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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

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

For the quarterly period ended March 31, 2011

OR

 

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

For the transition period from              to             

Commission file number 001-32367

 

 

BILL BARRETT CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   80-0000545

(State or other jurisdiction of

incorporation or organization)

 

(IRS Employer

Identification No.)

 

1099 18th Street, Suite 2300

Denver, Colorado

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

(303) 293-9100

(Registrant’s telephone number, including area code)

 

 

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    x  Yes    ¨  No

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

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

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

There were 47,192,365 shares of $0.001 par value common stock outstanding on April 22, 2011.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

PART I. FINANCIAL INFORMATION

  

Item 1.

   Unaudited Financial Statements      3   

Item 2.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations      22   

Item 3.

   Quantitative and Qualitative Disclosures about Market Risk      35   

Item 4.

   Controls and Procedures      36   
PART II. OTHER INFORMATION   

Item 1.

   Legal Proceedings      37   

Item 1A.

   Risk Factors      37   

Item 2.

   Unregistered Sales of Equity Securities and Use of Proceeds      37   

Item 3.

   Defaults Upon Senior Securities      37   

Item 5.

   Other Information      37   

Item 6.

   Exhibits      38   
SIGNATURES      39   

 

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Table of Contents

PART I. FINANCIAL INFORMATION

 

ITEM 1. Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

 

     March 31, 2011     December 31, 2010  
     (in thousands, except share and per share data)  

Assets:

    

Current Assets:

    

Cash and cash equivalents

   $ 41,210      $ 58,690   

Accounts receivable, net of allowance for doubtful accounts of $831 for March 31, 2011 and $814 for December 31, 2010

     76,293        72,594   

Prepayments and other current assets

     7,444        11,444   

Derivative assets

     32,730        64,920   
                

Total current assets

     157,677        207,648   

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

    

Proved oil and gas properties

     2,870,744        2,752,981   

Unproved oil and gas properties, excluded from amortization

     279,092        274,282   

Furniture, equipment and other

     28,953        28,501   
                
     3,178,789        3,055,764   

Accumulated depreciation, depletion, amortization and impairment

     (1,307,440     (1,243,945
                

Total property and equipment, net

     1,871,349        1,811,819   

Deferred Financing Costs and Other Noncurrent Assets

     18,969        19,033   
                

Total

   $ 2,047,995      $ 2,038,500   
                

Liabilities and Stockholders’ Equity:

    

Current Liabilities:

    

Accounts payable and accrued liabilities

   $ 87,003      $ 83,981   

Amounts payable to oil and gas property owners

     18,899        19,803   

Production taxes payable

     39,776        38,410   

Derivative liabilities

     12,079        943   

Deferred income taxes

     8,962        22,820   
                

Total current liabilities

     166,719        165,957   

Note Payable to Bank

     0        0   

Senior Notes

     240,113        239,766   

Convertible Senior Notes

     166,131        164,633   

Asset Retirement Obligations

     53,274        52,270   

Deferred Income Taxes

     273,998        266,009   

Derivatives and Other Noncurrent Liabilities

     8,814        8,903   

Stockholders’ Equity:

    

Common stock, $0.001 par value; authorized 150,000,000 shares; 47,157,503 and 46,813,269 shares issued and outstanding at March 31, 2011 and December 31, 2010, respectively, with 880,124 and 891,453 shares subject to restrictions, respectively

     46        46   

Additional paid-in capital

     836,985        830,903   

Retained earnings

     277,399        262,184   

Treasury stock, at cost: zero shares at March 31, 2011 and December 31, 2010

     0        0   

Accumulated other comprehensive income

     24,516        47,829   
                

Total stockholders’ equity

     1,138,946        1,140,962   
                

Total

   $ 2,047,995      $ 2,038,500   
                

See notes to unaudited consolidated financial statements.

 

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Table of Contents

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

 

     Three Months Ended March 31,  
     2011     2010  
     (in thousands, except share and
per share data)
 

Operating and Other Revenues:

    

Oil and gas production

   $ 172,197      $ 163,649   

Commodity derivative loss

     (11,112     (5,664

Other

     238        (175
                

Total operating and other revenues

     161,323        157,810   

Operating Expenses:

    

Lease operating expense

     13,299        12,441   

Gathering, transportation and processing expense

     19,336        15,970   

Production tax expense

     8,566        8,289   

Exploration expense

     1,351        301   

Impairment, dry hole costs and abandonment expense

     283        2,879   

Depreciation, depletion and amortization

     65,394        56,534   

General and administrative expense

     17,696        13,776   
                

Total operating expenses

     125,925        110,190   
                

Operating Income

     35,398        47,620   

Other Income and Expense:

    

Interest and other income

     63        20   

Interest expense

     (12,042     (10,123
                

Total other income and expense

     (11,979     (10,103
                

Income before Income Taxes

     23,419        37,517   

Provision for Income Taxes

     8,204        13,540   
                

Net Income

   $ 15,215      $ 23,977   
                

Net Income Per Common Share, Basic

   $ 0.33      $ 0.53   
                

Net Income Per Common Share, Diluted

   $ 0.33      $ 0.53   
                

Weighted Average Common Shares Outstanding, Basic

     46,092,625        44,909,655   

Weighted Average Common Shares Outstanding, Diluted

     46,766,503        45,408,146   

See notes to unaudited consolidated financial statements.

 

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Table of Contents

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(UNAUDITED)

 

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

Equity
    Comprehensive
Income (Loss)
 
     (in thousands)  

Balance — December 31, 2009

   $ 45       $ 792,418      $ 181,682       $ 0      $ 54,410      $ 1,028,555     

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

     1         23,777        0         (3,685     0        20,093      $ 0   

APIC pool for excess tax benefits related to stock-based compensation

     0         (52     0         0        0        (52     0   

Stock-based compensation

     0         18,445        0         0        0        18,445        0   

Retirement of treasury stock

     0         (3,685     0         3,685        0        0        0   

Comprehensive income:

                

Net income

     0         0        80,502         0        0        80,502        80,502   

Effect of derivative financial instruments, net of $4,086 of taxes

     0         0        0         0        (6,581     (6,581     (6,581
                                                          

Total comprehensive income

                 $ 73,921   
                      

Balance — December 31, 2010

   $ 46       $ 830,903      $ 262,184       $ 0      $ 47,829      $ 1,140,962     

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

     0         4,452        0         (3,408     0        1,044      $ 0   

Stock-based compensation

     0         5,038        0         0        0        5,038        0   

Retirement of treasury stock

     0         (3,408     0         3,408        0        0        0   

Comprehensive loss:

                   0   

Net income

     0         0        15,215         0        0        15,215        15,215   

Effect of derivative financial instruments, net of $14,075 of taxes

     0         0        0         0        (23,313     (23,313     (23,313
                                                          

Total comprehensive loss

                 $ (8,098
                      

Balance — March 31, 2011

   $ 46       $ 836,985      $ 277,399       $ 0      $ 24,516      $ 1,138,946     
                                                    

See notes to unaudited consolidated financial statements.

 

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BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

 

     Three Months Ended March 31,  
     2011     2010  
     (in thousands)  

Operating Activities:

    

Net Income

   $ 15,215      $ 23,977   

Adjustments to reconcile to net cash provided by operations:

    

Depreciation, depletion and amortization

     65,394        56,534   

Deferred income taxes

     8,204        12,191   

Impairment, dry hole costs and abandonment expense

     283        2,879   

Unrealized derivative loss

     5,708        901   

Stock compensation and other non-cash charges

     5,091        4,255   

Amortization of debt discounts and deferred financing costs

     3,169        2,608   

Loss on sale of properties

     279        935   

Change in operating assets and liabilities:

    

Accounts receivable

     (3,699     (1,327

Prepayments and other assets

     3,929        (2,446

Accounts payable, accrued and other liabilities

     (16,324     (15,192

Amounts payable to oil and gas property owners

     (904     738   

Production taxes payable

     1,366        2,923   
                

Net cash provided by operating activities

     87,711        88,976   

Investing Activities:

    

Additions to oil and gas properties, including acquisitions

     (105,172     (91,145

Additions of furniture, equipment and other

     (720     (709

Proceeds from sale of properties and other investing activities

     (344     3,105   
                

Net cash used in investing activities

     (106,236     (88,749

Financing Activities:

    

Proceeds from credit facility

     0        20,000   

Principal payments on credit facility

     0        (10,000

Proceeds from stock option exercises

     4,353        1,494   

Deferred financing costs and other

     (3,308     (14,872
                

Net cash provided by (used in) financing activities

     1,045        (3,378
                

Decrease in Cash and Cash Equivalents

     (17,480     (3,151

Beginning Cash and Cash Equivalents

     58,690        54,405   
                

Ending Cash and Cash Equivalents

   $ 41,210      $ 51,254   
                

See notes to unaudited consolidated financial statements.

 

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Table of Contents

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

March 31, 2011

1. Organization

Bill Barrett Corporation (the “Company”), 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 in January 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 Unaudited Consolidated Financial Statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), they do not include all of the information and footnotes required by GAAP 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 the Company’s financial position as of March 31, 2011, the Company’s results of operations for the three months ended March 31, 2011 and 2010 and cash flows for the three months ended March 31, 2011 and 2010. Operating results for the three months ended March 31, 2011 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, natural production declines, timing of development and exploration activities, the uncertainty of exploration and development drilling results and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, the Unaudited Consolidated Financial Statements and the notes thereto should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 previously filed with the SEC.

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

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 Unaudited Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. The weighted average interest rates used to capitalize interest were 12.3% and 11.4% for the three months ended March 31, 2011 and 2010, which include interest and amortization of discounts and deferred financing fees on the Company’s Convertible Notes, its 9.875% Senior Notes due 2016 (“Senior Notes”) and its credit facility. The Company capitalized interest costs of $0.4 million and $1.3 million for the three months ended March 31, 2011 and 2010, 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.

Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive and are assigned proved reserves. 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. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage and other relevant matters. During the three months ended March 31, 2011 and 2010, the Company did not recognize any non-cash impairment charges related to its unproved oil and gas properties.

 

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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 DD&A, and non-cash impairments relating to the Company’s natural gas and oil producing activities:

 

     As of
March 31, 2011
    As of
December 31, 2010
 
     (in thousands)  

Proved properties

   $ 438,572      $ 437,741   

Wells and related equipment and facilities

     2,188,615        2,083,329   

Support equipment and facilities

     231,088        219,280   

Materials and supplies

     12,469        12,631   
                

Total proved oil and gas properties

     2,870,744        2,752,981   

Accumulated depreciation, depletion, amortization and impairment

     (1,293,813     (1,230,975
                

Total proved oil and gas properties, net

   $ 1,576,931      $ 1,522,006   
                

Unproved properties

   $ 175,909      $ 172,242   

Wells and facilities in progress

     103,183        102,040   
                

Total unproved oil and gas properties, excluded from amortization

   $ 279,092      $ 274,282   
                

Net changes in capitalized exploratory well costs for the three months ended March 31, 2011 are reflected in the following table (in thousands):

 

Beginning of period

   $ 9,041   

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

     3,910   

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

     (371

Exploratory well costs charged to dry hole costs and abandonment expense

     0   
        

End of period

   $ 12,580   
        

The following table presents costs of exploratory wells for which drilling has been completed for a period of greater than one year and which are included in unproved oil and gas properties as of March 31, 2011, pending determination of whether the wells will be assigned proved reserves:

 

     Time Elapsed Since Drilling Completed  
     1-2
Years
     3-5
Years
     Total  

Costs of wells for which drilling has been completed (in thousands)

   $ 827       $ 5,716       $ 6,543   

Number of wells for which drilling has been completed

     7         35         42   

As of March 31, 2011, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling were $6.5 million, all of which were related to coalbed methane wells located in the Powder River Basin. These wells were drilled into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting up to 36 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.

