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Bill Barrett 10-Q 2011
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
(Mark One)
For the quarterly period ended September 30, 2011 OR
For the transition period from to Commission file number 001-32367
BILL BARRETT CORPORATION (Exact name of registrant as specified in its charter)
(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.
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 47,678,368 shares of $0.001 par value common stock outstanding on October 21, 2011.
TABLE OF CONTENTS
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PART I. FINANCIAL INFORMATION
BILL BARRETT CORPORATION CONSOLIDATED BALANCE SHEETS (UNAUDITED)
See notes to unaudited consolidated financial statements.
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BILL BARRETT CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
See notes to unaudited consolidated financial statements.
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BILL BARRETT CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (UNAUDITED)
See notes to unaudited consolidated financial statements.
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BILL BARRETT CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
See notes to unaudited consolidated financial statements.
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BILL BARRETT CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) September 30, 2011 1. Organization Bill Barrett Corporation together with its wholly-owned subsidiaries (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 September 30, 2011, the Company’s results of operations for the three and nine months ended September 30, 2011 and 2010 and cash flows for the nine months ended September 30, 2011 and 2010. Operating results for the three and nine months ended September 30, 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, revenues 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. Areas requiring the use of assumptions, judgments and estimates relate to the expected 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, the timing of dry hole costs, 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 8.5% and 12.4% for the three months ended September 30, 2011 and 2010, respectively, and 10.3% and 12.0% for the nine months ended September 30, 2011 and 2010, respectively, which include interest, amortization of discounts and deferred financing fees on the Company’s Convertible Notes, its 9.875% Senior Notes due 2016 (“9.875% Senior Notes”), its 7.625% Senior Notes due 2019 (“7.625% Senior Notes”) and its credit facility. The Company capitalized interest costs of $0.3 million and $1.1 million for the three months ended September 30, 2011 and 2010, respectively, and $1.2 million and $3.5 million for the nine months ended September 30, 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.
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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 and nine months ended September 30, 2011, the Company recognized a non-cash impairment charge of $3.9 million related to its unproved oil and gas properties which was included within impairment, dry hole costs and abandonment expense in the Unaudited Consolidated Statements of Operations. The non-cash impairment charge related to acreage within an exploration project that the Company no longer considers prospective. During the three and nine months ended September 30, 2010, the Company did not recognize any non-cash impairment charges related to its unproved oil and gas properties. 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:
Net changes in capitalized exploratory well costs for the nine months ended September 30, 2011 are reflected in the following table (in thousands):
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 September 30, 2011, pending determination of whether the wells will be assigned proved reserves:
As of September 30, 2011, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling were $5.0 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 typically 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.
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The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. During the three and nine months ended September 30, 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 liabilities are comprised of the following (in thousands):
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 FASB 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 on January 1, 2010, except for the Level 3 reconciliation disclosures, which were adopted on January 1, 2011. Adoption of the disclosure requirements did not have a material impact on the Company’s financial position or results of operations. In December 2010, the FASB issued Accounting Standards Update 2010-29, Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations, which amended FASB ASC Topic 805, Business Combinations. The objective of this update is to clarify and expand the pro forma revenue and earnings disclosure requirements for business combinations. The guidance was effective for fiscal years beginning after December 15, 2010, and the Company adopted the provision on January 1, 2011. Adoption of the disclosure requirements did not have a material impact on the Company’s financial position or results of operations. In May 2011, the FASB issued Accounting Standards Update 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, which amended FASB ASC Topic 820, Fair Value Measurement. The objective of this update is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”). The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements. These amendments are not expected to have a significant impact on companies applying GAAP. This provision is effective for interim and annual periods beginning after December 15, 2011. Adoption of this update is not expected to have a material impact on the Company’s disclosures and financial statements. In June 2011, the FASB issued Accounting Standards Update 2011-05, Presentation of Comprehensive Income, which amended FASB ASC Topic 220, Comprehensive Income. The intent of this update was to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. To facilitate convergence of GAAP and IFRS, the FASB eliminated the option to present components of other comprehensive income as part of the statement of stockholders’ equity and requires an entity to present total comprehensive income, the components of net income and the
