UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

Commission file number 001-32367

BILL BARRETT CORPORATION

(303) 293-9100
(Registrant’s telephone number, including area code)

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

     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. Yes R No £.

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes £ No R.

There were 43,387,479 shares of $.001 par value common stock outstanding on April 29, 2005.

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

See notes to consolidated financial statements.

2

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)

See notes to consolidated financial statements.

3

BILL BARRETT CORPORATION

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

See notes to consolidated financial statements.

4

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

See notes to consolidated financial statements.

5

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

March 31, 2005

1. Organization

     Bill Barrett Corporation (the “Company”, “we”, or “us”), a Delaware corporation, is an independent oil and gas company engaged in the acquisition, exploration, development and production of natural gas and crude oil. Since its inception on January 7, 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States. On December 9, 2004, our Registration Statements on Form S-1 (SEC File Nos. 333-114554, 333-121128 and 333-121142) concerning our initial public offering (“IPO”) were declared effective by the Securities and Exchange Commission (the “SEC”). The offering was completed on December 15, 2004 and the underwriters purchased a total of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. We received net proceeds of $347 million after deducting underwriting fees and other offering costs.

2. Summary of Significant Accounting Policies

     Basis of Presentation. The accompanying unaudited consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information. Pursuant to the rules and regulations of the SEC, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of March 31, 2005, and the results of operations and cash flows for the three months ended March 31, 2005 and 2004. Operating results for the three month period ended March 31, 2005 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, these consolidated financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2004 previously filed with the SEC.

     In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

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

     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. Generally, if an exploratory well does not find proved reserves within one year following completion of drilling, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs also are capitalized. Interest cost is capitalized as a component of property cost for exploration and development projects that require greater than six months to be readied for their intended use. To date, the Company has not capitalized any interest expense.

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

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

     Net capitalized costs relating to the Company’s natural gas and oil producing activities are summarized as follows (in thousands):

     The following table reflects the net changes in capitalized exploratory well costs for the three months ended March 31, 2005 (in thousands):

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

     The provision for depreciation, depletion and amortization (“DD&A”) of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Oil is converted to natural gas equivalents, Mcfe, at the rate of one barrel to six Mcf. Taken into consideration in the calculation of DD&A is estimated future dismantlement, restoration and abandonment costs, net of estimated salvage values.

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

     For awards granted while we were a nonpublic company (those granted prior to April 16, 2004, the date of which is defined by SFAS No. 123R as the date we became a public company as a result of making a filing with a regulatory agency in preparation for the sale of equity securities in a public market), we adopted SFAS No. 123R using the prospective transition method. Under the prospective transition method, we continue to account for awards granted prior to becoming a public company using the minimum value method described under APB No. 25. Accordingly, zero compensation expense was recorded upon adoption of SFAS No. 123R for those awards. Additionally, the calculated fair value of those awards using the minimum value method is not comparable to those options granted subsequent to April 16, 2004, for which a fair-value-based method was used.

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

     Included within general and administrative expense is non-cash stock based compensation related to option and restricted stock awards of $1.3 million and $0.7 million for the three months ended March 31, 2004 and 2005, respectively. As of March 31, 2005, there was $7.9 million of total unrecognized compensation costs related to nonvested stock options and restricted stock recorded in deferred compensation.

3. Per Share Data and Earnings Per Share

     Immediately preceding the completion of our IPO in December 2004, a common stock reverse split of 1-for-4.658 was effected. All share and per share amounts for periods prior to December 2004 have been restated to reflect the reverse split.

     Basic net income per common share of stock is calculated by dividing net income attributable to common stock by the weighted average of vested 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.

     Net income attributable to common stock is calculated by reducing net income by dividends earned on preferred securities. For the three months ended March 31, 2004, Series B preferred dividends, whether or not declared or paid, were considered earned for purposes of these calculations. The Series A and Series B preferred stock and a convertible note that subsequently converted into Series A preferred stock were not included in the computation of earnings per share for the three months ended March 31, 2004 because their inclusion would have been anti-dilutive.