Management believes these wells with suspended exploratory drilling costs have the potential for sufficient quantities of hydrocarbons to justify their development and is actively pursuing efforts to assess whether reserves can be attributed to their respective areas. If additional information becomes available that raises substantial doubt regarding the economic or operational viability of any of these wells, the associated costs will be expensed.

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

 

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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. During the three months ended March 31, 2011 and 2010, the Company did not recognize any non-cash impairment charges related to its proved oil and gas properties.

The provision for 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.

Accounts Payable and Accrued Liabilities. Accounts payable and accrued expenses are comprised of the following (in thousands):

 

     March 31,
2011
     December 31,
2010
 

Accrued drilling and facility costs

   $ 53,306       $ 39,912   

Accrued lease operating, gathering, transportation and processing expenses

     19,556         15,610   

Accrued general and administrative expenses

     5,528         9,020   

Trade payables and other

     8,613         19,439   
                 

Total accounts payable and accrued liabilities

   $ 87,003       $ 83,981   
                 

New Accounting Pronouncements. In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-06, Improving Disclosures about Fair Value Measurements, which amended Accounting Standards Codification (“ASC”) 820, Fair Value Measurements and Disclosures. The intent of this update was to improve disclosure requirements related to fair value measurements and disclosures. New disclosures were required regarding transfers in and out of Levels 1 and 2 and activity within Level 3 fair value measurements, as well as clarification of existing disclosures regarding the level of disaggregation of derivative contracts and disclosures about fair value measurement inputs and valuation techniques. The guidance was effective for interim and annual periods beginning after December 15, 2009, except for the Level 3 reconciliation disclosures, which were effective for interim and annual periods beginning after December 15, 2010. The Company adopted the provisions for the quarter ended March 31, 2010, except for the Level 3 reconciliation disclosures, which were adopted for the quarter ended March 31, 2011. The adoption of these disclosure requirements did not have a material impact on the Company’s financial statements.

3. 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 number of common shares outstanding during each period. Nonvested equity shares of common stock are included in the computation of basic net income per share only after the shares become fully vested. Diluted net income per share of common stock is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income 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, did not impact the diluted net income per share calculation for the three months ended March 31, 2011 and 2010. The diluted net income per share excludes the anti-dilutive effect of 192,835 and 338,320 shares of stock options and nonvested performance-based equity shares of common stock for the three months ended March 31, 2011 and 2010, respectively.

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

 

     Three Months Ended March 31,  
     2011      2010  

Net income

   $ 15,215       $ 23,977   

Basic weighted-average common shares outstanding in period

     46,093         44,910   

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

     674         498   
                 

Diluted weighted-average common shares outstanding in period

     46,767         45,408   
                 

Basic net income per common share

   $ 0.33       $ 0.53   
                 

Diluted net income per common share

   $ 0.33       $ 0.53   
                 

4. Supplemental Disclosures of Cash Flow Information

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

 

     Three Months Ended March 31,  
     2011     2010  

Cash paid for interest, net of amount capitalized

   $ 16,361      $ 16,856   

Cash paid for income taxes, net of refunds received

     (7,503     1,764   

Supplemental disclosures of non-cash investing and financing activities:

    

Current liabilities that are reflected in investing activities

     58,223        45,422   

Net increase (decrease) in asset retirement obligations

     848        (1,058

Treasury stock acquired from employee stock option exercises

     100        35   

Retirement of treasury stock

     (3,408     (3,383

 

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5. Dispositions and Property Held for Sale

At December 31, 2009, the Company had properties held for sale in its North Hill Creek field located in the Uinta Basin. In March 2010, the Company completed the sale of these properties. The Company received $3.1 million in cash proceeds and recognized a $0.9 million pre-tax loss, which is included in other operating revenues in the Unaudited Consolidated Statements of Operations for the three months ended March 31, 2010.

6. Long-Term Debt

The Company’s outstanding debt is summarized below (in thousands):

 

          As of March 31, 2011      As of December 31, 2010  
     

Maturity Date

   Principal      Unamortized
Discount
    Carrying
Amount
     Principal      Unamortized
Discount
    Carrying
Amount
 

Credit Facility

   April 1, 2014    $ 0       $ 0      $ 0       $ 0       $ 0      $ 0   

Senior Notes (1)

   July 15, 2016      250,000         (9,887     240,113         250,000         (10,234     239,766   

Convertible Notes (2)

   March 15, 2028 (3)      172,500         (6,369     166,131         172,500         (7,867     164,633   

 

(1) The aggregate estimated fair value of the Senior Notes was approximately $281.3 million as of March 31, 2011 based on quoted market trades of these instruments.
(2) The aggregate fair value of the Convertible Notes was approximately $177.2 million as of March 31, 2011. Because there is no active, public market for the Convertible Notes, the fair value was based on market-based parameters of the various components of the Convertible Notes and over-the-counter trades.
(3) The Company currently expects that the holders will put the Convertible Notes to the Company in March 2012. The Company also has the option to call the Convertible Notes anytime thereafter.

Revolving Credit Facility

On March 16, 2010, the Company amended its credit facility (the “Amended Credit Facility”) and extended the maturity date to April 1, 2014. 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 2.0% to 3.0% or an alternate base rate (“ABR”), based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.0%, plus applicable margins ranging from 1.0% to 2.0%. The borrowing base is required to be redetermined twice per year. On March 25, 2011, the borrowing base was reaffirmed at $800.0 million with commitments from 19 lenders of $700.0 million, based on December 31, 2010 reserves and hedge position. The Company pays annual commitment fees of 0.5% of the unused amount of the commitments. 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 currently is in compliance with all financial covenants and has complied with all financial covenants for all prior periods.

As of March 31, 2011, the Company did not have a balance outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility, effective May 4, 2010, which reduced the borrowing capacity of the Amended Credit Facility by $26.0 million to $674.0 million.

5% Convertible Senior Notes due 2028

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, including the Senior Notes. Interest is payable semi-annually in arrears on March 15 and September 15 of each year. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility.

 

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9.875% Senior Notes Due 2016

The Senior Notes, which were issued on July 8, 2009, are senior unsecured obligations of the Company and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the Company’s Convertible Notes. Interest is payable in arrears semi-annually on January 15 and July 15 each year. The Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility and the Convertible Notes. The Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, pay dividends, make restricted payments, create liens and sell assets. The Company is currently in compliance with all financial covenants and has complied with all financial covenants for all prior periods.

The following table summarizes the cash portion of interest expense related to the Amended Credit Facility, Convertible Notes and Senior Notes along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense (in thousands):

 

     Three Months Ended March 31,  
     2011      2010  

Amended Credit Facility (1)

  

Cash interest

   $ 981       $ 449   

Non-cash interest

   $ 780       $ 405   

Senior Notes (2)

  

Cash interest

   $ 6,172       $ 6,172   

Non-cash interest

   $ 608       $ 551   

Convertible Notes (3)

     

Cash interest

   $ 2,156       $ 2,156   

Non-cash interest

   $ 1,783       $ 1,652   

 

(1) Cash interest includes amounts related to interest and commitment fees paid on the line of credit and participation and fronting fees paid on the letter of credit.
(2) The stated interest rate for the Senior Notes is 9.875% per annum with an effective interest rate of 11.3% per annum.
(3) The stated interest rate for the Convertible Notes is 5% per annum with an effective interest rate of 9.7% per annum. The effective interest rate of the Convertible Notes includes amortization of the debt discount, which represents the fair value of the equity conversion feature at the time of issue.

7. 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 Unaudited 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 Unaudited Consolidated Statements of Operations.

A reconciliation of the Company’s asset retirement obligations for the three months ended March 31, 2011 is as follows (in thousands):

 

Beginning of period

   $ 53,079   

Liabilities incurred

     848   

Liabilities settled

     (96

Accretion expense

     937   

Revisions to estimate

     0   
        

End of period

   $ 54,768   

Less: current asset retirement obligations

     1,494   
        

Long-term asset retirement obligations

   $ 53,274   
        

 

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8. Fair Value Measurements

Assets and Liabilities Measured on a Recurring Basis

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 approximates its fair value due to its floating rate structure. However, the balance of the Amended Credit Facility was zero as of March 31, 2011. The Company’s other financial and non-financial assets and liabilities that are measured on a recurring basis are measured and reported at fair value.

The following tables sets forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities as of March 31, 2011 and December 31, 2010 that were measured at fair value on a recurring basis. Assets and 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.

As of March 31, 2011

 

     Level 1      Level 2     Level 3      Total  
     (in thousands)  

Assets

          

Deferred Compensation Plan

   $ 323      $ 0      $ 0      $ 323   

Commodity Derivatives

     0        55,531        0        55,531   

Liabilities

          

Commodity Derivatives

   $ 0      $ (42,235   $ 0      $ (42,235

As of December 31, 2010

 

     Level 1      Level 2     Level 3      Total  
     (in thousands)  

Assets

          

Deferred Compensation Plan

   $ 260      $ 0      $ 0      $ 260   

Commodity Derivatives

     0        81,685        0        81,685   

Liabilities

          

Commodity Derivatives

   $ 0      $ (25,294   $ 0      $ (25,294

All fair values reflected in the table above and on the Unaudited 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. In addition, the fair value measurement of a liability has been adjusted to 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.

Level 1 Fair Value Measurements – The Company maintains a non-qualified deferred compensation plan (as discussed in more detail in Note 13) which allows certain management employees to defer receipt of a portion of their compensation. The Company maintains assets for the deferred compensation plan in a rabbi trust. The assets of the rabbi trust are invested in publicly traded mutual funds and are recorded in other current and other long-term assets on the Unaudited Consolidated Balance Sheets. These financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs.

Level 2 Fair Value Measurements - The fair value of the natural gas and crude oil forwards and options are estimated using a combined income and market valuation methodology with a mid-market pricing convention based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. The Company did not make any adjustments to the obtained curves. The pricing services publish observable market information from multiple brokers and exchanges. No proprietary models are used by the pricing services for the inputs. The Company utilized the counterparties’ valuations to assess the reasonableness of the Company’s valuations.

Level 3 Fair Value Measurements - As of March 31, 2011, and for the three months ended March 31, 2011, the Company did not have assets or liabilities measured under a Level 3 fair value hierarchy.