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components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. The guidance is effective for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the potential impact that the adoption will have on the Company’s disclosures and financial statements. 3. Earnings Per Share Basic net income per common share 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 common share only after the shares become fully vested. Diluted net income per common share 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 common 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 expects to settle the Convertible Notes in cash; 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 common share calculation for the three and nine months ended September 30, 2011 and 2010. The diluted net income per common share calculation excludes the anti-dilutive effect of 95,280 and 160,214 shares of stock options and nonvested performance-based equity shares of common stock for the three months ended September 30, 2011 and 2010, respectively, and 140,015 and 222,747 shares of stock options and nonvested performance-based equity shares of common stock for the nine months ended September 30, 2011 and 2010, respectively. The following table sets forth the calculation of basic and diluted net income per common share (in thousands, except per share amounts):
4. Supplemental Disclosures of Cash Flow Information Supplemental cash flow information is as follows (in thousands):
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5. Acquisitions On June 8, 2011, the Company completed an acquisition, from an unrelated party, of oil properties and related assets in the East Bluebell area of the Uinta Basin (“East Bluebell Acquisition”) located in Duchesne and Uintah Counties in Utah. Total cash consideration given was approximately $116.8 million after post-closing adjustments. The purchase price allocation, after post-closing adjustments, is as follows (in thousands):
Amounts recognized for preliminary fair value of assets acquired and liabilities assumed:
On August 16, 2011, the Company completed an acquisition, from an unrelated party, of oil and gas properties and related assets in the Denver-Julesburg Basin (“DJ Basin Acquisition”) located in northeastern Colorado and southeastern Wyoming. Total cash consideration given was approximately $145.4 million, subject to final post-closing adjustments. The preliminary purchase price allocation, which is subject to final purchase price allocation adjustments, is as follows (in thousands):
Amounts recognized for preliminary fair value of assets acquired and liabilities assumed:
The East Bluebell Acquisition and DJ Basin Acquisition qualified as business combinations and, as such, the Company estimated the fair value of each property as of the respective acquisition dates, June 8, 2011 and August 16, 2011. To estimate the fair values of the properties as of the acquisition date, the Company used a net asset value approach. The Company utilized a discounted cash flow model that took into account the following inputs to arrive at estimates of future net cash flows:
To estimate the fair value of proved properties, the Company discounted the future net cash flows using a market-based rate that the Company determined appropriate at the acquisition date for the various proved reserve categories. To compensate for the inherent risk of estimating and valuing unproved properties, the Company reduced the discounted future net cash flows of the unproved properties by additional risk-weighting factors. Due to the unobservable nature of the inputs, the fair values of the proved and unproved oil and gas properties are considered Level 3 fair value measurements. The Company has not presented pro forma information for the acquired businesses as the impact of the acquisitions were not material to the consolidated balance sheet or results of operations for the three or nine months ended September 30, 2011. The results of operations from the East Bluebell Acquisition and the DJ Basin Acquisition are included in the Company’s consolidated financial statements from the acquisition dates of June 8, 2011 and August 16, 2011, respectively. Revenue related to the East Bluebell
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Acquisition that was included in the Company’s Unaudited Consolidated Statements of Operations was approximately $3.3 million for the three months ended September 30, 2011 and $3.8 million for the nine months ended September 30, 2011 and net income was insignificant. Revenue related to the DJ Basin Acquisition that was included in the Company’s Unaudited Consolidated Statements of Operations was approximately $1.7 million for both the three and nine months ended September 30, 2011 and net income was insignificant. 6. Long-Term Debt The Company’s outstanding debt is summarized below (in thousands):
Revolving Credit Facility On March 16, 2010, the Company amended its revolving 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 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 positions. As a result of issuing $400.0 million of 7.625% Senior Notes on September 27, 2011, the borrowing base was reduced to $700.0 million. 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. On October 18, 2011, the Company further amended the Amended Credit Facility which included extending the maturity date to October 31, 2016, increasing commitments to $900.0 million from 17 lenders and increasing the borrowing base to $1.1 billion based upon June 30, 2011 reserves and hedge positions. The amendment also decreased the interest margin to LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and reduced the commitment fee to between 0.375% to 0.5% based on borrowing base utilization. As of September 30, 2011, the Company had a zero balance outstanding under the Amended Credit Facility. As credit support for future payments 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. 9.875% Senior Notes Due 2016 The 9.875% Senior Notes 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. The 9.875% Senior Notes will mature on July 15, 2016. Interest is payable in arrears semi-annually on January 15 and July 15 each year. The 9.875% Senior Notes are fully and unconditionally guaranteed by the Company’s subsidiaries. The 9.875% 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.
