cash Flow Hedging
Relationships

Amount of
Gain (Loss)
Recognized in
OCI

Location of Gain
Reclassified from
Accumulated OCI into
Income

Amount of
Gain
Reclassified
from
Accumulated
OCI into
Income

Location of Gain on
Ineffective Hedges

Amount of
Gain
Recognized
in Income on
Ineffective
Hedges(in thousands)Interest Rate Contracts

$
(109
)
Interest and Other Income

$
(333
)
N/A


N/ACommodity Contracts


187,411

Oil and Gas Production


31,900

Commodity Derivative Gain


6,803Total

$
187,302



$
31,567



$
6,803


If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time
period, the hedging instrument loses cash flow hedge accounting treatment in accordance with SFAS No. 133. All current mark-to-market gains and losses are recorded in
earnings and all accumulated gains or losses recorded in other comprehensive income related to the hedging instrument are also reclassified to earnings. Due to the Company's limited ability to sell
its natural gas out of the Rocky Mountain region to the Mid-continent region at index prices, and due to an unexpected pipeline curtailment on Rockies Express that restricted the Company's
ability to transport to the Mid-continent, a portion of its Mid-continent gas derivatives no longer qualified for hedge accounting during the year ended December 31,
2008. The Company, therefore, discontinued hedge accounting for certain hedges during the year ended December 31, 2008. While such derivative contracts no longer qualify for hedge accounting,
the Company believes that these contracts remain a valuable component of its commodity price risk management program.

Some
of the Company's commodity derivatives do not qualify for hedge accounting under SFAS No. 133 but are, to a degree, an economic offset to the Company's commodity price
exposure. If a commodity derivative instrument does not qualify as a cash flow hedge or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in
commodity derivative gain or

F-27

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

8. Derivative Instruments (Continued)

loss
in the Consolidated Statements of Operations. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in
market prices. The Company's cash flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument contract is settled by
making or receiving a payment to or from the counterparty. Realized gains and losses of commodity derivative instruments that do not qualify as cash flow hedges are recognized in commodity derivative
gain or loss in the Consolidated Statements of Operations and are reflected in cash flows from operations on the Consolidated Statements of Cash Flows.

During
the year ended December 31, 2008, in addition to the swaps and collars discussed above, the Company entered into basis only swaps. With basis only swaps, the Company has
hedged the difference between the New York Mercantile Exchange ("NYMEX") price and the price received for the Company's natural gas production at a specific delivery location. Although the Company
believes that this represents a sound economic business hedging strategy, the basis only swaps do not qualify for hedge accounting under SFAS No. 133 because the total future cash flow has not
been fixed. As a result, the changes in fair value of these derivative instruments are recorded in earnings and recognized in commodity derivative gain in the Consolidated Statements of Operations. As
of December 31, 2008, the Company had basis only swaps in place for a portion of the Company's anticipated natural gas production in 2009, 2010 and 2011 for a total of 23,600,000 MMbtu.

The
following table summarizes the location and amounts of gains and losses on derivative instruments that do not qualify for hedge accounting under SFAS No. 133 for the year
ended December 31, 2008:

Derivatives Not Designated as Hedging
Instruments under SFAS No. 133

Location of Gain Recognized in
Income on Derivatives

Amount of Gain
Recognized in
Income on
Derivatives(in thousands)Commodity Contracts


Commodity Derivative Gain

$
1,117Total




$
1,117


The
Company was a party to various swap and collar contracts for natural gas based on the Colorado Interstate Gas Rocky Mountains ("CIGRM"), Panhandle Eastern Pipe Line Co.
("PEPL") and Northwest Pipeline Corporation ("NWPL") indices that settled during the year ended December 31, 2008 and based on the CIGRM index that settled during
the year ended December 31, 2007. As a result, the Company recognized an increase of natural gas production revenues related to these contracts of $41.0 million and $87.7 million
in 2008 and 2007, respectively. The Company was also a party to various swap and collar contracts for oil based on a West Texas Intermediate ("WTI") index, recognizing a reduction to oil production
revenues related to these contracts of $9.1 million and $0.8 million in 2008 and 2007, respectively.

F-28

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

8. Derivative Instruments (Continued)

The
table below summarizes the realized and unrealized gains and losses the Company recognized related to its oil and natural gas derivative instruments for the periods indicated:

Year Ended December 31,2008

2007(in thousands)Realized gains on derivatives designated as cash flow hedges(1)

$
31,900

$
86,917Realized gains on derivatives not designated as cash flow hedges

$
62

$
Unrealized ineffectiveness recognized on derivatives designated as cash flow hedges


6,803


Unrealized gains on derivatives not designated as cash flow hedges


1,055


Total commodity derivative gain(2)

$
7,920

$







9. Income Taxes

The expense for income taxes consists of the following:

Year Ended December 31,2008

2007

2006(in thousands)Current:Federal

$
857

$
432

$
460State


(3
)