     The Emerging Issues Task Force (EITF) has issued EITF Issue No. 03-6, Participating Securities and the Two-Class Method under FASB Statement No. 128 “Earnings Per Share” (“EITF 03-6”). We adopted EITF 03-6 as of January 1, 2004. EITF 03-6 provides guidance for the computation of earnings per share using the two-class method for enterprises with participating securities or multiple classes of common stock as required by SFAS No. 128. The two-class method allocates undistributed earnings to each class of common stock and participating securities for the purpose of computing

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basic earnings per share. However, upon completion of our IPO on December 15, 2004, all outstanding preferred securities were converted into common stock and, thus, we were not required to apply the two-class method subsequent to that date. The weighted average common shares outstanding at March 31, 2004 reflect the reverse split that occurred in conjunction with our IPO.

     The following table sets forth the calculation of basic and diluted earnings per share (in thousands except per share amounts):

4. Supplemental Disclosures of Cash Flow Information:

     Supplemental cash flow information is as follows (in thousands):

5. Derivative Instruments and Hedging Activities.

     The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its natural gas and oil production by reducing its exposure to price fluctuations. The Company accounts for such activities pursuant to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities.

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

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     For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive (loss) 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 may utilize derivative financial instruments which have not been designated as hedges under SFAS No. 133 even though they protect the Company from changes in commodity prices. These instruments are marked to market with the resulting changes in fair value recorded in earnings.

     To mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices and to comply with our credit agreement, we have entered into commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. Our natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133.

     The Company was a party to various swap contracts for natural gas based on Northwest Pipeline Rocky Mountains (“NORRM”) and Colorado Interstate Gas Rocky Mountains (“CIGRM”) indexes during the first three months of 2004 and 2005, recognizing a reduction of natural gas production revenues of $2.3 million and $668,000, respectively, related to these contracts. The Company was a party to various swap contracts for oil based on a West Texas Intermediate (“WTI”) index recognizing a reduction to oil production revenues of $544,000 related to these contracts in the first three months of 2005. There were no swap contract settlements for oil for the first three months of 2004. As the underlying prices in the Company’s hedge contracts were consistent with the indices used to sell its natural gas and oil, no ineffectiveness was recognized related to its hedge contracts for the three months ended March 31, 2004 and 2005.

     The Company was a party to various collar contracts for natural gas based on a NORRM index price for the first three months of 2005. Because actual index prices realized fell between the floor and ceiling prices of the collar contract, no increase or decrease to gas production revenues was recognized in the first three months of 2005.

     At March 31, 2005, we had the following commodity swap contracts in place to hedge cash flow and reduce the impact of natural gas and oil price fluctuations:

     At March 31, 2005, we had the following cashless collars (purchased put options and written call options) in order to hedge a portion of our 2005 and 2006 natural gas and oil production. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production and are also designated as cash flow hedges in accordance with SFAS No. 133.

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     The Company’s natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133 and are included in current and other long-term liabilities in the Company’s Consolidated Balance Sheets.

     At March 31, 2005, the estimated fair value of contracts designated and qualifying as cash flow hedges under SFAS No. 133 was a liability of $32.3 million. The Company will reclassify the appropriate amount to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected prices, the net amount of existing unrealized after-tax loss as of March 31, 2005 to be reclassified from accumulated other comprehensive loss to net income in the next twelve months would be $15.4 million. Of this amount, $8.2 million pertains to swap contracts, and $7.2 million pertains to collar contracts. In regards to the collar contracts, no amounts will be reclassified if actual prices received fall between the floor and ceiling prices as set forth in the contracts. The Company anticipates that all original forecasted transactions will occur by the end of the originally specified time periods.

6. Asset Retirement Obligations

     The Company follows the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations, in accounting for its obligations associated with the retirement of tangible long-lived assets. The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the accompanying Consolidated Statements of Operations. A reconciliation of the changes in the liability for the three months ended March 31, 2005 follows (in thousands):

7. Income Taxes

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

     Income tax expense for the three months ended March 31, 2004 and 2005 differs from the amounts that would be

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provided by applying the U.S. federal income tax rate of 34% to income before income taxes principally due to stock-based compensation not deductible for income tax purposes and other permanent differences.