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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 unsecured indebtedness. 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 Company’s subsidiaries. 7.625% Senior Notes Due 2019 On September 27, 2011, the Company issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes will mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 beginning April 1, 2012. The Company received net proceeds of $393.0 million (net of related offering costs), which were used to repay the outstanding borrowings under the Amended Credit Facility. The 7.625% Senior Notes 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. The 7.625% Senior Notes are fully and unconditionally guaranteed by the Company’s subsidiaries. The 7.625% 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 since issuance. The following table summarizes the cash portion of interest expense related to the Amended Credit Facility, 9.875% and 7.625% Senior Notes and Convertible Notes along with the non-cash portion of interest expense resulting from the amortization of debt discount and transaction costs through interest expense (in thousands):
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 DD&A expense in the Unaudited Consolidated Statements of Operations.
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A reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2011 is as follows (in thousands):
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. 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 set forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities as of September 30, 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 September 30, 2011
As of December 31, 2010
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.
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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 September 30, 2011, and for the nine months ended September 30, 2011, the Company did not have assets or liabilities that were measured on a recurring basis classified under a Level 3 fair value hierarchy. 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 and equipment. 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. The Company also applied fair value accounting guidance to measure the assets and liabilities acquired in the East Bluebell Acquisition and the DJ Basin Acquisition. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. The preliminary fair values of these items were primarily determined using the present value of estimated future cash inflows and outflows. Given the unobservable nature of these inputs, they are classified within Level 3. See Note 5 for additional discussion of the East Bluebell Acquisition and the DJ Basin Acquisition and disclosure of the inputs used to determine the preliminary fair value of the assets and liabilities acquired. 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 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 September 30, 2011 and December 31, 2010:
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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 September 30, 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 $45.3 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 gain (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 Sheets and the Unaudited Consolidated Statements of Operations for the periods indicated:
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.
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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 gain (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 gain (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 risk 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 gain (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. 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:
As of September 30, 2011, the Company had financial instruments in place to hedge the following volumes for the periods indicated:
The Company recognized a net increase in revenues related to natural gas, NGL and basis only hedges of $15.6 million and $52.5 million in the three and nine months ended September 30, 2011, respectively, and $44.6 million and $101.4 million for the three and nine months ended September 30, 2010, respectively. The Company also recognized a net increase related to oil hedges of $1.2 million for the three months ended September 30, 2011 and a net decrease of $2.0 million for the nine months ended September 30, 2011, and a net increase of $1.3 million and $2.4 million for the three and nine months ended September 30, 2010, respectively.
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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):
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. Two counterparties that were lenders in the Amended Credit Facility withdrew from the facility when the Company amended the facility in October 2011. The Company will continue to monitor the credit worthiness of these two counterparties during the remaining duration of the derivatives that were entered into while they were 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. 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 nine months ended September 30, 2011, there was no change to the Company’s liability for uncertain tax positions. The Company’s policy is to classify accrued interest and penalties 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 and nine months ended September 30, 2011. Due to the effect of state income taxes, stock-based compensation and other operating expenses that are not deductible for income tax purposes, income tax expense for the three and nine months ended September 30, 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. 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 September 30, 2011, all treasury stock held by the Company was retired.