7


34Deferred:Federal


60,188


15,804


36,353State


3,628


1,001


2,278Total

$
64,670

$
17,244

$
39,125


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

Year Ended December 31,2008

2007

2006(in thousands)Income tax expense at the federal statutory rate

$
60,310

$
15,400

$
35,392State income taxes, net of federal tax effect


3,636


978


2,278Non-deductible permanent items


1,080


344


942Other, net


(356
)

522


513Income tax expense

$
64,670

$
17,244

$
39,125


F-29

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

9. Income Taxes (Continued)

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at December 31, 2008 and 2007 are
presented below:

As of December 31,2008

2007(in thousands)Current:Deferred tax assets (liabilities):Derivative instruments

$
(72,053
)
$
(5,561
)Accrued expenses


352


167Bad debt expense


312


113Prepaid expenses


(329
)

(286
)Other


290


214Total current deferred tax assets (liabilities)

$
(71,428
)
$
(5,353
)Long-term:Deferred tax assets:Net operating loss carryforward

$
22,689

$
21,496Deferred offering costs


322


Long-term derivative instruments





2,730Stock-based compensation


6,030


3,208Deferred rent


329


403Minimum tax credit carryforward


1,617


721Other


165


106Less valuation allowance





Total long-term deferred tax assets


31,152


28,664Deferred tax liabilities:Oil and gas properties


(197,069
)

(127,618
)Long-term derivative instruments


(41,285
)

Other


(195
)

(195
)Total long-term deferred tax liabilities


(238,549
)

(127,813
)Net long-term deferred tax liabilities

$
(207,397
)
$
(99,149
)


At
December 31, 2008, the Company had approximately $68.0 million of federal tax net operating loss carryforwards, which expire through 2027. The Company has a federal
alternative minimum tax ("AMT") credit carryforward of $1.6 million, which has no expiration date.

At
December 31, 2008, the Company's balance sheet reflected a net deferred tax liability of $278.8 million, of which $113.3 million pertains to the tax effects of
derivative instruments reflected in other comprehensive income.

The
Company adopted the provisions of FIN No. 48 on January 1, 2007 and has commenced analyzing filing positions in all of the federal and state jurisdictions where it is
required to file income tax returns, as well as all open tax years in these jurisdictions. As a result of the implementation of FIN

F-30

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

9. Income Taxes (Continued)

No. 48,
the Company recognized a $0.2 million liability for unrecognized tax benefits. There was a cumulative adjustment of $0.05 million to the beginning balance of retained
earnings and a corresponding increase to deferred income tax liabilities of $0.15 million. Subsequent to the implementation of FIN No. 48, the Company has not recorded a change to the
above balance of unrecognized tax benefits. Of the $0.2 million balance of unrecognized tax benefits at December 31, 2008 and 2007, $0.05 million represents the amount of
unrecognized tax benefits that, if recognized, would unfavorably affect the effective income tax rate.

A
rollforward of changes in the Company's unrecognized tax benefits is shown below (in thousands):

Balance at December 31, 2006

$
195Additions based on tax positions related to the current year


Additions for tax positions of prior years


Reductions for tax positions of prior years


Settlements


Balance at December 31, 2007


195Additions based on tax positions related to the current year


Additions for tax positions of prior years


Reductions for tax positions of prior years


Settlements


Balance at December 31, 2008

$
195


The
Company anticipates that no uncertain tax positions will be recognized within the next 12-month period.

The
Company's policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company's income tax provision. As of December 31, 2008, the Company
did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the current year.

The
Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various states. With few exceptions, the Company is subject to U.S. federal tax
examination for years 2005 through 2008 and is subject to state tax examination for years 2004 through 2008.

10. Stockholders' Equity

Common and Preferred Stock.The Company's authorized capital stock consists of 75,000,000 shares of $0.001 per share par value
preferred stock and
150,000,000 shares of $0.001 per share par value common stock. In October 2004, 150,000 shares of $0.001 per share par value preferred stock were designated as Series A Junior Participating
Preferred Stock, none of which are outstanding. At December 31, 2008, the Series A Junior Participating Preferred Stock was the Company's only designated preferred stock, and the
remainder of the authorized preferred stock is undesignated. There are no issued and outstanding shares of preferred stock.

F-31

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

10. Stockholders' Equity (Continued)

Holders
of all classes of stock are entitled to vote on matters submitted to stockholders, except that, when issued, each share of Series A Junior Participating Preferred Stock
will entitle the holder thereof to 1,000 votes on all matters submitted to a vote of the Company's stockholders.

Treasury Stock.The Company may occasionally acquire treasury stock, which is recorded at cost, in connection with the vesting
and exercise of
share-based awards or for other reasons. As of December 31, 2008, all treasury stock held by the Company was retired.

