XNYS:KWK Quicksilver Resources, Inc. Quarterly Report 10-Q Filing - 3/31/2012
Effective Date 3/31/2012
| • FORM 10-Q • THIRTEENTH SUPPLEMENTAL INDENTURE • FOURTEENTH SUPPLEMENTAL INDENTURE • FIFTEENTH SUPPLEMENTAL INDENTURE • SIXTEENTH SUPPLEMENTAL INDENTURE • CERTIFICATION PURSUANT TO SECTION 302 • CERTIFICATION PURSUANT TO SECTION 302 • CERTIFICATION PURSUANT TO SECTION 906 • XBRL INSTANCE DOCUMENT • XBRL TAXONOMY EXTENSION SCHEMA • XBRL TAXONOMY EXTENSION CALCULATION LINKBASE • XBRL TAXONOMY EXTENSION DEFINITION LINKBASE • XBRL TAXONOMY EXTENSION LABEL LINKBASE • XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q
Commission file number: 001-14837 Quicksilver Resources Inc. (Exact name of registrant as specified in its charter)
(817) 665-5000 (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. Yes þ 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ 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. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
Table of ContentsDEFINITIONS As used in this Quarterly Report unless the context otherwise requires: “ABR” means alternate base rate “AOCI” means accumulated other comprehensive income “Bbl” or “Bbls” means barrel or barrels “Bbld” means barrel or barrels per day “Bcf” means billion cubic feet “Bcfe” means Bcf of natural gas equivalents “Canada” means our oil and natural gas operations located principally in British Columbia and Alberta, Canada “C$” means Canadian dollars “DD&A” means Depletion, Depreciation and Accretion “GPT” means gathering, processing and transportation expense “LIBOR” means London Interbank Offered Rate “MBbl” or “MBbls” means thousand barrels “MBbld” means MBbl per day “Mcf” means thousand cubic feet “Mcfe” means Mcf natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of gas “MMcf” means million cubic feet “MMcfd” means million cubic feet per day “MMcfe” means MMcf of natural gas equivalents “MMcfed” means MMcfe per day “NGL” or “NGLs” means natural gas liquids “OCI” means other comprehensive income “Oil” includes crude oil and condensate “RSU” means restricted stock unit COMMONLY USED TERMS Other commonly used terms and abbreviations include: “2007 Senior Secured Credit Facility” means collectively our U.S. senior secured revolving credit facility and our Canadian senior secured revolving credit facility, each dated as of February 9, 2007, which were terminated September 6, 2011 and replaced at that time by the Initial U.S. Credit Facility and the Initial Canadian Credit Facility “Amended and Restated Canadian Credit Facility” means our new Canadian senior secured revolving credit facility which was amended and restated, effective December 22, 2011 “Amended and Restated U.S. Credit Facility” means our new U.S. senior secured revolving credit facility which was amended and restated, effective December 22, 2011 “Bakken Asset” means our operations and our assets in the Southern Alberta basin in the Bakken formation of northern Wyoming and Montana, including our Cutbank field operations and assets “Barnett Shale Asset” means our operations and our assets in the Barnett Shale located in the Fort Worth basin of North Texas “BBEP” means BreitBurn Energy Partners L.P. “BBEP Unit” means BBEP limited partner unit “CMLP” means Crestwood Midstream Partners LP “Combined Credit Agreements” means collectively our Amended and Restated U.S. Credit Facility and our Amended and Restated Canadian Credit Facility “Crestwood” means Crestwood Holdings LLC “Crestwood Transaction” means the sale to Crestwood of all our interests in KGS, including general partner interests and incentive distribution rights “FASB” means the Financial Accounting Standards Board, which promulgates accounting standards in the U.S.