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12. Accumulated Other Comprehensive Income The components of AOCI and related tax effects for the nine months ended September 30, 2011 were as follows:
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 and nine months ended September 30, 2011 and 2010 (in thousands):
Unrecognized compensation cost as of September 30, 2011 was $29.3 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 2.6 years. Stock Options and Nonvested Equity Shares. The following tables present the equity awards granted pursuant to the Company’s various stock compensation plans:
Performance Share Program. In February 2010, the Compensation Committee of the Board of Directors of the Company approved a 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 of common stock were set aside for this program under the 2008 Incentive Plan. 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
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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 shares of common stock that could vest will not exceed the original number of performance shares granted. At the end of four years, any shares that have not vested will be forfeited. 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, the Compensation Committee in February 2011 approved vesting of 25.9% of the total grant. The Company recorded the remaining non-cash stock-based compensation cost associated with these shares of $0.2 million for the nine months ended September 30, 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. In March 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 consist of annual production growth (weighted at 25%), increases to natural gas and oil proved, probable and possible 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 nine months ended September 30, 2011, the remaining nonvested 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. During the three months ended September 30, 2011, the Company granted an additional 640 performance-based nonvested equity shares of common stock at a fair value of $45.27. Of the total performance-based nonvested equity shares, 136,965 could potentially vest if all performance goals are met at the stretch level. Based upon the number of shares expected to vest through February 2012, at the estimated performance compared to the performance metrics at September 30, 2011, the Company recognized $0.7 million and $1.1 million of non-cash stock-based compensation expense associated with these shares for the three and nine months ended September 30, 2011, respectively. In March 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-share fair value of $39.88 on the new grant date. During the three months ended September 30, 2011, the Company granted an additional 160 market-based nonvested equity shares of common stock at a fair value of $45.27. The fair value of the market-based awards is amortized ratably over the remaining 2.5 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 $0.1 million and $0.4 million of non-cash stock-based compensation expense attributable to these awards for the three and nine months ended September 30, 2011, respectively. Director Fees. The Company’s non-employee, or outside, directors may elect to receive all or a portion of 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 of common stock with a value equal to the fees payable for that quarter, calculated using the closing price on the last trading day of the quarter, will be delivered to each outside director who elected before that quarter to receive shares for payment of 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 for the issuance of those shares:
Other Employee Benefits-401(k) Savings Plan. The Company has an employee-directed 401(k) savings plan (the “401(k) Plan”) for all eligible employees over the age of 21. 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 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 $0.3 million and $1.3 million for the three and nine months ended September 30, 2011, respectively, and $0.3 million and $1.3 million for the three and nine months ended September 30, 2010, respectively.
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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 matching cash 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 nine months ended September 30, 2011 (in thousands):
The Company is not obligated to contemporaneously fund the deferred compensation 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 year ended December 31, 2010 and the nine months ended September 30, 2011 (in thousands):
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14. Guarantor Subsidiaries In addition to the Amended Credit Facility, the 9.875% Senior Notes, the 7.625% Senior Notes and the Convertible Notes, which are registered securities, 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
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Condensed Consolidating Statements of Operations
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Condensed Consolidating Statements of Cash Flows
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The following discussion contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements as to 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:
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.