 

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Assets and Liabilities Measured on a Non-Recurring Basis

The Company utilizes fair value on a non-recurring basis to perform impairment tests as required on its property and equipment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3. Additionally, the Company uses fair value to determine the inception value of its asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition and would generally be classified within Level 3.

9. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap and collar contracts to fix the floor and ceiling prices related to the sale of a portion of the Company’s production. The Company does not enter into derivative instruments for speculative or trading purposes.

In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sale 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 sale exception as mentioned above, are recorded at fair market value and included in the Unaudited Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative instruments in the Unaudited Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010:

 

     March 31, 2011     December 31, 2010  
     (in thousands)  

Derivatives Designated as Cash Flow Hedging Instruments

Assets:

    

Current: Derivative assets

   $ 43,804      $ 80,460   

Current: Derivative liability (1)

     10,749        0   

Derivatives and other noncurrent liabilities (1)(3)

     961        1,166   

Liabilities:

    

Current: Derivative assets (2)

     (6,206     (2,172

Current: Derivative liability

     (7,535     (943

Derivatives and other noncurrent liabilities (3)

     (3,411     (2,925
                

Total derivatives designated as cash flow hedging instruments

   $ 38,362      $ 75,586   
                

Derivatives Not Designated as Cash Flow Hedging Instruments

Assets:

    

Current: Derivative assets

   $ 4      $ 59   

Current: Derivative liability (1)

     13        0   

Liabilities:

    

Current: Derivative assets (2)

     (4,872     (13,427

Current: Derivative liability

     (15,306     0   

Derivatives and other noncurrent liabilities (3)

     (4,905     (5,827
                

Total derivatives not designated as cash flow hedging instruments

   $ (25,066   $ (19,195
                

Total Derivatives

   $ 13,296      $ 56,391   
                

 

(1) Amounts are netted against derivative liability balances with the same counterparty, and, therefore, are presented as a net liability on the Unaudited Consolidated Balance Sheets.
(2) Amounts are netted against derivative asset balances with the same counterparty, and, therefore, are presented as a net asset on the Unaudited Consolidated Balance Sheets.
(3) As of March 31, 2011 and December 31, 2010, this line item on the Unaudited Consolidated Balance Sheets also includes $1.5 million and $1.3 million, respectively, of other noncurrent liabilities.

 

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For derivative instruments that qualify and are designated as cash flow hedges, changes in fair value, to the extent the hedges are effective, are recognized in accumulated other comprehensive income (“AOCI”) until the forecasted transaction occurs. The Company will reclassify the appropriate cash flow hedge amounts from AOCI to oil and gas production revenues in the Unaudited Consolidated Statements of Operations as the hedged production quantity is sold. Based on projected market prices as of March 31, 2011, the amount to be reclassified from AOCI to net income in the next 12 months would be an after-tax net gain of approximately $23.1 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. 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 loss in the Unaudited Consolidated Statements of Operations. The following table summarizes the cash flow hedge gains and losses and their locations on the Unaudited Consolidated Balance Sheet and the Unaudited Consolidated Statement of Operations for the periods indicated:

 

    

Derivatives Qualifying

as Cash Flow Hedges

   Three Months Ended March 31,  
      2011     2010  
          (in thousands)  

Amount of Gain (Loss) Recognized in AOCI (net of tax)

   Commodity Hedges      (5,862     62,305   

Amount of Gain Reclassified from AOCI into Income (net of tax)

   Commodity Hedges(1)      17,451        13,129   

Amount of Gain Recognized in Income on Ineffective Hedges

   Commodity Hedges(1)      163        393   

 

(1) Gains and losses reclassified from AOCI into income as well as gains and losses on ineffective hedges are located in the Oil and Gas Production Revenues and the Commodity Derivative Loss line items, respectively, in the Unaudited Consolidated Statements of Operations.

During the derivative’s term, if the Company determines that the hedge is no longer effective or necessary, hedge accounting is prospectively discontinued. All subsequent changes in the derivative’s fair value are recorded in earnings, and all accumulated gains and losses, based on the effective portion of the derivative at that date, recorded in AOCI will remain in AOCI and are reclassified to earnings when the underlying transaction occurs. If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time period, the hedging instrument loses cash flow hedge accounting treatment, and all subsequent mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in AOCI related to the hedging instrument are also reclassified to earnings.

Some of the Company’s commodity derivative instruments do not qualify or are not designated as cash flow hedges but are, to a degree, an economic offset to the Company’s commodity price exposure. If a commodity derivative instrument does not qualify or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative loss in the Unaudited 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 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 loss in the Unaudited Consolidated Statements of Operations and are reflected in cash flows from operations on the Unaudited Consolidated Statements of Cash Flows.

In addition to the swaps and collars discussed above, the Company has entered into basis only swaps. Basis only swaps hedge the difference between the New York Mercantile Exchange (“NYMEX”) gas price and the price received for the Company’s natural gas production at a specific delivery location. Although the Company believes that this is an appropriate part of a mitigation strategy, the basis only swaps do not qualify for hedge accounting because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments are recorded in earnings and recognized in commodity derivative loss in the Unaudited Consolidated Statements of Operations. The Company has also entered into swap contracts to hedge the amount received related to natural gas liquids (“NGLs”) resulting from the processing of its natural gas. The NGL hedges were not designated as cash flow hedges and the changes in fair value of these derivative instruments were recorded in earnings.

 

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The following table summarizes the location and amounts of gains and losses on derivative instruments that do not qualify for hedge accounting for the period indicated:

 

    

Location of Loss Recognized in

Income on Derivatives

   Three Months Ended March 31,  
      2011     2010  
          (in thousands)  

Amount of Loss Recognized in Income on Derivatives

   Commodity Derivative Loss    $ (11,275   $ (6,057

As of March 31, 2011, the Company had financial instruments in place to hedge the following volumes for the periods indicated:

 

     April  – December
2011
     For the year
2012
     For the  year
2013
     For the  year
2014
 

Oil (Bbls)

     770,000         475,800         109,500         73,000   

Natural Gas (MMbtu)

     40,262,500         26,990,000         0         0   

Natural Gas Basis (MMbtu)

     5,500,000         7,320,000         0         0   

Natural Gas Liquids (Gallons)

     52,050,000         13,200,000         0         0   

The Company recognized a net increase in natural gas production revenues related to these contracts of $23.3 million and $15.9 million in the three months ended March 31, 2011 and 2010, respectively. The Company was also a party to various swap and collar contracts for oil, recognizing a decrease to oil production revenues related to these contracts of $0.8 million for the three months ended March 31, 2011 and an increase of $0.3 million in the three months ended March 31, 2010.

The table below summarizes the realized and unrealized gains and losses the Company recognized in the Unaudited Consolidated Statements of Operations related to its commodity derivative instruments for the periods indicated (in thousands):

 

     Three Months Ended March 31,  
     2011     2010  

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

   $ 27,922      $ 21,008   
                

Realized loss on derivatives not designated as cash flow hedges (2)

   $ (5,404   $ (4,763

Unrealized ineffectiveness gain recognized on derivatives designated as cash flow hedges (2)

     163        393   

Unrealized loss on derivatives not designated as cash flow hedges (2)

     (5,871     (1,294
                

Total commodity derivative loss

   $ (11,112   $ (5,664
                

 

(1) Included in “oil and gas production” revenues in the Unaudited Consolidated Statements of Operations.
(2) Included in “commodity derivative loss” in the Unaudited Consolidated Statements of Operations.

Derivative financial instruments that hedge the price of oil and gas are generally executed with major financial or commodities trading institutions that 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 12 different counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, 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.

It is the Company’s policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. The Company’s derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”) or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions with its lenders (or affiliates of lenders) that, in the event of counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty or its affiliated lender under the Amended Credit Facility or other general obligations against monies owed for derivative contracts.

 

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10. Income Taxes

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return in accordance with the FASB’s rules on income taxes. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on technical merits. During the three months ended March 31, 2011, there was no change to the Company’s liability for uncertain tax positions.

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. The Company did not record any accrued interest or penalties associated with unrecognized tax benefits during the three months ended March 31, 2011.

Income tax expense for the three months ended March 31, 2011 and 2010 differs from the amounts that would be provided by applying the U.S. federal income tax rate to income before income taxes principally due to the effect of state income taxes, stock-based compensation and other operating expenses not deductible for income tax purposes.

11. Stockholders’ Equity

The Company’s authorized capital structure 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. The remainder of the authorized preferred stock is undesignated. There are no issued and outstanding shares of preferred stock.

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.

The Company may occasionally acquire treasury stock, which is recorded at cost, in connection with the vesting and exercise of stock-based awards or for other reasons. As of March 31, 2011, all treasury stock held by the Company was retired.

12. Accumulated Other Comprehensive Income

The components of AOCI and related tax effects for the three months ended March 31, 2011 were as follows:

 

     Gross     Tax
Effect
    Net of
Tax
 
     (in thousands)  

Accumulated other comprehensive income—December 31, 2010

   $ 76,613      $ (28,784   $ 47,829   

Unrealized change in fair value of cash flow hedges

     (9,466     3,604        (5,862

Reclassification adjustment for realized gains on hedges included in net income

     (27,922     10,471        (17,451
                        

Accumulated other comprehensive income—March 31, 2011

   $ 39,225      $ (14,709   $ 24,516   
                        

13. Equity Incentive Compensation Plans and Other Employee Benefits

The Company maintains various stock-based compensation plans and other employee benefits as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period).

The following table presents the non-cash stock-based compensation related to equity awards for the three months ended March 31, 2011 and 2010 (in thousands):

 

     Three Months Ended March 31,  
     2011      2010  

Common stock options

   $ 2,168       $ 2,024   

Nonvested equity shares

     2,060         1,698   

Nonvested performance-based equity shares

     174         182   

Market performance-based equity shares

     190         73   
                 

Total non-cash stock-based compensation

   $ 4,592       $ 3,977   
                 

Unrecognized compensation cost as of March 31, 2011 was $35.6 million related to grants of nonvested stock options and nonvested equity shares of common stock that are expected to be recognized over a weighted-average period of 2.9 years. This amount includes $1.3 million related to the market-based nonvested equity shares that is expected to be recognized ratably through February 2014.

 

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Stock Options and Nonvested Equity Shares. The following tables present the equity awards granted pursuant to the Company’s various stock compensation plans:

 

     Three Months Ended March 31, 2011  
     Number
of options
     Weighted Average
Price Per Share
 

Options to purchase shares of common stock

     247,824       $ 39.02   
     Three Months Ended March 31, 2011  
     Number
of shares
     Weighted Average
Grant Date Fair Value
 

Nonvested equity shares

     287,602       $ 38.99   

Nonvested performance-based equity shares

     4,922       $ 39.88   

Market performance-based equity shares

     1,038       $ 39.88   
           

Total shares granted

     293,562      
           

Performance Share Program. In February 2010, the Compensation Committee of the Board of Directors of the Company approved a new performance share program (the “2010 Program”) pursuant to the Company’s 2008 Stock Incentive Plan (the “2008 Incentive Plan”). A total of 325,000 shares under the 2008 Incentive Plan were set aside for this program. The vesting of these awards is contingent upon meeting various Company-wide performance goals. Upon commencement of the 2010 Program and during each subsequent year of the 2010 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 of up to four years, depending on the level at which the performance goals are achieved. Each year for four years, it is possible for up to 50% of the shares to vest based on the achievement of the performance goals. Twenty-five percent of the total grant will vest if each of the independent metrics are met at the target level, and an additional 25% of the total grant will vest if each of the independent metrics are 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 had not vested were to be forfeited.