The
following table reflects the activity in the Company's common and treasury stock:

Year Ended December 31,2008

2007

2006Common Stock Outstanding:Shares at beginning of period


44,760,955


44,141,453


43,695,286Exercise of common stock options


210,775


329,307


462,227Shares issued for 401(k) plan


20,780


18,341


16,883Shares issued directors' fees


6,671


4,126


Shares issued for nonvested equity shares of common stock


243,080


403,800


252,817Shares retired or forfeited


(113,830
)

(136,072
)

(285,760
)Shares at end of period


45,128,431


44,760,955


44,141,453Treasury Stock:Shares at beginning of period








124,024Treasury stock acquired


63,542


107,391


161,736Treasury stock retired


(63,542
)

(107,391
)

(285,760
)Shares at end of period











Accumulated Other Comprehensive Income.The Company follows the provisions of SFAS No. 130,Reporting Comprehensive
Income, which establishes standards for reporting comprehensive income. The

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

10. Stockholders' Equity (Continued)

components
of accumulated other comprehensive income and related tax effects for the years ended December 31, 2006, 2007 and 2008 were as follows:

Gross

Tax Effect

Net of Tax(in thousands)Accumulated other comprehensive incomeDecember 31, 2006

$
46,807

$
(17,436
)
$
29,371Unrealized change in fair value of hedges


(126,223
)

47,018


(79,205
)Reclassification adjustment for realized gains on hedges included in net income


87,018


(32,414
)

54,604Accumulated other comprehensive incomeDecember 31, 2007

$
7,602

$
(2,832
)
$
4,770Unrealized change in fair value of hedges


330,715


(122,724
)

207,991Reclassification adjustment for realized gains on hedges included in net income


(31,567
)

11,719


(19,848
)Reclassification adjustment for discontinued cash flow hedges included in net income


(1,340
)

499


(841
)Accumulated other comprehensive incomeDecember 31, 2008

$
305,410

$
(113,338
)
$
192,072


11. Equity Incentive Compensation Plans and Other Employee Benefits

The Company maintains various stock-based compensation plans as discussed below. Under the fair value recognition provisions of SFAS 123R, stock-based compensation is measured at
the grant date based on the value of the awards, and the value is recognized on a straight-line basis over the requisite service period (usually the vesting period).

Stock Options and Nonvested Equity Shares.In January 2002, the Company adopted a stock option plan to benefit key employees,
directors and
non-employees. This plan was amended and restated in its entirety by the Amended and Restated 2002 Stock Option Plan (the "2002 Option Plan"). The aggregate number of shares that the
Company may issue under the 2002 Option Plan may not exceed 1,642,395 shares of the Company's common stock. Options granted under the 2002 Option Plan expire up to ten years from the grant date. The
options vest 40% on the first anniversary of the date of grant and 20% on each of the following three subsequent anniversaries of the date of grant.

In
December 2003, the Company adopted its 2003 Stock Option Plan (the "2003 Option Plan") to benefit key employees, directors and non-employees. In April 2004, the 2003
Option Plan was approved by the Company's stockholders. The aggregate number of shares that the Company may issue under the 2003 Option Plan may not exceed 42,936 shares of the Company's common stock.
Options granted under the 2003 Option Plan expire up to ten years from the date of grant with an exercise price not less than 100% of the fair market value, as defined in the 2003 Option Plan, of the
underlying common shares on the date of grant. Options granted under the 2003 Option Plan vest 25% on each of the first four anniversaries of the date of grant.

On
December 1, 2004, the Company's stockholders approved the 2004 Stock Incentive Plan (the "2004 Incentive Plan") for the purpose of enhancing the Company's ability to attract
and retain officers, employees, directors and consultants and to provide such persons with an interest in the

F-33

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

11. Equity Incentive Compensation Plans and Other Employee Benefits (Continued)

Company
parallel to its stockholders. The 2004 Incentive Plan provides for the grant of stock options (including incentive stock options and non-qualified stock options) and other awards
(including performance units, performance shares, share awards, restricted stock, restricted stock units, and stock appreciation rights, or SARs). The maximum number of shares of common stock that may
be granted under the 2004 Incentive Plan is 4,900,000. In addition, the maximum number of shares of common stock that may be granted to a participant in any one year is 1,225,000. Options granted thus
far under the 2004 Incentive Plan generally expire seven years from the date of grant and vest 25% on each of the first four anniversaries of the date of grant. Unless terminated earlier by the Board
of Directors of the Company, the 2004 Incentive Plan will terminate on June 30, 2014. Upon an event constituting a "change in control" (as defined in the 2004 Incentive Plan) of the Company,
all options will become immediately exercisable in full. In addition, in such an event, performance units will become immediately vested, and restrictions on restricted stock awards will lapse.

The
Company's Compensation Committee may grant awards on such terms, including vesting and payment forms, as it deems appropriate in its discretion; however, no award may be exercised
more than 10 years after its grant (five years in the case of an incentive stock option granted to an eligible individual who possesses more than 10% of the total combined voting power of all
classes of stock of the Company). The purchase price or the manner in which the exercise price is to be determined for shares under each award will be determined by the Compensation Committee and set
forth in the agreement. However, the exercise price per share under each award may not be less than 100% of the fair market value of a share on the date the award is granted (110% in the case of an
incentive stock option granted to an eligible individual who possesses more than 10% of the total combined voting power of all classes of stock of the Company).