     At March 31, 2005 the Company’s balance sheet reflected net deferred tax assets of $12.9 million, of which $11.9 million pertains to the tax effects of derivative instruments reflected in other comprehensive (loss) income. The Company has not recognized a valuation allowance against its net deferred tax assets because it believes that it is more likely than not that the net deferred tax assets will be realized on future income tax returns, primarily from the generation of future taxable income.

8. Stockholders’ Equity

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

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

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

     As of March 31, 2005, of the 1,800,548 common shares issued to founding management and employees, 100% were dollar vested and 1,582,173 shares were time vested. The remaining time vesting will occur ratably through January 2006.

     There are no issued and outstanding shares of Series A Junior Participating Preferred Stock. It ranks junior to all series of preferred stock with respect to dividends and specified liquidation events. Dividends on this series are cumulative and do not bear interest, however, no dividend payment, or payment-in-kind, may be made to holders of common stock without declaring a dividend on this series equal to 1,000 times the aggregate per share amount declared on common stock. Upon the occurrence of specified liquidation events, the holders of this series shall be entitled to receive an aggregate amount per share equal to 1,000 times the aggregate amount to be distributed per share to holders of shares of common stock plus an amount equal to any accrued and unpaid dividends. Upon consolidation, merger or combination in which shares of common stock are exchanged for or changed into other securities or other assets, each share of this series shall be similarly exchanged into an amount per share equal to 1,000 times that into which each share of common stock is exchanged. The number of Series A Junior Participating Preferred Stock will be proportionately changed in the event the Company declares or pays a common stock dividend or effects a stock split of common stock.

9. Accumulated Other Comprehensive Loss

     The Company follows the provisions of SFAS No. 130, Reporting Comprehensive Income, which establishes standards for reporting comprehensive income. The components of accumulated other comprehensive loss and related tax effects for the three months ended March 31, 2005 were as follows:

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10. Restatement of Consolidated Financial Statements

     Subsequent to filing the Company’s first amendment to the Registration Statement on Form S-1/A on July 2, 2004, management determined that, for financial reporting purposes, the amount of stock-based compensation expense related to restricted common stock issued to management during the year ended 2002 at the formation of the Company (“Management Stock”), Series B preferred stock purchased by employees during the years ended 2003 and 2004 at less than fair value for financial reporting purposes, and options granted in years ended 2002, 2003 and 2004 under our 2002 Stock Option Plan and 2003 Stock Option Plan should be adjusted to reflect an increase in intrinsic value received as a result of upward adjustments to the estimated fair value of our common stock. As a result, the Company’s consolidated financial statements for the three months ended March 31, 2004 have been restated from the amounts previously reported on Form S-1/A to reflect the changes in stock-based compensation expense. A summary of the significant effects of the restatement is as follows:

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     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 in our Annual Report on Form 10-K for the year ended December 31, 2004 under the subsections “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

     Bill Barrett Corporation (the “Company”, “we” or “us”) was formed in January 2002 and is incorporated in the State of Delaware. We explore for and develop natural gas and oil in the Rocky Mountain region of the United States. 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 or around the Gibson Gulch field in the Piceance Basin. In December 2004, we completed our initial public offering (“IPO”) of 14,950,000 shares of our common stock at a price to

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the public of $25.00 per share. We received net proceeds of $347 million after deducting underwriting fees and other offering costs.

Results of Operations

     The following table sets forth selected operating data for the three month periods ended March 31, 2004 and 2005.

Quarter Ended March 31, 2005 Compared to the Quarter Ended March 31, 2004

     The financial information with respect to the three month periods ended March 31, 2004 and 2005 that is discussed below is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.

     Production Revenues. Production revenues increased from $36.0 million in the quarter ended March 31, 2004 to $50.7 million in the quarter ended March 31, 2005 due to both an increase in production and increases in natural gas and oil prices. Price increases added approximately $8.0 million of production revenues and production increases from the development of existing properties added approximately $6.7 million of production revenues, after natural production declines so that our new production more than offset natural production declines.

     Total production volumes for the quarter ended March 31, 2005 increased 15% from total production for the quarter ended March 31, 2004. Additional information concerning production is in the following table.