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Overview Bill Barrett Corporation together with our wholly-owned subsidiaries (“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 developing key existing development programs. Through exploration and acquisition, we seek high quality growth prospects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of natural gas and oil production at market prices, and revenues related to the sale of NGLs resulting from the processing of our natural gas by third parties, and the settlement of commodity hedges. As of December 31, 2010, our proved reserves were 1,118 Bcfe. We were formed in January 2002. Since inception, we substantially increased our activity level and the number of properties that we operate and our operating results reflect this growth. We began operations in March 2002 with the acquisition of properties in the Wind River Basin. From 2002 through 2009, we completed several acquisitions of properties in the Uinta, Piceance and Powder River Basins. 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. Consistent with our strategy of pursuing strategic and complementary acquisitions of developed and undeveloped properties in the Rocky Mountain region, we are continuously evaluating acquisition opportunities. On June 8, 2011, we acquired entities and oil properties in the Uinta Basin with a purchase price of approximately $116.8 million, after post-closing adjustments (the “East Bluebell Acquisition”). This acquisition was financed through borrowings under the Amended Credit Facility. On August 16, 2011, we acquired oil and gas properties in the Denver-Julesburg Basin for total cash consideration of approximately $145.4 million, which is subject to post-closing adjustments (the “DJ Basin Acquisition”). This acquisition was also financed through borrowings under the Amended Credit Facility. While there are currently no unannounced agreements for the acquisition of any material businesses or assets, future acquisitions could have a material impact on our financial condition and results of operations by increasing our proved reserves, production, and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under the Amended Credit Facility, other indebtedness, and/or debt, equity or equity-linked securities.
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Results of Operations The financial information for the three and nine months ended September 30, 2011 and 2010 that is discussed below is unaudited. In the opinion of management, such information contains all material adjustments, consisting only of normal and recurring adjustments, 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. Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010
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Before the effects of hedging, the average prices we received for natural gas and oil were as follows:
Production Revenues and Volumes. Production revenues increased to $573.1 million for the nine months ended September 30, 2011 from $535.0 million for the nine months ended September 30, 2010 due to an 8% increase in production partially offset by a 1% 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 gain (loss) within operating revenues in the Unaudited Consolidated Statements of Operations. See below for more information related to the commodity derivative gain (loss) line item. The net increase in production added approximately $40.3 million of production revenues, while the decrease in average realized price decreased production revenues by approximately $2.2 million. Total production volumes for the nine months ended September 30, 2011 of 77.7 Bcfe increased from 72.3 Bcfe for the nine months ended September 30, 2010 primarily due to increased production in the Piceance and Uinta Basins. The increase in production was partially offset by a decrease in production from the Wind River and Powder River Basins. Additional information concerning production is in the following table:
The production increase in the Piceance Basin was the result of our continued development activities with initial sales from 121 new gross wells from October 1, 2010 to September 30, 2011. The production increase in the Uinta Basin resulted from our development activities in the West Tavaputs area in the Uinta Basin with initial sales from 53 new gross wells from October 1, 2010 to September 30, 2011, as well as the acquisition of the East Bluebell field during the quarter ended June 30, 2011. In addition, we had increased production resulting from our ongoing development program at Blacktail Ridge and Lake Canyon in the Uinta Basin with initial sales from 27 new gross wells from October 1, 2010 to September 30, 2011. Further, we acquired producing wells within the DJ Basin on August 16, 2011, leading to production increases during the quarter ended September 30, 2011. The production decreases in the Wind River and Powder River Basins were due to natural production declines with no significant drilling or recompletion activities in our Wind River Basin properties or coalbed methane Powder River Basin properties to offset these declines. Hedging Activities. During the nine months ended September 30, 2011, approximately 67% of our natural gas volumes (excluding basis only swaps, which were equivalent to 8% of our natural gas volumes), 55% of our NGL related volumes and 67% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $52.5 million and a decrease in oil