For the year ended December 31, 2010, the performance goals consisted of finding and development costs per Mcfe (weighted at 37.5%), combined lease operating expenses and general and administrative expenses (weighted at 25%) and production growth (weighted at 37.5%). Based on the Company’s performance with respect to those metrics during the year ended December 31, 2010 and the Compensation Committee’s approval in February 2011, 25.9% of the total grant vested in February 2011. The Company recorded the remaining non-cash stock-based compensation cost associated with these shares of $0.2 million for the three months ended March 31, 2011, for the remaining time vesting requirement through the February 2011 vest date.

As new goals are established each year for the performance-based awards, 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 an estimate of the extent to which the performance goals would be met. If such goals are not met, no compensation cost is recognized and any previously recognized compensation cost is reversed.

On March 30, 2011, the Compensation Committee approved the performance metrics for vesting of the performance shares based on 2011 performance. For the year ending December 31, 2011, the performance goals consisted of annual production growth (weighted at 25%), increases to our natural gas and oil proved reserves (weighted at 25%), finding and development costs (weighted at 25%) and increases to the Company’s present value (at a 10% annual discount) of future net cash flows from proved reserves (weighted at 25%). For the three months ended March 31, 2011, the remaining unvested performance shares that were granted in 2010, along with 4,922 newly granted performance-based nonvested equity shares of common stock, were subject to the new grant date and the fair value was remeasured at $39.88 per share. Of those performance-based nonvested equity shares, 136,534 could potentially vest if all performance goals are met at the stretch level. Based upon the new grant date of March 30, 2011 for these shares, the non-cash stock-based compensation expense recognized for the remainder of the three months ended March 31, 2011 was minimal.

 

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During the three months ended March 31, 2011, the Compensation Committee also modified the vesting terms of the Company’s nonvested equity awards that are subject to a market performance-based vesting condition, which is based on the Company’s total stockholder return (“TSR”) ranking relative to a defined peer group’s individual TSRs. The remeasured aggregate fair value of the market-based awards was $1.3 million based on a per-unit fair value of $39.88 on the new grant date. The fair value of the market-based awards is amortized ratably over the remaining three year requisite service period. All compensation expense related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. The Company recognized $0.2 million of compensation expense attributable to these awards for the three months ended March 31, 2011.

Director Fees. The Company’s non-employee, or outside, 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 to receive shares of the Company’s common stock for payment of the director fees. The following table summarizes common stock issued as payment for directors’ fees and the amount of non-cash stock-based compensation cost recognized associated with the issuance of those shares:

 

     Three Months Ended March 31,  
     2011      2010  

Director fees (shares)

     2,791         2,303   

Stock-based compensation (in thousands)

   $ 111       $ 71   

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 and employees can immediately sell the portion of the match made with the Company’s common stock. The Company made matching cash and common stock contributions of $0.7 million and $0.6 million for the three months ended March 31, 2011 and 2010, respectively.

Deferred Compensation Plan. In 2010, the Company adopted a non-qualified deferred compensation plan for certain employees and officers whose eligibility to participate in the plan was determined by the Compensation Committee of the Company’s Board of Directors. The Company makes cash matching contributions on behalf of eligible employees up to 6% of the employee’s cash compensation once the contribution limits are reached on the Company’s 401(k) Plan. All amounts deferred and matched under the plan vest immediately.

Participants earn a return on their deferred compensation based on investment earnings of participant-selected mutual funds. Participants’ deferred compensation amounts are not directly invested in these investment vehicles; however, the Company tracks the performance of each participant’s investment selections and adjusts the deferred compensation liability accordingly. Changes in the market value of the participants’ investment selections are recorded as an adjustment to deferred compensation liabilities, with an offset to compensation expense included within general and administrative expenses in the Unaudited Consolidated Statements of Operations. Deferred compensation, including accumulated earnings on the participant-directed investment selections, is distributable in cash at participant-specified dates or upon retirement, death, disability, change in control or termination of employment.

The table below summarizes the activity in the plan during the year ended December 31, 2010 and three months ended March 31, 2011 and the Company’s ending deferred compensation liability as of March 31, 2011 (in thousands):

 

Beginning deferred compensation liability balance – January 1, 2010

   $ 0   

Employee contributions

     145   

Company matching contributions

     104   

Participant earnings

     11   
        

Ending deferred compensation liability balance – December 31, 2010

   $ 260   
        

Employee contributions

     46   

Company matching contributions

     44   

Distributions

     (35

Participant earnings

     8   
        

Ending deferred compensation liability balance – March 31, 2011

   $ 323   
        

Amount to be paid within one year

   $ 0   

Remaining balance to be paid beyond one year

   $ 323   

 

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The Company is not obligated to contemporaneously fund the liability. It has, however, established a rabbi trust to offset the deferred compensation liability and protect the interest of the plan participants. The trust assets are invested in publicly-traded mutual funds. The investments in the rabbi trust seek to offset the change in the value of the related liability. As a result, there is no expected impact on earnings or earnings per share from the changes in market value of the investment assets because the changes in market value of the trust assets are offset by changes in the value of the deferred compensation plan liability. The gains and losses from changes in fair value of the investments are included in interest and other income in the Unaudited Consolidated Statements of Operations.

The following table represents the Company’s activity in the investment assets held in the rabbi trust during the three months ended March 31, 2011 (in thousands):

 

Beginning investment balance – January 1, 2010

   $ 0   

Investment purchases

     249   

Earnings

     11   
        

Ending investment balance – December 31, 2010

   $ 260   
        

Investment purchases

     90   

Distributions

     (35

Earnings

     8   
        

Ending investment balance – March 31, 2011

   $ 323   
        

14. Guarantor Subsidiaries

The Senior Notes, as well as the Convertible Notes, are jointly and severally guaranteed on a full and unconditional basis by the Company’s 100% owned subsidiaries (“Guarantor Subsidiaries”). Presented below are the Company’s condensed consolidating balance sheets, statements of income and statements of cash flows, as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.

The following condensed consolidating financial statements have been prepared from the Company’s financial information on the same basis of accounting as the Unaudited Consolidated Financial Statements. Investments in the subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Company and the Guarantor Subsidiaries are reflected in the Intercompany Eliminations column.

Condensed Consolidating Balance Sheets

 

     March 31, 2011  
     (in thousands)  
     Parent
Issuer
    Guarantor
Subsidiaries
    Intercompany
Eliminations
     Consolidated  

Assets:

         

Current assets

   $ 156,977      $ 700      $ 0       $ 157,677   

Property and equipment, net

     1,789,813        81,536        0         1,871,349   

Intercompany receivable (payable)

     64,334        (64,334     0         0   

Investment in subsidiaries

     (8,446     0        8,446         0   

Noncurrent assets

     18,969        0        0         18,969   
                                 

Total assets

   $ 2,021,647      $ 17,902      $ 8,446       $ 2,047,995   
                                 

Liabilities and Stockholders’ Equity:

         

Current liabilities

   $ 166,033      $ 686      $ 0       $ 166,719   

Long-term debt

     406,244        0        0         406,244   

Deferred income taxes

     249,094        24,904        0         273,998   

Other noncurrent liabilities

     61,330        758        0         62,088   

Stockholders’ equity

     1,138,946        (8,446     8,446         1,138,946   
                                 

Total liabilities and stockholders’ equity

   $ 2,021,647      $ 17,902      $ 8,446       $ 2,047,995   
                                 

 

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     December 31, 2010  
     (in thousands)  
     Parent
Issuer
    Guarantor
Subsidiaries
    Intercompany
Eliminations
     Consolidated  

Assets:

         

Current assets

   $ 206,987      $ 661      $ 0       $ 207,648   

Property and equipment, net

     1,727,872        83,947        0         1,811,819   

Intercompany receivable (payable)

     65,662        (65,662     0         0   

Investment in subsidiaries

     (7,474     0        7,474         0   

Noncurrent assets

     19,033        0        0         19,033   
                                 

Total assets

   $ 2,012,080      $ 18,946      $ 7,474       $ 2,038,500   
                                 

Liabilities and Stockholders’ Equity:

         

Current liabilities

   $ 165,166      $ 791      $ 0       $ 165,957   

Long-term debt

     404,399        0        0         404,399   

Deferred income taxes

     241,105        24,904        0         266,009   

Other noncurrent liabilities

     60,448        725        0         61,173   

Stockholders’ equity

     1,140,962        (7,474     7,474         1,140,962   
                                 

Total liabilities and stockholders’ equity

   $ 2,012,080      $ 18,946      $ 7,474       $ 2,038,500   
                                 

Condensed Consolidating Statements of Operations

 

     Three Months Ended March 31, 2011  
     (in thousands)  
     Parent
Issuer
    Guarantor
Subsidiaries
    Intercompany
Eliminations
     Consolidated  

Operating and other revenues

   $ 158,745      $ 2,578      $ 0       $ 161,323   

Operating expenses

     104,679        3,550        0         108,229   

General and administrative

     17,696        0        0         17,696   

Interest and other income (expense)

     (11,979     0        0         (11,979
                                 

Income (loss) before income taxes and equity in earnings (loss) of subsidiaries

     24,391        (972     0         23,419   

Provision for income taxes

     8,204        0        0         8,204   

Equity in earnings (loss) of subsidiaries

     (972     0        972         0   
                                 

Net income (loss)

   $ 15,215      $ (972   $ 972       $ 15,215   
                                 

 

     Three Months Ended March 31, 2010  
     (in thousands)  
     Parent
Issuer
    Guarantor
Subsidiaries
    Intercompany
Eliminations
     Consolidated  

Operating and other revenues

   $ 154,313      $ 3,497      $ 0       $ 157,810   

Operating expenses

     92,515        3,899        0         96,414   

General and administrative

     13,776        0        0         13,776   

Interest and other income (expense)

     (10,103     0        0         (10,103
                                 

Income (loss) before income taxes and equity in earnings (loss) of subsidiaries

     37,919        (402     0         37,517   

Provision for income taxes

     13,540        0        0         13,540   

Equity in earnings (loss) of subsidiaries

     (402     0        402         0   
                                 

Net income (loss)

   $ 23,977      $ (402   $ 402       $ 23,977   
                                 

 

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Condensed Consolidating Statements of Cash Flows

 

     Three Months Ended March 31, 2011  
     (in thousands)  
     Parent
Issuer
    Guarantor
Subsidiaries
    Intercompany
Eliminations
     Consolidated  

Cash flows from operating activities

   $ 86,701      $ 1,010      $ 0       $ 87,711   

Cash flows from investing activities:

         

Additions to oil and gas properties, including acquisitions

     (105,141     (31     0         (105,172

Additions to furniture, fixtures and other

     (371     (349     0         (720

Proceeds from sale of properties and other investing activities

     (344     0        0         (344

Cash flows from financing activities:

         

Intercompany transfers

     630        (630     0         0   

Other financing activities

     1,045        0        0         1,045   
                                 

Change in cash and cash equivalents

     (17,480     0        0         (17,480

Beginning cash and cash equivalents

     58,690        0        0         58,690   
                                 

Ending cash and cash equivalents

   $ 41,210      $ 0      $ 0       $ 41,210   
                                 

 

     Three Months Ended March 31, 2010  
     (in thousands)  
     Parent
Issuer
    Guarantor
Subsidiaries
    Intercompany
Eliminations
     Consolidated  

Cash flows from operating activities

   $ 87,693      $ 1,283      $ 0       $ 88,976   

Cash flows from investing activities:

         

Additions to oil and gas properties, including acquisitions

     (90,684     (461     0         (91,145

Additions to furniture, fixtures and other

     (420     (289     0         (709

Proceeds from sale of properties and other investing activities

     3,105        0        0         3,105   

Cash flows from financing activities:

         

Proceeds from debt

     20,000        0        0         20,000   

Principal payments on debt

     (10,000     0        0         (10,000

Intercompany transfers

     533        (533     0         0   

Other financing activities

     (13,378     0        0         (13,378
                                 

Change in cash and cash equivalents

     (3,151     0        0         (3,151

Beginning cash and cash equivalents

     54,405        0        0         54,405   
                                 

Ending cash and cash equivalents

   $ 51,254      $ 0      $ 0       $ 51,254   
                                 

 

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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, the following risks and uncertainties:

 

   

volatility of market prices received for natural gas, natural gas liquids (“NGLs”) and oil;

 

   

regulatory approvals;

 

   

legislative or regulatory changes;

 

   

economic and competitive conditions;

 

   

debt and equity market conditions;

 

   

derivative activities;

 

   

exploration risks such as drilling unsuccessful wells;

 

   

the ability to obtain industry partners for our prospects on favorable terms to reduce our capital risks and accelerate our exploration activities;

 

   

availability of third party facilities for gathering, processing, refining and transportation;

 

   

future processing volumes and pipeline throughput;

 

   

reductions in the borrowing base under our Amended Credit Facility;

 

   

the potential for production decline rates from our wells to be greater than we expect;

 

   

changes in estimates of proved reserves;

 

   

potential failure to achieve expected production from existing and future exploration or development projects;

 

   

declines in the values of our natural gas and oil properties resulting in impairments;

 

   

capital expenditures and other contractual obligations;

 

   

liabilities resulting from litigation concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, or other matters that may not be covered by an effective indemnity or insurance;

 

   

higher than expected costs and expenses including production, drilling and well equipment costs;

 

   

occurrence of property acquisitions or divestitures;

 

   

ability to obtain adequate pipeline transportation capacity for our production;

 

   

changes in tax rates; 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, 2010 under the “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” sections and in Item 1A, “Risk Factors” of this Quarterly Report on Form 10-Q, all of which are difficult to predict.

In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Readers should not place undue reliance on these forward-looking statements, which reflect management’s views only as of the date hereof. Other than as required under the securities laws, we do not undertake any obligation to publicly correct or update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.

Overview

Bill Barrett Corporation (“we,” “our” or “us”) explores for and develops oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value through profitable growth in reserves and production, which will include investing in and profitably developing key existing development programs as well as growth through exploration and acquisitions. We seek high quality exploration prospects 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, NGLs, and oil production at market prices and the settlement of commodity hedges.

 

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We were formed in January 2002. Since inception, we substantially increased our activity level and the number of properties that we operate. Our operating results reflect this growth. We began active natural gas and oil operations in March 2002 with the acquisition of properties in the Wind River Basin. Also in 2002, we completed two additional acquisitions of properties in the Uinta, Wind River, Powder River and Williston Basins. In early 2003, we completed an acquisition of largely undeveloped coalbed methane properties located in the Powder River Basin. In September 2004, we acquired properties in the Piceance Basin in or around the Gibson Gulch field. On December 15, 2004, we completed our initial public offering in which we received net proceeds of $347.3 million after deducting underwriting fees and other offering costs. In May 2006, we acquired additional coalbed methane properties in the Powder River Basin. In June 2007, we sold our Williston Basin properties. In June 2009, we acquired Cottonwood Gulch, an undeveloped property in the Piceance Basin.

 

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Results of Operations

The financial information for the three months ended March 31, 2011 and 2010 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.

Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010

 

     Three Months Ended
March 31,
    Increase (Decrease)  
     2011     2010     Amount     Percent  
     ($ in thousands, except per unit data)  

Operating Results:

        

Operating and Other Revenues

        

Oil and gas production

   $ 172,197      $ 163,649      $ 8,548        5

Commodity derivative loss

     (11,112     (5,664     (5,448     (96 )% 

Other

     238        (175     413        236

Operating Expenses

        

Lease operating expense

     13,299        12,441        858        7

Gathering, transportation and processing expense

     19,336        15,970        3,366        21

Production tax expense

     8,566        8,289        277        3

Exploration expense

     1,351        301        1,050        349

Impairment, dry hole costs and abandonment expense

     283        2,879        (2,596     (90 )% 

Depreciation, depletion and amortization

     65,394        56,534        8,860        16

General and administrative expense (1)

     13,067        9,802        3,265        33

Non-cash stock-based compensation expense (1)

     4,629        3,974        655        16
                          

Total operating expenses

   $ 125,925      $ 110,190      $ 15,735        14

Production Data:

        

Natural gas (MMcf)

     21,434        20,629        805        4

Oil (MBbls)

     297        184        113        61

Combined volumes (MMcfe)

     23,216        21,733        1,483        7

Daily combined volumes (MMcfe/d)

     258        241        17        7

Average Realized Prices (2):

        

Natural gas (per Mcf)

   $ 6.69      $ 7.08      $ (0.39     (6 )% 

Oil (per Bbl)

     78.44        70.04        8.40        12

Combined (per Mcfe)

     7.18        7.31        (0.13     (2 )% 

Average Costs (per Mcfe):

        

Lease operating expense

   $ 0.57      $ 0.57      $ 0.00        0

Gathering, transportation and processing expense

     0.83        0.73        0.10        14

Production tax expense

     0.37        0.38        (0.01     (3 )% 

Depreciation, depletion and amortization

     2.82        2.60        0.22        8

General and administrative expense (3)

     0.56        0.45        0.11        24

 

(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense for a total of $17.7 million and $13.8 million for the three months ended March 31, 2011 and 2010, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with stock-based grants.

 

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(2) Average realized prices shown in the table include the impact of all of our realized financial hedges in the form of commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting. As a result of our realized hedging transactions, natural gas production revenues and oil production revenues increased (decreased) by the following amounts (in millions) for the periods indicated:

 

     Three Months Ended March 31,  
     2011     2010  

Natural gas production revenues

   $ 23.3      $ 15.9   

Oil production revenues

   $ (0.8   $ 0.3   

Before the effects of hedging, the average prices we received for natural gas and oil were as follows:

 

     Three Months Ended March 31,  
     2011      2010  

Natural gas (per Mcf)

   $ 5.61       $ 6.31   

Oil (per Bbl)

   $ 81.18       $ 68.23   

 

(3) Excludes non-cash stock-based compensation expense as described in footnote (1) above. This presentation is a non-GAAP measure. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Unaudited Consolidated Statements of Operations, were $0.76 and $0.63 for the three months ended March 31, 2011 and 2010, respectively.

Production Revenues and Volumes. Production revenues increased to $172.2 million for the three months ended March 31, 2011 from $163.6 million for the three months ended March 31, 2010 due to a 7% increase in production partially offset by a 2% decrease in natural gas and oil prices on a per Mcfe basis after the effects of realized cash flow hedges. The effects of realized hedges only include settlements from hedging instruments that were designated as cash flow hedges and exclude those that do not qualify, or were not designated, as cash flow hedges such as basis only and NGL swaps. The settlements from hedging instruments that were not designated as cash flow hedges are included in the line item commodity derivative loss within operating revenues in the Unaudited Consolidated Statements of Operations. See below for more information related to the commodity derivative loss line item. The net increase in production added approximately $11.0 million of production revenues, while the decrease in average price decreased production revenues by approximately $2.4 million.

During the three months ended March 31, 2011, we realized an increase in production revenues related to NGL values received for a portion of our gas production in the Piceance Basin of approximately $25.8 million, or $1.11 per Mcfe, as compared to an increase of $12.8 million, or $0.59 per Mcfe, for the three months ended March 31, 2010. There is no assurance that the amount received in the future related to NGL resulting from the processing of natural gas will exceed the additional cost of processing or the price of natural gas. Based on our revised capital expenditures budget and current price outlook (see “–Capital Resources and Liquidity” section below) for 2011, we expect our NGL recoveries to be comparable to prior years.

Total production volumes for the three months ended March 31, 2011 of 23.2 Bcfe increased from 21.7 Bcfe for the three months ended March 31, 2010 due to increased production in the Piceance Basin. The increase in production was partially offset by decreases in production from West Tavaputs in the Uinta and Wind River Basins. Additional information concerning production is in the following table:

 

     Three Months Ended March 31, 2011      Three Months Ended March 31, 2010      % 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

     140         11,131         11,971         105         9,169         9,799         33     21     22

Uinta Basin

     145         5,545         6,415         66         6,260         6,656         120     (11 )%      (4 )% 

Wind River Basin

     4         1,356         1,380         4         1,821         1,845         0     (26 )%      (25 )% 

Powder River Basin

             3,341         3,341                 3,335         3,335                0     0

Other

     8         61         109         9         44         98         (11 )%      39     11
                                                            

Total

     297         21,434         23,216         184         20,629         21,733         61     4     7
                                                            

The production increase in the Piceance Basin was the result of our continued development activities with initial sales from 148 new gross wells from April 1, 2010 to March 31, 2011. The production increase in oil from the Uinta Basin resulted from our ongoing development program at Blacktail Ridge and Lake Canyon with initial sales from 23 new gross wells from April 1, 2010 to March 31, 2011. The decrease in gas production from the Uinta Basin is due to natural production declines as well as a limited development program in our West Tavaputs field during 2010, partially offset by higher natural gas volumes from our Blacktail Ridge/Lake Canyon development. Due to the issuance of the final Environmental Impact Statement and Record of Decision in the West Tavaputs field of the Uinta Basin authorizing full field development, we anticipate an overall increase in production in this basin in 2011 as our development activities increase. The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields with no significant drilling or recompletion activities to offset these declines.

 

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Hedging Activities. During the three months ended March 31, 2011, approximately 63% of our natural gas volumes (excluding basis only swaps, which were equivalent to 8% of our natural gas volumes) and 63% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $23.3 million and a decrease in oil revenues of $0.8 million after settlements for all commodity derivatives, including basis only and NGL swaps. During the three months ended March 31, 2010, approximately 77% of our natural gas volumes (excluding basis only swaps, which were equivalent to 12% of our natural gas volumes) and 47% of our oil volumes were subject to financial hedges, which resulted in an increase in gas revenues of $15.9 million and an increase in oil revenues of $0.3 million after settlements for all commodity derivatives, including basis only and NGL swaps. We may not always be able to generate increases in revenue, like those in the first quarter of 2011 discussed above, due to the expiration of hedges entered into at higher prices and the inability to enter into new hedges at those prices as natural gas prices have fallen since entering into those hedges.