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     The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields that occurred throughout 2004 and the first quarter of 2005, and on which development activities were more or less completed in late 2004. The production increase in the Uinta Basin is due to development activities in both the West Tavaputs and Hill Creek fields. The production increase in the Powder River Basin reflects the success of our development activities. The production increase in the Williston is principally due to continued development activities on the properties. The production increase in the Piceance Basin is a result of the acquisition made in September 2004. The production in the Piceance Basin includes 116 MMcf of a gas balancing settlement pertaining to production in the last quarter of 2004.

     Hedging Activities. During the first quarter of 2004, we hedged approximately 41% of our natural gas volumes and no oil volumes, incurring a reduction in revenues of $2.3 million. During the first quarter of 2005, we hedged approximately 63% of our natural gas volumes and 21% of our oil volumes, resulting in a reduction in revenues of $1.2 million.

     Lease Operating Expense and Gathering and Transportation Expense. Our lease operating expense increased from $0.41 per Mcfe in the first quarter of 2004 to $0.53 per Mcfe in the first quarter of 2005, and our gathering and transportation expense increased from $0.16 per Mcfe in the first quarter of 2004 to $0.32 per Mcfe in the first quarter of 2005. On a per Mcfe basis, the increase in lease operating expenses is primarily due to a workover in the Hill Creek field in the Uinta Basin and declining production in our Cave Gulch and Wallace Creek fields in the Wind River Basin with no corresponding decrease in fixed costs associated with operating these gas wells. The increase in gathering and transportation expense is principally attributable to the CBM properties in the Powder River Basin and resulted principally from increased third party charges for compressor fuel, the relative increase in production in the Powder River Basin, which is a higher gathering cost area, compared to the first quarter of 2004, and firm transportation fees we commenced incurring in the first quarter of 2005. We have entered into long-term firm transportation contracts to guarantee capacity on major pipelines to avoid production curtailments that may arise due to limited pipeline capacity. Generally, gathering contracts with third parties require we pay current market prices for compressor fuel consistent with the increase in realized prices on the gas we produce.

     Production Tax Expense. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 11.4% in the quarter ended March 31, 2004 and 12.7% in the quarter ended March 31, 2005. Production taxes are primarily based on the wellhead values of production and vary across the different areas that we operate. Total production taxes increased as a result of higher production revenues, primarily due to higher prices in the quarter ended March 31, 2005 compared to the quarter ended March 31, 2004.

     Exploration Expense. Exploration costs increased from $1.5 million in the first quarter of 2004 to $6.7 million in the first quarter of 2005. The costs for the quarter ended March 31, 2004 include $1.2 million for seismic programs in the Tri-State project area in the DJ Basin and $0.3 million for delay rentals and other costs. The costs for the quarter ended March 31, 2005 include $4.4 million for exploratory dry holes in the Wind River and Green River Basins, $1.7 million for seismic programs, principally in the Wind River Basin, and $0.6 million for delay rentals, unevaluated leasehold abandonments and other costs. The Company also determined that an exploratory well in the Uinta Basin that commenced drilling after March 31, 2005 was a dry hole. The costs related to this well will be reflected in the Company’s second quarter financial results.

     Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense was $19.8 million in the quarter ended March 31, 2005 compared to $12.4 million in the quarter ended March 31, 2004. $1.9 million of the increase is due to the 15% increase in production and $5.5 million is due to an increased depletion rate for the first quarter

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2005 production. During the quarter ended March 31, 2004, the weighted average depletion rate was $1.69 per Mcfe. In the quarter ended March 31, 2005, the weighted average depletion rate was $2.33 per Mcfe. Under successful efforts accounting, depletion expense is separately computed for each producing area. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a depletion rate for current production. Between the quarters ended March 31, 2004 and March 31, 2005, the Company’s cost of finding oil and gas reserves in certain areas yielded an overall higher depletion rate for the current quarter compared to the quarter ended March 31, 2004. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