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revenues of $2.0 million after settlements for all commodity derivatives, including basis only and NGL swaps. During the nine months ended September 30, 2010, approximately 74% of our natural gas volumes (excluding basis only swaps, which were equivalent to 14% of our natural gas volumes), 49% of NGL related volumes and 48% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $101.4 million and an increase in oil revenues of $2.4 million after settlements for all commodity derivatives, including basis only and NGL swaps. We may not be able to generate increases in revenue in the future as we did in the first nine months of 2011 as discussed above because hedges we entered into at higher prices are expiring, and we may be unable to enter into new hedges at those prices due to lower natural gas prices. The overall change in commodity derivative gain (loss) to a loss of $12.7 million for the nine months ended September 30, 2011 from a loss of $2.9 million for the nine months ended September 30, 2010 was due to a change in the unrealized gain on derivatives not designated as cash flow hedges from a $17.1 million gain for the nine months ended September 30, 2010 to an $8.9 million gain for the nine months ended September 30, 2011 primarily as a result of a decrease in the fair value of our basis only hedges. The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative gain (loss) for the periods indicated:
Lease Operating Expense. Lease operating expense decreased to $0.53 per Mcfe for the nine months ended September 30, 2011 from $0.54 per Mcfe for the nine months ended September 30, 2010. The nine months ended September 30, 2010 included $2.2 million of nonrecurring remediation efforts related to a minor condensate leak at the Dry Canyon Compressor Station in the Uinta Basin, which increased lease operating expense by $0.03 per Mcfe. The successful drilling program in our Blacktail Ridge field in the Uinta Basin throughout the nine months ended September 30, 2011 has increased water production. The additional trucking and disposal costs associated with this water production are primarily responsible for the increase in lease operating expense. As our development program in the Blacktail Ridge field continues to grow, we plan to add necessary infrastructure and scale to reduce future operating costs on a unit of production basis. Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $0.85 per Mcfe for the nine months ended September 30, 2011 from $0.72 per Mcfe for the nine months ended September 30, 2010. Increased production from the West Tavaputs field within the Uinta Basin has led to an increase in volumes gathered, transported and processed under higher cost structured agreements, which resulted in higher costs on a per unit basis. As a result, gathering, transportation and processing expense increased approximately $0.07 per Mcfe during the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. The increase in transportation costs related to West Tavaputs was primarily the result of firm transportation agreements that became effective in late July 2011 for the Ruby Pipeline as well as Wyoming Interstate Company (both contracts expire June 2021). The remaining increase on a per unit basis was attributed to new gathering and transportation agreements in Blacktail Ridge and the Piceance Basin, which added approximately $0.02 and $0.03 per Mcfe, respectively. Also, in September 2011 we incurred a one-time charge of $0.01 per Mcfe related to gathering agreements in the Paradox Basin. 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 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 $0.31 and $0.18 per Mcfe of firm transportation and gathering expense for the nine months ended September 30, 2011 and 2010, respectively, and $0.05 and $0.04 per Mcfe of firm processing expense from long-term contracts for the nine months ended September 30, 2011 and 2010, respectively. The increase in firm transportation and gathering expense to $0.31 per Mcfe for the nine months ended September 30, 2011 compared to $0.18 per Mcfe for the nine months ended September 30, 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 $29.3 million for the nine months ended September 30, 2011 from $25.5 million for the nine months ended September 30, 2010. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense increased during the nine months ended September 30, 2011 primarily due to a 22% increase in the wellhead values of production, excluding hedging activities, partially offset by a decrease in production tax rates. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 5.9% for the nine months ended September 30, 2011 compared to 6.2% for the nine months ended September 30, 2010.