The overall change in commodity derivative loss to $11.1 million for the three months ended March 31, 2011 from a loss of $5.7 million for the three months ended March 31, 2010 was primarily due to an increase in the unrealized loss on derivatives not designated as cash flow hedges from $1.3 million for the three months ended March 31, 2010 to $5.9 million for the three months ended March 31, 2011 primarily as a result of changes in the fair value of our NGL hedges.

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

 

     Three Months Ended March 31,  
     2011     2010  
     (in thousands)  

Realized loss on derivatives not designated as cash flow hedges

   $ (5,404   $ (4,763

Unrealized ineffectiveness gain recognized on derivatives designated as cash flow hedges

     163        393   

Unrealized loss on derivatives not designated as cash flow hedges

     (5,871     (1,294
                

Total commodity derivative loss

   $ (11,112   $ (5,664
                

Lease Operating Expense. Lease operating expense for both the three months ended March 31, 2011 and the three months ended March 31, 2010 was $0.57 per Mcfe. The increase in total lease operating expense of $0.9 million was primarily due to a 7% increase in production in the current year, which kept lease operating expenses unchanged on a per unit basis.

Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $0.83 per Mcfe for the three months ended March 31, 2011 from $0.73 per Mcfe for the three months ended March 31, 2010. This increase is due to additional expense we recognized associated with the start-up of new firm contracts to gather, transport and process our production from the Piceance and Uinta Basins ahead of anticipated production increases.

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 and Uinta Basins where we expect to allocate a significant portion of our capital expenditure programs in future years. In addition, we have entered into long-term firm processing contracts on a portion of our production in the Piceance and Uinta Basins. Included in gathering, transportation and processing expense are $0.29 and $0.18 per Mcfe of firm transportation and gathering expense and $0.04 and $0.05 per Mcfe of firm processing expense from long-term contracts for the three months ended March 31, 2011 and 2010, respectively. The increase in firm transportation and gathering expense to $0.29 per Mcfe for the three months ended March 31, 2011 compared to $0.18 per Mcfe for the three months ended March 31, 2010 was the result of additional long-term contracts executed with various pipelines for our natural gas production in the Piceance and Uinta Basins as mentioned above.

Production Tax Expense. Total production taxes increased to $8.6 million for the three months ended March 31, 2011 from $8.3 million for the three months ended March 31, 2010. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense for the three months ended March 31, 2011 includes a one-time reduction of $0.8 million related to the 2010 Utah and Colorado annual severance tax calculations. Production tax expense for the three months ended March 31, 2010 included a one-time reduction of $2.2 million related to amended 2004 through 2009 Utah annual severance tax calculations. Production taxes as a percentage of natural gas and oil sales before hedging adjustments was 5.9% for the three months ended March 31, 2011, which included a reduction of 0.5% related to the nonrecurring item associated with the Utah and Colorado annual severance tax calculations. For the three months ended March 31, 2010, production taxes as a percentage of natural gas and oil sales before hedging adjustments was 5.8%, which included a reduction of 1.5% related to the nonrecurring item associated with the Utah severance tax.

 

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Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas. The decrease in the overall production tax rate, excluding the nonrecurring items associated with the Utah and Colorado severance taxes, is consistent with our production decrease from states with higher production tax rates.

Exploration Expense. Exploration expense increased to $1.4 million for the three months ended March 31, 2011 from $0.3 million for the three months ended March 31, 2010. Exploration expense for the three months ended March 31, 2011 consisted of $1.3 million of geological and geophysical seismic programs and $0.1 million for delay rentals across all basins. Exploration expense for the three months ended March 31, 2010 consisted of $0.1 million for seismic programs and $0.2 million for delay rentals and other costs across all basins.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense decreased to $0.3 million during the three months ended March 31, 2011 from $2.9 million during the three months ended March 31, 2010. For the three months ended March 31, 2011, expired leasehold costs were $0.3 million. For the three months ended March 31, 2010, abandonment expense associated with exploratory drilling locations was $0.2 million, expired leasehold costs were $0.8 million and dry hole costs were $1.9 million. For the three months ended March 31, 2011 and 2010, we did not incur any impairment charges related to the net carrying value of our oil and gas properties.

Depreciation, Depletion and Amortization. DD&A was $65.4 million for the three months ended March 31, 2011 compared to $56.5 million for the three months ended March 31, 2010. The increase of $8.9 million was a result of a 7% increase in production for the three months ended March 31, 2011 compared to the three months ended March 31, 2010 coupled with an increase in the DD&A rate. The increase in production accounted for $3.9 million of additional DD&A expense, while the overall increase in the DD&A rate accounted for a $5.0 million increase in DD&A expense. For the three months ended March 31, 2011 and 2010, the weighted average DD&A rates were $2.82 per Mcfe and $2.60 per Mcfe, respectively.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $13.1 million in the three months ended March 31, 2011 from $9.8 million in the three months ended March 31, 2010. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 24 for a reconciliation and explanation. This increase was primarily due to an increase in employee compensation and benefit programs for the three months ended March 31, 2011, $0.8 million of which is not expected to be recurring. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, increased to $0.56 per Mcfe for the three months ended March 31, 2011 from $0.45 per Mcfe for the three months ended March 31, 2010.

Non-cash charges for stock-based compensation were $4.6 million for the three months ended March 31, 2011 compared to $4.0 million for the three months ended March 31, 2010. Non-cash stock-based compensation expense for each of the three months ended March 31, 2011 and 2010 related primarily to 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 was primarily due to additional equity awards that were granted during the last nine months of 2010 and during the three months ended March 31, 2011.

The components of non-cash stock-based compensation for the three months ended March 31, 2011 and 2010 are shown in the following table:

 

     Three Months Ended March 31,  
     2011      2010  
     (in thousands)  

Stock options and nonvested equity shares of common stock

   $ 4,242       $ 3,657   

Shares issued for 401(k) plan

     276         246   

Shares issued for directors’ fees

     111         71   
                 

Total

   $ 4,629       $ 3,974   
                 

Interest Expense. Interest expense increased to $12.0 million for the three months ended March 31, 2011 from $10.1 million for the three months ended March 31, 2010. The increase was primarily due to a higher effective interest rate due to increased financing and commitment fees relating to the Amended Credit Facility combined with reduced capitalized interest costs for the three months ended March 31, 2011. Interest cost is capitalized as a component of oil and gas property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. For the three months ended March 31, 2011, we had less significant wells and facilities in progress as compared to the three months ended March 31, 2010 resulting in a lower amount of interest costs that were capitalized during the period. Our weighted average interest rate for the three months ended March 31, 2011, including interest and amortization of discounts and deferred financing fees on our Amended Credit Facility, Convertible Notes and Senior Notes, was 12.3% compared to 11.4% for the three months ended March 31, 2010. We capitalized interest costs of $0.4 million and $1.3 million for the three months ended March 31, 2011 and 2010, respectively.

 

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Income Tax Expense. Income tax expense totaled $8.2 million for the three months ended March 31, 2011 compared to $13.5 million for the three months ended March 31, 2010, resulting in effective tax rates of 35.0% and 36.1%, respectively. The effective tax rate decrease was primarily the result of a greater proportion of our operating revenue being attributable to lower tax rate jurisdictions. The effect of this rate change on our prior year net deferred tax liability was included in income tax expense for the three months ended March 31, 2011. The effective tax rate will vary from period to period due to changes in the composition of income between state tax jurisdictions resulting from our activity. For both the 2011 and 2010 periods, our effective tax rate differs from the federal statutory rate primarily because we recorded stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been net cash provided by operating activities, sales and other issuances of equity and debt securities, including our Convertible Notes and Senior Notes, bank credit facilities, proceeds from joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of natural gas and oil properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. The credit market dislocation that has existed over the past two to three years has improved. We believe that we have significant liquidity available to us from cash flows from operations and under our Amended Credit Facility for our planned uses of capital. In addition, our hedge positions provide relative certainty on a significant portion of our cash flows from operations through 2011 and 2012 even with the general decline in the price of natural gas resulting from current oversupply and decreased demand. We actively review acquisition opportunities on an ongoing basis. If we were to make substantial additional acquisitions for cash, we may need to obtain additional equity or debt financing, which may be at a higher cost than previous issuances or that was previously available. We have an automatically effective shelf registration statement with the SEC that we used for the offering of our Senior Notes and that we may use for future securities offerings.

At March 31, 2011, we had cash and cash equivalents of $41.2 million with a zero balance outstanding under our Amended Credit Facility. Under our Amended Credit Facility, we have a borrowing base of $800.0 million with commitments from 19 lenders for a total of $700.0 million, which was reaffirmed on March 25, 2011 based on our December 31, 2010 reserves and hedge position. Our borrowing capacity is reduced by $26.0 million to $674.0 million due to an outstanding irrevocable letter of credit.

Cash Flow from Operating Activities

For the three months ended March 31, 2011, we generated $87.7 million of cash provided by operating activities, a decrease of $1.3 million over the same period in 2010. Cash provided by operating activities decreased primarily due to higher cash operating expenses including lease operating expense, gathering, transportation and processing expense, production tax expense and general and administrative expense, which were slightly offset by higher production volumes.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas, NGLs and oil. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic and political activity, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 3.—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, NGLs and oil prices, we have entered into financial commodity swap and cashless collar contracts (purchased put options and written call options) to receive fixed prices for a portion of our production revenue. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production revenue. We typically hedge a fixed price for natural gas at our sales points (New York Mercantile Exchange (“NYMEX”) less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. In addition to the swaps and collars, we also have entered into basis only swaps. With a basis only swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. At March 31, 2011, we had in place natural gas financial collars, swaps and basis only swaps covering portions of our 2011 and 2012 production revenue and NGLs and crude oil financial collars and swaps covering portions of our 2011, 2012, 2013 and 2014 production.

In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas production revenues at the time of settlement.

 

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

During the term of a derivative instrument, if we determine that the hedge is no longer effective or necessary, hedge accounting is prospectively discontinued. All subsequent changes in the derivative’s fair value are recorded in earnings, and all accumulated gains or losses, based on the effective portion of the derivative at that date, recorded in AOCI will remain in AOCI and are reclassified to earnings when the underlying transaction occurs. If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time period, the hedging instrument loses cash flow hedge accounting treatment and all subsequent mark-to-market gains and losses are recorded in earnings, and all accumulated gains or losses recorded in AOCI related to the hedging instrument are also reclassified to earnings.

Some of our derivatives do not qualify for hedge accounting or are not designated as cash flow hedges but are, to a degree, an economic offset to our commodity price exposure. If a derivative instrument does not qualify 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 loss in the Unaudited 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 a payment to or receiving a payment from the counterparty. Realized gains and losses of derivative instruments that do not qualify as cash flow hedges are recognized in commodity derivative loss in the Unaudited Consolidated Statements of Operations and are reflected in cash flows from operations on the Unaudited Consolidated Statements of Cash Flows.