     General and Administrative Expense. General and administrative expense increased $1.1 million from $5.3 million in the quarter ended March 31, 2004 to $6.4 million in the quarter ended March 31, 2005. This increase was primarily due to increased personnel required for our capital program and production levels. As of March 31, 2005, we had 154 full time employees compared to 108 as of March 31, 2004. General and administrative expense includes non-cash charges for stock based compensation, including $1.3 million in the first quarter of 2004 and $0.7 million in the first quarter of 2005. The decrease in charges for non-cash compensation was due to a stock based compensation charge related to the vesting of common stock in January 2004. On a per unit produced basis, general and administrative expense increased from $0.72 per Mcfe in the first quarter of 2004 to $0.75 per Mcfe in the first quarter of 2005. Our capital budget relative to our production levels is high and requires an appropriate number of personnel and related costs to prudently manage our capital expenditure program. Until our capital expenditure program significantly increases our production levels, we expect that general and administrative expense per unit of production to remain at current levels.

     Interest Expense. Interest expense decreased $0.1 million to $0.5 million in the quarter ended March 31, 2005 from $0.6 million in the quarter ended March 31, 2004. Interest expense in the 2005 first quarter is comprised of amortization of deferred financing costs and payment of debt commitment fees. Interest expense in the first quarter of 2004 is comprised of interest of $0.4 million on a weighted average outstanding balance of $58 million under our credit facility and $0.2 million of amortization of deferred financing costs and payment of debt commitment fees and in that quarter period. We had no outstanding indebtedness under our credit facility during the first quarter of 2005.

     Income Tax Expense. Our effective tax rate was 42% in the quarters ended March 31, 2004 and 2005. All of our income tax provisions are deferred. Due to the tax deductions being created by our drilling activities, we expect that we will not incur cash tax liabilities for at least the next year.

     Net Income. We generated net income of $3.1 million in the quarter ended March 31, 2005 compared to net income of $4.7 million in the quarter ended March 31, 2004. The primary reasons for the decrease in results were increases in all expense categories, the total of which exceeded increases in production volumes and product prices.

Capital Resources and Liquidity

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

     At March 31, 2005, our balance sheet reflected a cash balance of $89 million with no balance outstanding on our credit facility, principally as a result of completing our IPO on December 15, 2004, from which we received net proceeds of $347 million. On that date we repaid a $150 million bridge loan and paid down the outstanding balance of $123.2 million on our line of credit.

Cash Flow from Operating Activities

     Net cash provided by operating activities was $17.2 million and $41.7 million for the three months ended March 31,

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2004 and 2005, respectively. The increases in net cash provided by operating activities was partially due to increased production revenues, offset by increased expenses, as discussed above in “— Results of Operations”. Changes in current assets and liabilities reduced cash flow from operations by $4.4 million for the three months ended March 31, 2004, but increased cash flow from operations by $12.1 million for the three months ended March 31, 2005.

     Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas and oil produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

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

     The table below provides the volumes associated with the swap contracts as of March 31, 2005.

     The table below provides the volumes associated with the collar contracts as of March 31, 2005.

     By removing the price volatility from a portion of our natural gas and oil production for 2005 and 2006, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are

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creditworthy major financial institutions deemed by management as competent and competitive market makers.

     Based on hedging contracts outstanding on March 31, 2005, our cash flow hedge positions from natural gas and oil derivatives had an estimated net pre-tax liability of $32.3 million recorded as both current and non-current liabilities, as appropriate. The Company will reclassify this amount to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current prices, the net amount of existing unrealized after-tax loss as of March 31, 2005 to be reclassified from accumulated other comprehensive loss to natural gas and oil production operating revenues in the next twelve months would be $15.4 million. We anticipate that all original forecasted transactions will occur by the end of the originally specified time periods.

Capital Expenditures

     Our capital expenditures were $34.6 million and $65.9 million for the three months ended March 31, 2004 and 2005, respectively. The total for the three month period of 2004 includes $6.5 million for acquisitions of properties, $26.1 million for drilling, development, exploration and exploitation (including related gathering and facilities, but excluding exploratory dry holes) of natural gas and oil properties, $1.5 million related to geologic and geophysical costs and exploratory dry holes, which are expensed under successful efforts accounting as exploration expense, and $0.5 million for furniture, fixtures and equipment. The total capital expenditures for the three month period of 2005 includes $5.6 million for the acquisition of properties, $53.1 million for drilling, development and exploration of natural gas and oil properties, $6.7 million for geologic and geophysical costs and exploratory dry holes, and $0.5 million for furniture, fixtures and equipment.