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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 is consistent with our production decrease from states with higher production tax rates. Exploration Expense. Exploration expense decreased to $2.6 million for the nine months ended September 30, 2011 from $4.8 million for the nine months ended September 30, 2010. Exploration expense for the nine months ended September 30, 2011 consisted of $1.8 million of geological and geophysical seismic programs and $0.8 million for delay rentals across all basins. Exploration expense for the nine months ended September 30, 2010 consisted of $3.5 million for a well drilled for data gathering purposes, $0.3 million for seismic programs, $0.1 million for evaluation of non-acquired assets and $0.9 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 increased to $18.6 million during the nine months ended September 30, 2011 from $8.5 million during the nine months ended September 30, 2010. For the nine months ended September 30, 2011, impairment expense was $3.9 million, abandonment expense was $3.5 million, primarily in the Paradox Basin, and dry hole costs were $11.2 million. The $3.9 million non-cash impairment expense related to acreage within an exploration project that we no longer consider prospective. The $11.2 million in dry hole costs related to one unsuccessful exploratory well in the McRae Gap prospect of the Wind River Basin and two unsuccessful exploratory wells within the northern DJ Basin on acreage acquired prior to the DJ Basin Acquisition. For the nine months ended September 30, 2010, abandonment expense was $2.6 million and dry hole costs were $5.9 million. The $5.9 million in dry hole costs was associated with the partial expensing of one exploratory well in the Blacktail Ridge prospect of the Uinta Basin and the expensing of two unsuccessful exploratory wells in the Yellow Jacket prospect of the Paradox Basin. For the nine months ended September 30, 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”). DD&A was $210.4 million for the nine months ended September 30, 2011 compared to $191.6 million for the nine months ended September 30, 2010. The increase of $18.8 million was a result of an 8% increase in production for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010 coupled with a 2% increase in the DD&A rate. The increase in production accounted for $14.5 million of additional DD&A expense, while the overall increase in the DD&A rate accounted for a $4.3 million increase in DD&A expense. For the nine months ended September 30, 2011 and 2010, the weighted average DD&A rates were $2.71 per Mcfe and $2.65 per Mcfe, respectively. General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $36.5 million in the nine months ended September 30, 2011 from $30.6 million in the nine months ended September 30, 2010. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 28 for a reconciliation and explanation. This increase was primarily due to an increase in employee compensation and benefit programs for the nine months ended September 30, 2011 along with an increase in full time employees in our corporate office. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, increased to $0.47 per Mcfe for the nine months ended September 30, 2011 from $0.42 per Mcfe for the nine months ended September 30, 2010. Non-cash charges for stock-based compensation were $13.7 million for the nine months ended September 30, 2011 compared to $11.2 million for the nine months ended September 30, 2010. Non-cash stock-based compensation expense for both periods 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 three months of 2010 and during the nine months ended September 30, 2011. The components of non-cash stock-based compensation for the nine months ended September 30, 2011 and 2010 are shown in the following table:
Interest Expense. Interest expense increased to $38.4 million for the nine months ended September 30, 2011 from $32.5 million for the nine months ended September 30, 2010. The increase was primarily due to an increase in our weighted average outstanding debt balance, including our Amended Credit Facility, 5.0% Convertible Notes (“Convertible Notes”), 9.875% Senior Notes (“9.875% Senior Notes”) and 7.625% Senior Notes (“7.625% Senior Notes”), which was $510.1 million for the nine months ended September 30, 2011 compared to $403.2 million for the nine months ended September 30, 2010. The increase in our weighted average outstanding debt
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balance was primarily due to additional borrowings on the Amended Credit Facility during the nine months ended September 30, 2011. In addition, capitalized interest costs decreased during the nine months ended September 30, 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 nine months ended September 30, 2011, we had fewer projects in progress as compared to the nine months ended September 30, 2010, which resulted in a lower amount of interest costs that were capitalized during the period. We capitalized interest costs of $1.2 million and $3.5 million for the nine months ended September 30, 2011 and 2010, respectively. Income Tax Expense. Income tax expense totaled $39.5 million for the nine months ended September 30, 2011 compared to $52.2 million for the nine months ended September 30, 2010, resulting in effective tax rates of 36.6% and 37.3%, respectively. The decrease in income tax expense was primarily the result of the variations in revenue and expense components as discussed above and the resulting decrease in income. The effective tax rate decline was primarily the result of an increase in stock-based compensation deductible for tax purposes. Additionally, a greater proportion of our operating revenue was attributable to lower tax rate jurisdictions during the nine months ended September 30, 2011. The effect of this rate change on our prior year net deferred tax liability was included in income tax expense for the nine months ended September 30, 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 subject to different treatment for income tax purposes than for financial reporting purposes as well as the effect of state income taxes.
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Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010
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Before the effects of hedging, the average prices we received for natural gas and oil were as follows:
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