In addition to the swaps and collars discussed above, we have entered into basis only swaps to hedge the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. Although we believe this is an appropriate part of a mitigation strategy, the basis only swaps do not qualify for hedge accounting because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments are recorded in earnings.

We have also entered into swap contracts to hedge a portion of the amount received related to NGLs resulting from the processing of our gas. Our NGL hedges were not designated as cash flow hedges, and the fair value of these derivative instruments were recorded in earnings.

At March 31, 2011, the estimated fair value of all of our commodity derivative instruments was a net asset of $13.3 million comprised of current assets, current liabilities, and non-current liabilities, including a fair value liability of $13.4 million for basis only swaps and a fair value liability of $11.7 million for NGL swaps. We will reclassify the appropriate cash flow hedge amounts from AOCI to gains and 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 relating to cash flow hedges as of March 31, 2011 to be reclassified from AOCI to earnings in the next 12 months would be a gain of approximately $23.1 million. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. We anticipate that all originally forecasted transactions related to our derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods.

The hedge instruments designated as cash flow hedges are at liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale, which may result in ineffectiveness. Ineffectiveness related to our cash flow derivative instruments for the three months ended March 31, 2011 and 2010 were gains of $0.2 million and $0.4 million, respectively, which were reported in commodity derivative loss in the Unaudited Consolidated Statements of Operations. Although those derivatives may not achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

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

 

     Three Months Ended March 31,  
     2011     2010  

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

   $ 27,922      $ 21,008   
                

Realized loss on derivatives not designated as cash flow hedges (2)

   $ (5,404   $ (4,763

Unrealized ineffectiveness gain recognized on derivatives designated as cash flow hedges (2)

     163        393   

Unrealized loss on derivatives not designated as cash flow hedges (2)

     (5,871     (1,294
                

Total commodity derivative loss

   $ (11,112   $ (5,664
                

 

(1) Included in oil and gas production revenues in the Unaudited Consolidated Statements of Operations.
(2) Included in commodity derivative loss in the Unaudited Consolidated Statements of Operations.

 

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The following table summarizes all of our hedges in place as of March 31, 2011:

 

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:

                                     

2011

                                     

Natural gas

       2,140,000         MMBtu      $ 4.75         $ 6.00           N/A           N/A       CIG      $ 1,643   

Oil

       55,000         Bbls      $ 92.50         $ 120.78           N/A           N/A       WTI      $ (73

Swap Contracts:

                                     

2011

                                     

Natural gas

       19,635,000         MMBtu        N/A           N/A         $ 5.99           N/A       CIG      $ 35,936   

Natural gas

       18,487,500         MMBtu        N/A           N/A         $ 5.08           N/A       NWPL      $ 16,498   

Natural gas
liquids
(2)

       52,050,000         Gallons        N/A           N/A         $ 1.07           N/A       Mt. Belvieu      $ (10,707

Oil

       715,000         Bbls        N/A           N/A         $ 92.69           N/A       WTI      $ (10,859

2012

                                     

Natural gas

       6,715,000         MMBtu        N/A           N/A         $ 4.71           N/A       CIG      $ 578   

Natural gas

       20,275,000         MMBtu        N/A           N/A         $ 4.53           N/A       NWPL      $ (2,951

Natural gas
liquids
(2)

       13,200,000         Gallons        N/A           N/A         $ 1.48           N/A       Mt. Belvieu      $ (978

Oil

       475,800         Bbls        N/A           N/A         $ 101.70           N/A       WTI      $ (2,145

2013

                                     

Oil

       109,500         Bbls        N/A           N/A         $ 101.52           N/A       WTI      $ (191

2014

                                     

Oil

       73,000         Bbls        N/A           N/A         $ 100.75           N/A       WTI      $ (74

Basis Only Swap Contracts(3):

                                     

2011

                                     

Natural gas

       5,500,000         MMBtu        N/A           N/A           N/A         $ (1.72    NWPL      $ (7,369

2012

                                     

Natural gas

       3,660,000         MMBtu        N/A           N/A           N/A         $ (1.24    NWPL      $ (3,129

Natural gas

       3,660,000         MMBtu        N/A           N/A           N/A         $ (1.20    CIG      $ (2,883
                                           

Total

                                      $ 13,296   
                                           

 

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The following table includes all hedges entered into subsequent to March 31, 2011 through April 22, 2011:

 

Contract

     Total
Hedged
Volumes
      

Quantity

Type

     Weighted
Average
Floor
Price
       Weighted
Average
Ceiling
Price
       Weighted
Average
Fixed
Price
       Basis
Differential
      

Index

Price(1)

Cashless Collars:

                                  

2011

                                  

Oil

       27,500         Bbls      $ 100.00         $ 122.00           N/A           N/A         WTI

Swap Contracts:

                                  

2011

                                  

Natural gas

       3,670,000         MMBtu        N/A           N/A         $ 4.16           N/A         NWPL

Natural gas

       1,220,000         MMBtu        N/A           N/A         $ 4.27           N/A         CIG

Natural gas liquids(3)

       5,250,000         Gallons        N/A           N/A         $ 1.00           N/A         Mt. Belvieu

2012

                                  

Natural gas liquids(4)

       3,300,000         Gallons        N/A           N/A         $ 2.18           N/A         Mt. Belvieu

Oil

       292,800         Bbls        N/A           N/A         $ 108.59           N/A         WTI

2013

                                  

Oil

       73,000         Bbls        N/A           N/A         $ 105.75           N/A         WTI

2014

                                  

Oil

       36,500         Bbls        N/A           N/A         $ 105.50           N/A         WTI

 

(1) CIG refers to Colorado Interstate Gas Rocky Mountains and NWPL refers to Northwest Pipeline Corporation, price as quoted in Platt’s Inside FERC on the first business day of each month. Mt. Belvieu refers to the average daily price as quoted by Oil Price Information Service (“OPIS”) for Mont Belvieu spot gas liquid prices. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.
(2) Weighted average fixed price includes purity ethane, propane, normal butane, isobutane and natural gasoline hedges
(3) Represents a swap of the basis between the NYMEX price and the spot price of the index listed under Index Price above.
(4) Weighted average fixed price includes propane, normal butane, isobutane, and natural gasoline hedges.

By removing the price volatility related to a portion of our natural gas production for 2011 and 2012 and a portion of our oil production for 2011, 2012, 2013 and 2014 we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

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

We believe all of our counterparties currently are acceptable credit risks. We are not required to provide credit support or collateral to any of our counterparties other than cross collateralization with the properties securing our Amended Credit Facility, nor are they required to provide credit support to us. As of April 22, 2011, we do not have any past due receivables from any of our counterparties.

Capital Expenditures

Our capital expenditures are summarized in the following tables:

 

     Three Months Ended March 31,  
Basin/Area    2011      2010  
     (in millions)  

Piceance

   $ 45.7       $ 67.0   

Uinta

     65.8         31.6   

Powder River

     8.7         1.1   

Wind River

     0.9         1.9   

Other

     3.7         2.0   
                 

Total

   $ 124.8       $ 103.6   
                 

 

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     Three Months Ended March 31,  
     2011      2010  
     (in millions)  

Acquisitions of proved and unproved properties and other real estate

   $ 4.4       $ 1.8   

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

     118.0         101.0   

Geologic and geophysical costs

     1.4         0.3   

Furniture, fixtures and equipment

     1.0         0.5   
                 

Total (2)

   $ 124.8       $ 103.6   
                 

 

(1) Includes related gathering and facilities costs.
(2) For the three months ended March 31, 2010, we received $3.1 million of proceeds principally from the sale of interests in oil and gas properties, which are not deducted from the capital expenditures presented above.

Our current estimate is for capital expenditures of $625 to $645 million in 2011 excluding acquisitions, which may be adjusted throughout the year as business conditions warrant. We have increased our capital expenditure budget from the budget set forth in our Form 10-K for the year ended December 31, 2010. We believe that we have sufficient available liquidity through 2011 to fund our capital expenditures budget from cash flow from operations and the Amended Credit Facility. Future cash flows are subject to a number of variables, including our level of natural gas and oil production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.

The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If natural gas and oil prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity generally by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow. We routinely monitor and adjust our capital expenditures, including acquisitions and divestitures, in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside of our control.

Financing Activities

Our outstanding debt is summarized below (in thousands):

 

          As of March 31, 2011      As of December 31, 2010  
     

Maturity Date

   Principal      Unamortized
Discount
    Carrying
Amount
     Principal      Unamortized
Discount
    Carrying
Amount
 

Amended Credit Facility

   April 1, 2014    $ 0       $ 0      $ 0       $ 0       $ 0      $ 0   

Senior Notes (1)

   July 15, 2016      250,000         (9,887     240,113         250,000         (10,234     239,766   

Convertible Notes (2)

   March 15, 2028 (3)      172,500         (6,369     166,131         172,500         (7,867     164,633   

 

(1) The aggregate estimated fair value of the Senior Notes was approximately $281.3 million as of March 31, 2011 based on quoted market trades of these instruments.
(2) The aggregate fair value of the Convertible Notes was approximately $177.2 million as of March 31, 2011. Because there is no active, public market for the Convertible Notes, the fair value was based on market-based parameters of the various components of the Convertible Notes and over-the-counter trades.
(3) We currently expect that the holders will put the Convertible Notes to us in March 2012. We also have the option to call the Convertible Notes anytime thereafter.

 

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Revolving Credit Facility

On March 16, 2010, we amended our credit facility (the “Amended Credit Facility”) and extended the maturity date to April 1, 2014. 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 2.0% to 3.0% or an alternate base rate (“ABR”), based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.0%, plus applicable margins ranging from 1.0% to 2.0%. The borrowing base is required to be redetermined twice per year. On March 25, 2011, the borrowing base was reaffirmed at $800.0 million with commitments from 19 lenders of $700.0 million, based on December 31, 2010 reserves and hedge position. We pay annual commitment fees of 0.5% of the unused amount of our commitments. 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. The Amended Credit Facility also contains certain financial covenants. We currently are in compliance with all financial and other covenants, and we have complied with all financial covenants for all prior periods.

As of March 31, 2011, we did not have a balance outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility effective May 4, 2010, which reduced the borrowing capacity of the Amended Credit Facility by $26.0 million to $674.0 million.

5% Convertible Senior Notes due 2028

The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior indebtedness, including the Senior Notes. Interest is payable semi-annually in arrears on March 15 and September 15 of each year. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility.

9.875% Senior Notes Due 2016

The Senior Notes, which were issued on July 8, 2009, are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes. Interest is payable in arrears semi-annually on January 15 and July 15 each year. The Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility and the Convertible Notes. The Senior Notes include certain covenants that limit our ability to incur additional indebtedness, pay dividends, make restricted payments, create liens and sell assets. We currently are in compliance with all financial covenants, and we have complied with all financial covenants for all prior periods.