     Unevaluated properties increased $12.4 million to $150.0 million at March 31, 2005 from $137.6 million at December 31, 2004, principally from increases in uncompleted wells in progress resulting from increased development and exploratory drilling activity during the first quarter of 2005.

     Our current capital budget, which is anticipated to change as the Company conducts activities throughout the year, is approximately $276 million for 2005, $66.5 million of which was incurred in the first quarter. Of the $276 million capital budget, we plan to spend approximately $238 million (86%) in our development areas in Wyoming, Utah, Montana, North Dakota and Colorado, $36 million (13%) on exploration activities in Utah and Wyoming, with the remaining amounts allocated to other activities. Of the $238 million planned for expenditures in our development areas, approximately $46 million has been allocated to drill and complete proved undeveloped and proved nonproducing reserves. We are projecting that cash on hand, cash available from operating activities and borrowings from our credit facility will be sufficient to fund our 2005 capital budget. In addition to our 2005 capital budget, we plan to seek industry partners with whom we expect to enter into joint exploration agreements which would involve a sell down of approximately 30% to 60% of our working interest in a number of exploration projects principally in Wyoming, Montana and North Dakota. Proceeds from the joint exploration agreements will be used to accelerate and drill additional exploration wells not reflected in the 2005 capital budget. During the first quarter of 2005, we sold for $5.5 million partial interests in two exploratory projects, one in the DJ Basin and the other in the Wind River Basin.

     The amount and timing of capital expenditures is largely discretionary and within our control. If natural gas and oil prices decline to levels below our acceptable levels, we could choose to defer a portion of these planned 2005 capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and crews. Based upon current natural gas and oil price expectations for 2005, we anticipate that our operating cash flow and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for 2005. However, future cash flows are subject to a number of variables, including the level of natural gas and oil production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

     Credit Facility. Our current bank line of credit provides a borrowing base of $200 million. This credit facility was entered into on February 4, 2004 and has a maturity of February 4, 2007. The credit facility was amended on September 1, 2004. The credit facility bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate, or LIBOR, plus applicable margins ranging from 1.25% to 3.75% or an alternate base rate, based upon the greater

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of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 2.25%. We pay commitment fees ranging from 0.375% to 0.50% of the unused borrowing base. The credit facility is secured by natural gas and oil properties representing at least 85% of the value of our proved reserves and the pledge of all of the stock of our subsidiaries. The borrowing base includes a $45 million portion, referred to as the “Tranche B” portion, that allows the borrowing base to be greater than the typical borrowing base that would have been computed based on proved natural gas and oil reserves. The Tranche B portion of the borrowing base terminates on November 30, 2005. At March 31, 2005, there were no amounts outstanding under our revolving credit facility. On December 15, 2004, upon the completion of our IPO, we repaid the then outstanding balance of $123 million. None of the outstanding borrowings at the time of repayment were under the Tranche B portion of the borrowing base. For information concerning the effect of changes in interest rates on interest payments under this facility, see below, Item 3. “Quantitative and Qualitative Disclosure About Market Risk — Interest Rate Risks”.

     The credit facility contains certain financial covenants, including a minimum current ratio and a minimum present value to total debt ratio. The credit facility also contains certain covenants that are based on what is defined in the credit facility as EBITDAX. The credit facility defines EBITDAX as our net income, subject to certain adjustments for the particular period plus the following expenses or charges to the extent deducted from net income during that period: interest, income taxes, depreciation, depletion, amortization, exploration and abandonment expenses and other similar non-cash charges and expenses, including stock based compensation and non-cash impairments of goodwill, minus all non-cash income added to net income, in each case, and without duplication, calculated after giving pro forma effect to acquisitions and dispositions during the period. These covenants require that our debt to EBITDAX ratio cannot exceed 4.0 to 1.0 until November 30, 2005 and 3.5 to 1.0 thereafter, and that our EBITDAX to interest ratio cannot be below 2.5 to 1.0. EBITDAX is not intended to represent net income (loss) as defined by generally accepted accounting principles in the United States, or GAAP, and such information should not be considered as an alternative to net income (loss), cash provided by operating activities or any other measure of performance prescribed by GAAP. We have complied with all financial covenants for all periods.