Currently,
the Company's practice is to issue new shares upon stock option exercise. The Company does not expect to repurchase any shares in the open market or issue treasury shares to
settle any such exercises. For the years ended December 31, 2008, 2007 and 2006, the Company did not pay cash to repurchase any stock option exercises.

In
accordance with SFAS No. 123R, the fair value of each share-based option award under all of the Company's plans is estimated on the date of grant using a Black-Scholes pricing
model that incorporates the assumptions noted in the following table. Where the Company did not have enough historical data relating to its own common stock to compute volatilities associated with
certain expected terms, expected volatilities were estimated based on an average of volatilities of similar sized Rocky Mountain oil and gas companies whose common stock is or has been publicly traded
for a minimum of five years and other similar sized oil and gas companies who recently became publicly traded. For expected terms for which the Company had adequate historical data relating to its own
common stock, estimated expected volatilities were based upon historical volatility of the Company's common stock. For options granted when the Company was a nonpublic company, it adopted the minimum
value method under SFAS No. 123, which uses 0% volatility. Given the Company's stage of growth and requirement for capital investment, the Company used a 0% expected dividend yield, which is
comparable to most of its peers in the industry. The expected terms range from 1.25 years to 5.0 years based on 25% of each grant's vesting on each anniversary date and factoring in
potential blackout dates and historic exercises, with a weighted average of 2.9 years. The risk-free rate for periods within the contractual life of the option is based on the U.S.
Treasury yield curve in effect on the date of grant.

F-34

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

11. Equity Incentive Compensation Plans and Other Employee Benefits (Continued)

The
Company estimated a 6% annual compounded forfeiture rate, based on historical employee turnover and actual forfeitures, for 2008 and 2007 and a 4% annual compounded forfeiture rate for 2006.

Year Ended December 31,2008

2007

2006Weighted Average Volatility


40
%

41
%

36
%Expected Dividend Yield


0
%

0
%

0
%Weighted Average Expected Term (in years)


2.9


2.9


2.7Weighted Average Risk-free Rate


2.3
%

4.7
%

4.3
%


A
summary of share-based option activity under all the Company's plans as of December 31, 2008, and changes during the year then ended, is presented below:

Shares

Weighted-average
Exercise Price

Weighted-average
remaining
contractual term

Aggregate
intrinsic valueOutstanding at January 1, 2008


2,917,862

$
28.25Granted


783,400


42.90Exercised


(210,775
)

21.90Forfeited or expired


(110,238
)

31.92Outstanding at December 31, 2008


3,380,249

$
31.92


4.56

$
1,077,938Vested, or expected to vest, at December 31, 2008 through the life of the options


3,274,014

$
31.77


4.53


1,075,986Vested and exercisable at December 31, 2008


1,609,672

$
26.78


3.58

$
1,011,768


The
per share weighted-average grant-date fair value of awards granted for the years ended December 31, 2008, 2007 and 2006 was $12.40, $10.13 and $7.26, respectively,
and the total intrinsic value of awards exercised during the same periods was $5.6 million, $4.3 million and $4.5 million, respectively. The aggregate intrinsic value in the
preceding table represents the total pre-tax intrinsic value, based on the Company's closing stock price of $21.13 on December 31, 2008. With respect to stock option exercises, the
Company received $4.1 million, $5.1 million and $4.9 million for the years ended December 31, 2008, 2007 and 2006, respectively.

F-35

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

11. Equity Incentive Compensation Plans and Other Employee Benefits (Continued)

A
summary of the Company's nonvested equity shares of common stock as of December 31, 2008, and changes during the year then ended, is presented below:

Shares

Weighted-average
Grant Date Fair
ValueOutstanding at January 1, 2008


339,100

$
32.26Granted


225,230


41.51Vested


(99,294
)

32.26Forfeited or expired


(40,733
)

37.53Outstanding at December 31, 2008


424,303

$
36.72Vested, or expected to vest, at December 31, 2008 through the life of the option


398,845

$
36.72Vested and exercisable at December 31, 2008




$



The
Company recorded non-cash stock-based compensation related to share-based option and nonvested equity share awards of $11.9 million, $8.0 million, and
$6.4 million for the years ended December 31, 2008, 2007 and 2006, respectively. Included in the $6.4 million of stock-based compensation for the year ended December 31,
2006 is $0.9 million related to the modification of equity awards for certain employees in which their vesting terms were accelerated. For the years ended December 31, 2008, 2007 and
2006, the Company did not recognize an excess tax benefit related to the exercise of stock options in accordance with SFAS No. 123R. As of December 31, 2008, there was
$24.3 million of total compensation costs related to nonvested stock option and nonvested equity shares of common stock grants that are expected to be recognized over a weighted-average period
of 2.5 years.