The following table summarizes the cash portion of interest expense related to the Amended Credit Facility, Convertible Notes and Senior Notes along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense (in thousands):

 

     Three Months Ended March 31,  
     2011      2010  

Credit Facility (1)

  

Cash interest

   $ 981       $ 449   

Non-cash interest

   $ 780       $ 405   

Senior Notes (2)

  

Cash interest

   $ 6,172       $ 6,172   

Non-cash interest

   $ 608       $ 551   

Convertible Notes (3)

     

Cash interest

   $ 2,156       $ 2,156   

Non-cash interest

   $ 1,783       $ 1,652   

 

(1) Cash interest includes amounts related to interest and commitment fees paid on the line of credit and participation and fronting fees paid on the letter of credit.
(2) The stated interest rate for the Senior Notes is 9.875% per annum with an effective interest rate of 11.3% per annum.
(3) The stated interest rate for the Convertible Notes is 5% per annum with an effective interest rate of 9.7% per annum. The effective interest rate of the Convertible Notes includes the amortization of the debt discount, which represents the fair value of the equity conversion feature at the time of issue.

 

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

Contractual Obligations. A summary of our contractual obligations as of and subsequent to March 31, 2011 is provided in the following table:

 

     Payments Due By Year  
   Year 1      Year 2      Year 3      Year 4      Year 5      Thereafter      Total  
     (in thousands)  

Notes payable (1)

   $ 553      $ 553      $ 553      $ 553       $ 553      $ 1,149      $ 3,914   

Senior Notes(2)

     24,688         24,688         24,688         24,688        24,688        257,201        380,641   

Convertible Notes (3)

     181,005         —           —           —           —           —           181,005   

Purchase commitments (4)(5)

     17,259         —           —           —           —           —           17,259   

Drilling rig commitments (5) (6)

     24,240         16,808         690         —           —           —           41,738   

Office and office equipment leases and other(7)

     2,372         2,165         1,984         1,803         1,821         5,615         15,760   

Firm transportation and processing agreements(5)(8)

     58,014         61,855         61,805         61,829         60,130         230,810         534,443   

Asset retirement obligations (9)

     1,494         9,132         584         1,168         3,317         39,073         54,768   

Derivative liabilities (10)

     33,919         8,123         147         46         —           —           42,235   
                                                              

Total

   $ 343,544       $ 123,324       $ 90,451       $ 90,087       $ 90,509       $ 533,848       $ 1,271,763   
                                                              

 

(1) We currently have no balance outstanding on our Amended Credit Facility. This table does not include future commitment fees, interest expense or other fees on our Amended Credit Facility because the Amended Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. However, we have a $26.0 million letter of credit that accrues interest at 2.0% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term for the letter of credit is April 30, 2018.
(2) On July 8, 2009, we issued $250.0 million aggregate principal amount of Senior Notes. We are obligated to make annual interest payments throughout maturity equal to $24.7 million.
(3) On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. For purposes of contractual obligations, we assume that the holders of our Convertible Notes will not exercise the conversion feature, and we will therefore repay the $172.5 million in cash in 2012. We currently expect to call the Convertible Notes for redemption or have them put to us in 2012. We also are obligated to make annual interest payments equal to $8.6 million.
(4) We have two take-or-pay carbon dioxide (“CO2”) purchase agreements, one that expires in December 2011 and one that expires in February 2012, that impose a minimum volume commitment to purchase CO2 at a contracted price. The contracts provide CO2 used in fracture stimulation operations in our Uinta Basin operations. Should we not take delivery of the minimum volume required, we would be obligated to pay for the deficiency. At this time, our planned volumes needed exceed the minimum requirement, and we do not anticipate any deficiency payments.
(5) The values in the table represent the gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest and net revenue interest, which will vary from property to property.
(6) We currently have six drilling rigs under contract; four that expire in 2011 and two that expire in 2013. These contracts may be terminated but we would be required to pay a penalty of $24.2 million. All other rigs currently performing work for us are on a well-by-well basis and, therefore, can be released without penalty at the conclusion of drilling on the current well. These latter types of drilling obligations have not been included in the table above.
(7) The lease for our principal offices in Denver was renewed in September 2010 and now extends through March 2019.
(8) 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 13 years and require us to pay transportation demand and processing charges regardless of the amount of gas we deliver to the processing facility or pipeline.

 

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(9) Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See “Critical Accounting Policies and Estimates” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
(10) Derivative liabilities represent the net fair value for oil and gas commodity derivatives presented as liabilities in our Consolidated Balance Sheets as of March 31, 2011. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See “Critical Accounting Policies and Estimates” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 and in “–Commodity Hedging Activities” above in this Quarterly Report on Form 10-Q for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

In addition to the commitments above, we have commitments for the purchase of facilities and infrastructure as of March 31, 2011 of $13.1 million.

Trends and Uncertainties

For a discussion of trends and uncertainties that may affect our financial condition or liquidity, we refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010. Other than as discussed above and except for trends described in the risk factor section contained in Part II, Item 1A of this Form 10-Q, no material change to such trends and uncertainties has occurred during the three months ended March 31, 2011.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 and the notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Quarterly Report on Form 10-Q for a description of critical accounting policies and estimates.

 

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 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 prices we receive for our 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, NGLs and oil has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for future 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 derivative contracts in place for the three months ended March 31, 2011, our annual income before income taxes would have decreased by approximately $0.9 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.1 million for each $1.00 per barrel decrease in crude oil prices.

We routinely enter into financial hedges relating to a portion of our projected production revenue through various financial transactions that hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price 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 that provide an acceptable rate of return and to manage our exposure to natural gas and oil price fluctuations. In addition to the swaps and collars discussed above, we also entered into basis only swaps. With a basis only swap, we have fixed the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location to mitigate against the risk of large differences between NYMEX (Henry Hub) and our primary sales points, CIG and NWPL. We may consider entering into hedge transactions based on a NYMEX price in the future with a volume equal to the volume for our basis only swaps, thereby effectively fixing a price for CIG or NWPL.

 

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As of April 22, 2011, we have financial derivative instruments related to natural gas, NGLs and oil volumes in place for the following periods indicated. Further detail of these hedges is summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Commodity Hedging Activities.”

 

     April – December
2011
     For the year
2012
     For the  year
2013
     For the  year
2014
 

Oil (Bbls)

     797,500         768,600         182,500         109,500   

Natural Gas (MMbtu)

     45,152,500         26,990,000         0         0   

Natural Gas Basis (MMbtu)

     5,500,000         7,320,000         0         0   

Natural Gas Liquids (Gallons)

     57,300,000         16,500,000         0         0   

Rate Risks

At March 31, 2011, there was no outstanding balance under our Amended Credit Facility, which bears interest at floating rates in accordance with our Amended Credit Facility. Therefore the average annual interest rate incurred on this debt for the three months ended March 31, 2011 was 0% and a 1.0% increase in each of the average LIBOR rate and federal funds rate for the three months ended March 31, 2011 would have had no effect on interest expense for the three months ended March 31, 2011. At March 31, 2010, we had debt outstanding under our Amended Credit Facility of $15.0 million. The average annual interest rate incurred on this debt for the three months ended March 31, 2010 was 2.1%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the three months ended March 31, 2010 would have resulted in an estimated $0.2 million increase in interest expense assuming a similar average debt level to the three months ended March 31, 2010. We also had $172.5 million principal amount of Convertible Notes and $250.0 million principal amount of Senior Notes outstanding at March 31, 2011, which have fixed cash interest rates of 5.0% and 9.875% per annum, respectively.

 

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Based on an evaluation carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2011.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended March 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II. OTHER INFORMATION

 

Item 1. Legal Proceedings.

We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

 

Item 1A. Risk Factors.

As of the date of this filing, there have been no material changes or updates to the risk factors previously disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2010, referred to as our 2010 Annual Report. An investment in our securities involves various risks. When considering an investment in our Company, you should carefully consider all of the risk factors described in our 2010 Annual Report and subsequent reports filed with the SEC. These risks and uncertainties are not the only ones facing us, and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our Company.

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Unregistered Sales of Securities

There were no sales of unregistered equity securities during the period covered by this report.

Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended March 31, 2011:

 

Period

   Total
Number of
Shares (1)
     Weighted
Average  Price
Paid Per
Share
     Total Number of  Shares
(or Units) Purchased as
Part of Publicly
Announced Plans or
Programs
     Maximum Number  (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs
 

January 1 – 31, 2011

     0       $ 0         0        0  

February 1 – 28, 2011

     85,180         38.08         0        0  

March 1 – 31, 2011

     4,350         37.69         0        0  
                             

Total

     89,530       $ 38.06         0        0  
                             

 

(1) Represents shares delivered by employees to satisfy the exercise price of stock options and tax withholding obligations in connection with the exercise of stock options and shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of shares of common stock issued pursuant to our employee incentive plans.

 

Item 3. Defaults upon Senior Securities.

Not applicable.

 

Item 5. Other Information.

Not applicable.

 

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Item 6. Exhibits.

 

Exhibit

Number

 

Description of Exhibits

  3.1   Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 of our Current Report on Form 8-K filed with the Commission on December 20, 2004.]
  3.2   Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.5 of our Current Report on Form 8-K filed with the Commission on December 20, 2004.]
      4.1(a)   Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
      4.1(b)   Indenture, dated March 12, 2008, between Bill Barrett Corporation and Deutsch Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
      4.1(c)   Indenture, dated July 8, 2009, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on July 8, 2009.]
      4.2(a)   Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 of Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
      4.2(b)   First Supplemental Indenture, dated March 12, 2008, by and between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 5% Convertible Senior Notes due 2028). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
      4.2(c)   First Supplemental Indenture, dated July 8, 2009, by Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 9.875% Senior Notes due 2016). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on July 8, 2009.]
      4.3(a)   Stockholders’ Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
      4.3(b)   Second Supplemental Indenture, dated July 8, 2009, by Bill Barrett Corporation, Bill Barrett CBM Corporation, Bill Barrett CBM LLC, Circle B Land Company LLC and Deutsche Bank Trust Company Americas, as Trustee (including form of 9.875% Senior Notes due 2016). [Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K with the Commission on July 8, 2009.]
  4.4   Form of Rights Agreement concerning Shareholder Rights Plan, which includes as Exhibit A thereto the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, and, as Exhibit B thereto the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
  4.5   Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
  4.6   Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 24, 2004.]
31.1   Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2   Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32.1   Section 1350 Certification of Chief Executive Officer.
32.2   Section 1350 Certification of Chief Financial Officer.
101   The following materials from the Bill Barrett Corporation Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, formatted in XBRL (eXtensible Business Reporting Language) include (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Stockholders’ Equity and Comprehensive Income, (iv) the Consolidated Statements of Cash Flows, and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text.*

 

* Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these Sections.

 

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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.

 

    BILL BARRETT CORPORATION
Date: May 3, 2011     By:  

/s/ Fredrick J. Barrett

      Fredrick J. Barrett
      Chairman of the Board of Directors, Chief Executive Officer and President
      (Principal Executive Officer)
Date: May 3, 2011     By:  

/s/ Robert W. Howard

      Robert W. Howard
      Chief Financial Officer and Treasurer
      (Principal Financial Officer)

 

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