     The current ratio covenant states that our current ratio adjusted for the unused portion of the borrowing base and to eliminate certain non-cash assets and liabilities related to hedging activities must be greater than 1.0. We calculated the ratio for December 31, 2004 and March 31, 2005 to be 5.8 and 4.6, respectively.

     The ratio of present value of natural gas and oil properties to total debt covenant states that the defined present value divided by the outstanding debt under the bank line of credit must not be less than 1.5. This ratio is calculated every six months based on engineering estimates calculated at commodity prices and present value factors determined by the lenders. At December 31, 2004, we were in compliance with this covenant. At March 31, 2005, there were no amounts outstanding under the credit facility.

Critical Accounting Policies and Estimates

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

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Derivative Instruments and Hedging Activities

     We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas and oil production by reducing our exposure to price fluctuations. 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.

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

     As of March 31, 2005, the fair value of the derivative positions for our natural gas and oil swaps and natural gas collars for 2005 and 2006 production was $32.3 million and recorded on the balance sheet as a current liability of $24.5 million for the settlements expected to be paid within one year and other noncurrent liabilities of $7.8 million for the settlements expected to be paid later than one year. The deferred income tax effect on the $32.3 million fair value of derivatives at March 31, 2005 totaled $11.9 million, which is recorded in current and noncurrent deferred tax assets.

Income Taxes

     Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statement and income tax reporting. We have not recognized a valuation allowance against our net deferred taxes because we believe that it is more likely than not that the net deferred tax assets will be realized based on estimates of our future operating income.

Stock-based Compensation

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

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

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Dollar vested Management Stock and equity vested options are further subject to time vesting provisions. As of May 12, 2004, all Management Stock and options granted under the 2002 Option Plan were fully dollar and equity vested.

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

Acquisitions

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

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

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

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

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

     The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes

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in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

     Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. For the three months ended March 31, 2005, our income before income taxes would have changed by $528,000 for each $0.10 change in natural gas prices and $74,000 for each $1.00 change in crude oil prices.

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

     As of March 31, 2005, we had hedges in place for approximately 17 Bcf and 13 Bcf of natural gas production for 2005 and 2006, respectively, and approximately 256 thousand barrels (“MBbls”) of oil production for 2005 and 2006, respectively. These hedges are summarized in the table presented above under Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities”.

Price Swaps

     Through various price swaps, we have fixed the price we will receive on a portion of our natural gas and oil production in 2005. The table presented above under Item 2. “ Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities” provides the volumes associated with these various arrangements as of March 31, 2005.

     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.

Price Collars

     Through price collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas production in 2005 and 2006. The minimum, or floor, price we will receive in each of 2005 and 2006 is $4.75 and $5.00, respectively, per MMBtu Northwest Pipeline Corp. Rocky Mountain (“NORRM”) price and a $5.00 per MMBtu Colorado Interstate Gas Rocky Mountain price, and the maximum, or ceiling, price we will receive in each of 2005 and 2006 is $7.10 and $8.10 per MMBtu NORRM price, respectively. We have also fixed the minimum price we will receive on a portion of our oil production in 2005 and 2006 based on floors referencing a $45.00 and $42.00 per Bbl West Texas Intermediate (“WTI”) price, respectively, and the maximum price that we will receive is $55.25 and $50.20 WTI, respectively. The price collars also allow us to share in upward price movements up to the ceiling prices referenced in the contracts. The table presented above under Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities” provides the volumes and floor and ceiling prices associated with these various arrangements as of March 31, 2005.

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

Interest Rate Risks

     At March 31, 2005, we had no outstanding debt. Amounts drawn against our $200 million revolving credit facility will bear interest at floating rates as defined in the facility.

Item 4. Controls and Procedures

     In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2005 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

     There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 6. Exhibits and Reports on Form 8-K

Exhibits

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SIGNATURES

     Pursuant to the requirements 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.

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Exhibit Index