Performance Share Plan.On May 9, 2007, the Compensation Committee of the Board of Directors of the Company approved a
performance share
program pursuant to the Company's 2004 Stock Incentive Plan for the Company's officers and other senior employees, pursuant to which vesting of awards is contingent upon meeting various
Company-wide performance goals. Upon commencement of the program and during each subsequent year of the program, the Compensation Committee will meet to approve target and stretch goals
for certain operational or financial metrics that are selected by the Compensation Committee for the upcoming year and to determine whether metrics for the prior year have been met. These
performance-based awards contingently vest over a period up to four years, depending on the level at which the performance goals are achieved. Each year for four years, it is possible for between 25%
and 50% of the original shares to vest based on the achievement of the performance goals. Twenty-five percent of the total grant will vest for metrics met at the target level, and an
additional 25% of the total grant will vest for performance met at the stretch level. If the actual results for a metric are between the target levels and the stretch levels, the vested number of
shares will be adjusted on a prorated basis of the actual results compared to the target and stretch goals. If the target level metrics are not met, no shares will vest. In any event, the total number
of common shares that could vest will not exceed the original number of performance shares granted. At the end of four years, any shares that have not vested will be forfeited. A total of 250,000
shares under the 2004 Incentive Plan were set aside for this program.

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

11. Equity Incentive Compensation Plans and Other Employee Benefits (Continued)

For
the year ended December 31, 2007, the performance goals consisted of annual production growth (weighted at 30%), additions to the Company's natural gas and oil reserves
(weighted at 30%), finding and development costs (weighted at 30%) and general and administrative expenses (weighted at 10%). The weighting was determined by the Compensation Committee. Each metric is
independent so that vesting can occur for one or more metrics even if the goals are not achieved for other metrics. Also, for the year ended December 31, 2007, the Compensation Committee
required that an initial threshold level for finding and development costs be met before any of the performance shares would vest. In future years of the program, the Compensation Committee may impose
initial threshold levels based on this or other metrics. Based upon Company performance in 2007, 30% of the performance shares granted in 2007 vested in February 2008, and the Company recognized
$0.5 million of compensation costs related to these awards for the year ended December 31, 2008.

As
new goals are established each year, a new grant date and a new fair value are created for financial reporting purposes for those shares that could potentially vest in the upcoming
year. Compensation cost is recognized based upon the probability that the performance goals will be met. If such goals are not met, no compensation cost is recognized and any previously recognized
compensation cost is reversed.

In
February 2008, the Compensation Committee approved the performance metrics for vesting of the performance shares based on 2008 performance. For the year ended December 31,
2008, the performance goals consisted of annual production growth (weighted at 30%), additions to the Company's natural gas and oil reserves (weighted at 30%), finding and development costs (weighted
at 30%) and lease operating expenses (weighted at 10%). Also for the year ended December 31, 2008, the
Compensation Committee required that an initial threshold level for finding and development costs be met before any of the performance shares would vest. As of December 31, 2008, the Company
determined that 50% of the total grant related to the year ended December 31, 2008 would vest. Accordingly, the Company recorded non-cash stock-based compensation related to
performance-based nonvested equity share awards of $4.9 million for the year ended December 31, 2008. As of December 31, 2008, there was $0.4 million of total compensation
cost that will be recognized through February 2009, which represents the remaining time vesting requirement.

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

11. Equity Incentive Compensation Plans and Other Employee Benefits (Continued)

A
summary of the Company's nonvested performance-based equity shares of common stock as of December 31, 2008, and changes during the year then ended, is presented below:

Shares

Weighted-average
Grant Date Fair
ValueOutstanding at January 1, 2008


225,000

$
37.21Vested


(67,500
)

37.21Modified, performance goals revised(1)


(157,500
)

37.21Modified, performance goals revised(1)


157,500


42.83Granted


17,850


39.69Forfeited or expired


(9,555
)

37.83Outstanding at December 31, 2008


165,795

$
42.49Vested, or expected to vest, at December 31, 2008 through the life of the shares


126,650

$
42.51Vested and exercisable at December 31, 2008




$



---

On
May 13, 2008, at the Company's annual meeting of stockholders, the Company's stockholders approved the 2008 Stock Incentive Plan (the "2008 Incentive Plan"), which had been
previously approved by the Company's Board of Directors. The 2008 Incentive Plan became effective May 13, 2008. The types of awards that may be granted under the 2008 Incentive Plan include
incentive and non-qualified stock options, stock appreciation rights, restricted stock, performance shares and other stock-based awards. The total number of shares of the Company's common
stock available for issuance under the 2008 Incentive Plan is 3,000,000, subject to adjustment for future stock splits, stock dividends and similar changes in the Company's capitalization. The maximum
number of shares of common stock that may be the subject of awards other than options and stock appreciation rights is 1,000,000, while the maximum number of shares of common stock that may be issued
pursuant to stock options and stock appreciation rights is 3,000,000. The aggregate number of shares of common stock subject to options and/or stock appreciation rights granted during any calendar
year to any one participant may not exceed 500,000. The aggregate number of shares of common stock subject to restricted stock and/or restricted stock unit awards granted during any calendar year to
any one participant may not exceed 500,000. No awards have been granted under the 2008 Incentive Plan as of December 31, 2008.

Director Fees.The Company's directors may elect to receive their annual retainer and meeting fees in the form of the Company's
common stock issued,
pursuant to the Company's 2004 Incentive Plan. After each quarter, shares with a value equal to the fees payable for that quarter, calculated using the closing price on the last trading day before the
end of the quarter, will be delivered to each outside director who elected before that quarter end to receive shares of the Company's common stock for payment of the director's fees. For the year
ended December 31, 2008, the Company issued 6,671

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

11. Equity Incentive Compensation Plans and Other Employee Benefits (Continued)

shares
of common stock under the 2004 Incentive Plan for payment of the director's fees and recognized $0.2 million of non-cash stock-based compensation cost associated with the
issuance of those shares.

Other Employee Benefits-401(k) Savings Plan.The Company has an employee directed 401(k) savings plan (the "401(k) Plan") for
all
eligible employees over the age of 21. Employees become eligible the quarter following the beginning of their employment. Under the 401(k) Plan, employees may make voluntary contributions based upon a
percentage of their pretax income.

The
Company matches 100% of each employee's contribution, up to 6% of the employee's pretax income, with 50% of the match made with the Company's common stock. The Company's cash and
common stock contributions and shares of common stock are fully vested upon the date of match. The Company made matching cash and common stock contributions of $1.4 million,
$1.2 million, and $1.0 million for the years ended December 31, 2008, 2007 and 2006, respectively.

12. Transactions with Related Parties

A former director of the Company (who served until May 2006) was a managing director of a company which wholly owns the counterparty to a portion of the natural gas and oil hedges noted
in Note 8 above. In management's opinion, the terms obtained in these transactions were as favorable to the Company as could be obtained from non-related sources.

13. Significant Customers and Other Concentrations

Significant Customers.During 2008, EnCana Oil & Gas and Sempra Energy Trading Corporation accounted for 16.7% and
16.6%, respectively, of the
Company's oil and gas production revenues. During 2007, Sempra Energy Trading Corporation, EnCana Oil & Gas and United Energy Trading accounted for 20.6%, 15.7% and 8.7%, respectively, of the
Company's oil and gas production revenues. During 2006, Sempra Energy Trading Corporation, Xcel Energy Inc. and ONEOK Inc. accounted for 21.3%, 10.0% and 9.7%, respectively, of the
Company's oil and gas production revenues. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or
results of operations of the Company.

Concentrations of Market Risk.The future results of the Company's oil and gas operations will be affected by the market prices
of oil and gas. The
availability of a ready market for crude oil, natural gas and liquid products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of
competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil, gas and liquid products, the regulatory environment, the
economic environment, and other regional and political events, none of which can be predicted with certainty.

The
Company operates in the exploration, development and production phase of the oil and gas industry. Its receivables include amounts due from purchasers of oil and gas production and
amounts due from joint venture partners for their respective portions of operating expense and exploration and development costs. The Company believes that no single customer or joint venture partner
exposes the Company to significant credit risk. While certain of these customers and joint venture partners are

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

13. Significant Customers and Other Concentrations (Continued)

affected
by periodic downturns in the economy in general or in their specific segment of the natural gas or oil industry, the Company believes that its level of credit-related losses due to such
economic fluctuations has been and will continue to be immaterial to the Company's results of operations in the long-term. Trade receivables are generally not collateralized. The Company
analyzes customers' and joint venture partners' historical credit positions and payment histories prior to extending credit.

Concentrations of Credit Risk.Derivative financial instruments that hedge the price of oil and gas and interest rate levels are
generally executed
with major financial or commodities trading institutions which expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties.
The Company has hedges in place with eight different counterparties, of which all but one are lenders in our Amended Credit Facility. As of December 31, 2008, JP Morgan Chase & Company,
J. Aron & Company (a subsidiary of Goldman, Sachs & Company) and Bank of Montreal accounted for 43.6%, 22.8% and 15.1%, respectively, of the net fair market value of the Company's
derivative asset. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the
counterparties, are substantially smaller. The credit worthiness of counterparties is subject to continuing review, and the Company believes all of these institutions currently are acceptable credit
risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties. The Company's policy is to execute financial derivatives only with major, credit
worthy financial institutions.

14. Commitments and Contingencies

Transportation Demand and Firm Processing Charges.The Company has entered into contracts that provide firm transportation
capacity on pipeline
systems and firm processing charges. The remaining terms on these contracts range from one to 14 years and require the Company to pay transportation demand and processing charges regardless of
the amount of pipeline capacity utilized by the Company. The Company paid $9.4 million, $5.5 million and $3.7 million of transportation demand charges for the years ended
December 31, 2008, 2007 and 2006, respectively. The Company paid $3.5 million, $3.7 million and $0.7 million of firm processing charges in 2008, 2007 and 2006,
respectively. All transportation costs including demand charges and processing charges, are included in gathering and transportation expense in the Consolidated Statements of Operations.

The
values in the table below represent the Company's gross future minimum transportation demand and firm processing charges as of and subsequent to December 31, 2008. However,
the

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

14. Commitments and Contingencies (Continued)

Company
will record in its financial statements only the Company's proportionate share based on the Company's working interest and net revenue interest, which will vary from basin to basin.

(in thousands)2009

$
25,8182010


29,8162011


50,5692012


54,2362013


53,950Thereafter


323,962Total

$
538,351


Lease Obligations and Other Commitments.The Company leases office space, vehicles and certain equipment under non-cancelable
operating
leases. Office lease expense was $1.4 million for each of the years ended December 31, 2008, 2007 and 2006. Additionally, the Company has entered into various long-term
agreements for telecommunications service. The Company also has commitments for developing oil and gas properties of $65.6 million for 2009 through 2011, which consist of drilling and carbon
dioxide ("CO2") purchase contracts that are included in the minimum payment schedule below.

Future
minimum annual payments under such leases and agreements as of and subsequent to December 31, 2008 are as follows:

Other
Commitments(1)

Office &
Equipment
Leases(in thousands)2009

$
31,790

$
2,5542010


24,550


2,5542011


9,300


7432012





2013





Thereafter





Total

$
65,640

$
5,851






Drilling and Purchase Contracts.At December 31, 2008, the Company had one drilling rig under contract through 2009, two
through 2010 and one
through 2011, which have total commitments of $42.3 million. Early termination of these contracts would require penalty payments of $29.4 million. Other drilling rigs working for the
Company are not under long-term contracts but instead are under contracts that can be terminated at the end of the current operations. In addition, the Company has

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

14. Commitments and Contingencies (Continued)

two
take-or-pay purchase agreements for supply of CO2, which have a total financial commitment of $23.4 million. Under these contracts, the Company is obligated to
purchase a minimum daily volume at a set price, subject to annual escalation. If the Company takes delivery of less than the minimum required amount, the Company is responsible for full payment
(deficiency payment). At this time, the Company anticipates sufficient need for CO2 and, therefore, expects to avoid any deficiency payments. The CO2 is for use in fracturing operations in the
Company's West Tavaputs field.

Litigation.The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the course of
ordinary business. It
is the opinion of the Company's management that current claims and litigation involving the Company are not likely to have a material adverse effect on its consolidated financial position, cash flows
or results of operations.

15. Supplementary Oil and Gas Information (unaudited)

Costs Incurred.Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion
per equivalent
unit-of-production were as follows:

Year Ended December 31,2008

2007

2006(in thousands, except amortization data)Acquisition costs:Unproved properties

$
33,057

$
23,635

$
126,091Proved properties


6,314


2,008


33,138Exploration costs


342,890


250,687


224,189Development costs


213,996


162,502


114,593Asset retirement obligation


8,198


982


6,272Total costs incurred

$
604,455

$
439,814

$
504,283Depletion per Mcfe of production

$
2.59

$
2.78

$
2.60


Supplemental Oil and Gas Reserve Information.The reserve information presented below is based on estimates of net proved
reserves as of
December 31, 2008, 2007, and 2006 that were prepared by internal petroleum engineers in accordance with guidelines established by the SEC and were reviewed by independent petroleum engineering
firms, Ryder Scott Company and Netherland, Sewell & Associates, Inc. ("NSAI") in 2006 and reviewed by NSAI in 2007 and 2008.

Proved
oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas
reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

15. Supplementary Oil and Gas Information (unaudited) (Continued)

Analysis of Changes in Proved Reserves.The following table sets forth information regarding the Company's estimated net total
proved and proved
developed oil and gas reserve quantities:

Oil
(MBbls)

Gas
(MMcf)

Equivalent
Units (MMcfe)Proved reserves:Balance, December 31, 2006


8,453


377,726


428,444Purchases of oil and gas reserves in place


1


2,673


2,679Extension, discoveries and other additions


1,021


169,618


175,744Revisions of previous estimates


322


52,231


54,163Sales of reserves


(5,989
)

(6,257
)

(42,191
)Production


(586
)

(57,678
)

(61,194
)Balance, December 31, 2007


3,222


538,313


557,645Purchases of oil and gas reserves in place


3


3,060


3,078Extension, discoveries and other additions


2,047


183,918


196,200Revisions of previous estimates


1,051


132,780


139,086Sales of reserves





(126
)

(126
)Production


(661
)

(73,623
)

(77,589
)Balance, December 31, 2008


5,662


784,322


818,294Proved developed reserves:December 31, 2006


5,006


218,902


248,938December 31, 2007


2,090


317,298


329,838December 31, 2008


3,100


416,546


435,146


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

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

At
year-end 2006, the Company revised its proved reserves upward by 12.4 Bcfe, excluding pricing revisions. This revision was primarily the result of increased performance of
wells drilled during the last half of 2005 and the first half of 2006. The pricing revision at year-end 2006 at prices of $4.46 per

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

15. Supplementary Oil and Gas Information (unaudited) (Continued)

MMBtu
of gas and $61.06 per barrel of oil, relative to year-end 2005 prices of $7.72 per MMBtu and $61.04 per barrel of oil, was downward 33.8 Bcfe. Year-end prices were
adjusted by lease for quality, transportation fees and regional price differences.

Standardized Measure.Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS
No. 69, Disclosures about Oil and Gas Producing Activities. Certain information concerning the assumptions used in computing the valuation of proved reserves
and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

Future
cash inflows are computed by applying year-end prices of oil and gas relating to the Company's proved reserves to the year-end quantities of those
reserves. Year-end calculations were made using prices of $41.00, $92.50 and $61.06 per Bbl for oil and $4.61, $6.04 and $4.46 per MMBtu for gas for 2008, 2007 and 2006, respectively.
These prices are adjusted for transportation and quality and basis differentials. The Company also records an overhead expense of $100 per month per operated well in the calculation of its future cash
flows.

The
assumptions used to compute estimated future cash inflows do not necessarily reflect the Company's expectations of actual revenues or costs, nor their present worth. In addition,
variations from the expected production rate also could result directly or indirectly from factors outside of the Company's control, such as unexpected delays in development, changes in prices or
regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic
considerations could also affect the amount of cash eventually realized.

Future
development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year,
based on year-end costs and assuming continuation of existing economic conditions.

Future
income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future
pre-tax net cash flows relating to the Company's proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.

A
10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

15. Supplementary Oil and Gas Information (unaudited) (Continued)

The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves:

Year Ended December 31,2008

2007

2006(in thousands)Future cash inflows

$
3,868,227

$
3,667,661

$
2,201,106Future production costs


(898,653
)

(861,344
)

(601,502
)Future development costs


(882,201
)

(554,410
)

(418,126
)Future income taxes


(389,275
)

(510,554
)

(168,959
)Future net cash flows


1,698,098


1,741,353


1,012,51910% annual discount


(839,955
)

(800,107
)

(483,233
)Standardized measure of discounted future net cash flows

$
858,143

$
941,246

$
529,286


The
present value (at a 10% annual discount) of future net cash flows from the Company's proved reserves is not necessarily the same as the current market value of its estimated oil and
natural gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash
flows from its oil and natural gas properties will also be affected by factors such as actual prices the Company receives 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 the Company's production and 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% annual discount factor the Company uses 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 the Company or the oil and natural gas industry in general.

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

15. Supplementary Oil and Gas Information (unaudited) (Continued)

A
summary of changes in the standardized measure of discounted future net cash flows is as follows:

Year Ended December 31,2008

2007

2006(in thousands)Standardized measure of discounted future net cash flows, beginning of period

$
941,246

$
529,286

$
782,478Sales of oil and gas, net of production costs and taxes


(445,909
)

(203,970
)

(253,645
)Extensions, discoveries and improved recovery, less related costs


243,289


379,243


178,726Quantity revisions


268,365


142,748


(43,902
)Price revisions


(353,264
)

262,362


(474,739
)Net changes in estimated future development costs


(110,687
)

(39,606
)

62,574Accretion of discount


120,385


60,281


104,960Purchases of reserves in place


6,397


3,454


33,518Sales of reserves


(191
)

(79,752
)

(9,671
)Changes in production rates (timing) and other


106,673


76,286


(44,614
)Net changes in future income taxes


81,839


(189,086
)

193,601Standardized measure of discounted future net cash flows, end of period

$
858,143

$
941,246

$
529,286


16. Quarterly Financial Data (unaudited)

The following is a summary of the unaudited quarterly financial data, including income before income taxes, net income and net income per common share for the years ended
December 31, 2008 and 2007.

First Quarter

Second Quarter

Third Quarter

Fourth Quarter(in thousands, except per share data)Year ended December 31, 2008:Total revenues

$
149,202

$
157,519

$
164,415

$
146,775Less: costs and expenses


96,324


102,811


100,978


131,683Operating income

$
52,878

$
54,708

$
63,437

$
15,092Income before income taxes


49,724


51,168


60,396


11,029Net income


30,708


33,982


36,065


6,892Net income per common share, basic


0.69


0.76


0.81


0.15Net income per common share, diluted


0.68


0.75


0.80


0.15


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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006

16. Quarterly Financial Data (unaudited) (Continued)



First Quarter

Second Quarter

Third Quarter

Fourth Quarter(in thousands, except per share data)Year ended December 31, 2007:Total revenues

$
98,380

$
100,653

$
82,255

$
108,982Less: costs and expenses


72,968


82,040


79,693


101,208Operating income

$
25,412

$
18,613

$
2,562

$
7,774Income before income taxes


23,069


16,050


499


4,380Net income


14,184


9,858


233


2,479Net income per common share, basic


0.32


0.22


0.01


0.06Net income per common share, diluted


0.32


0.22


0.01


0.06


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