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Table of Contents“Fortune Creek” means Fortune Creek Gathering and Processing Partnership, a midstream partnership formed in December 2011 with KKR dedicated to the construction and operation of natural gas midstream services within Horn River “GAAP” means accounting principles generally accepted in the U.S. “Horn River Asset” means our operations and our assets in the Horn River basin of Northeast British Columbia “Horseshoe Canyon Asset” means our operations and our assets in Horseshoe Canyon, the coalbed methane fields of southern and central Alberta “Initial Canadian Credit Facility” means our initial Canadian senior secured revolving credit facility, dated as of September 6, 2011, which was amended and restated by the Amended and Restated Canadian Credit Facility on December 22, 2011 “Initial U.S. Credit Facility” means our initial U.S. senior secured revolving credit facility, dated as of September 6, 2011, which was amended and restated by the Amended and Restated U.S. Credit Facility on December 22, 2011 “KGS” means Quicksilver Gas Services LP, a publicly-traded partnership, which we formerly owned that traded under the ticker symbol of “KGS” and subsequent to the Crestwood Transaction renamed itself Crestwood Midstream Partners LP and trades under the ticker symbol “CMLP” “KKR” means the Kohlberg Kravis Roberts & Co. L.P. with whom we formed Fortune Creek “Mercury” means Mercury Exploration Company, which is owned by members of the Darden family “NGTL” means NOVA Gas Transmission Ltd., a subsidiary of TransCanada PipeLines Limited “NGTL Project” means the series of contracts with NGTL for the construction of a pipeline and meter station, which will serve our and others’ operations in the Horn River basin “Sand Wash Asset” means our operations and our assets in the Sand Wash basin located in Colorado and southern Wyoming “SEC” means the U.S. Securities and Exchange Commission “VIE” means variable interest entity “West Texas Asset” means our operations and our assets in the Midland and Delaware basins in West Texas prospective in the Bone Springs and Wolfcamp formations, principally concentrated in four areas: Jeff Davis and Reeves Counties, Upton and Crockett Counties, Pecos County and Presidio County
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Table of ContentsINDEX TO QUARTERLY REPORT ON FORM 10-Q For the Quarter Ended March 31, 2012
Except as otherwise specified and unless the context otherwise requires, references to the “Company,” “Quicksilver,” “we,” “us,” and “our” refer to Quicksilver Resources Inc. and its subsidiaries.
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Table of ContentsForward-Looking Information Certain statements contained in this Quarterly Report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict, and are subject to material uncertainties that may affect actual results and may be beyond our control. The forward-looking statements included in this Quarterly Report are made only as of the date of this Quarterly Report, and we undertake no obligation to update any of these forward-looking statements to reflect subsequent events or circumstances except to the extent required by applicable law. All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.
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QUICKSILVER RESOURCES INC. CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) In thousands, except for per share data – Unaudited
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Table of ContentsQUICKSILVER RESOURCES INC. CONDENSED CONSOLIDATED BALANCE SHEETS In thousands, except for share data – Unaudited
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Table of ContentsQUICKSILVER RESOURCES INC. CONDENSED CONSOLIDATED STATEMENTS OF EQUITY In thousands – Unaudited
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Table of ContentsQUICKSILVER RESOURCES INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS In thousands – Unaudited
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Table of ContentsQUICKSILVER RESOURCES INC. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Unaudited 1. ACCOUNTING POLICIES AND DISCLOSURES The accompanying condensed consolidated interim financial statements have not been audited. In management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to fairly present our financial position as of March 31, 2012 and our results of operations and cash flows for the three months ended March 31, 2011 and 2012. All such adjustments are of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results. The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates. Certain disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2011 Annual Report on Form 10-K. Immaterial Restatement The consolidated financial statements as of and for the year ended December 31, 2010 were restated as disclosed within Item 8, Note 2 in the 2011 Annual Report on Form 10-K to increase the previously recognized gain related to the sale of our interests in KGS by $20.7 million and to provide additional deferred taxes on the increased gain. The previously reported gain excluded certain liabilities for intercompany transactions related to services performed by KGS for our U.S. exploration and production segment, which should have been included in the gain calculation. Additional depletion expense was recognized due to the inclusion of additional future development costs in the 2010 depletion calculation. The results of this restatement, which had no impact on our total cash flow from operations, investing and financing activities as reported, impacted the retained earnings and the total stockholder’s equity as of March 31, 2011. Previously, retained earnings and total stockholder’s equity were reported as $183.3 million and $968.3 million, respectively, in the Form 10-Q for the quarter ended March 31, 2011. These balances have been restated to $193.8 million and $978.8 million, respectively, within the Condensed Consolidated Statement of Equity as of March 31, 2011. Recently Issued Accounting Standards Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. In June 2011, the FASB issued an amendment to accounting guidance to update the presentation of comprehensive income in consolidated financial statements. Under the amended guidance, the presentation of total comprehensive income, the components of net income, and the components of other comprehensive income may be made either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance became effective for us beginning with the quarter ended March 31, 2012, and requires retrospective application to earlier periods presented. Our condensed consolidated statements of income and comprehensive income for the three months ended March 31, 2012 and 2011 contain the required disclosure. The implementation of this accounting pronouncement resulted in increased disclosure in Note 12. In May 2011, the FASB issued an amendment to the accounting guidance for fair value measurement and disclosure. Among other things, the guidance expands the disclosure requirements around fair value measurements categorized in Level 3 of the fair value hierarchy and requires disclosure of the level in the fair
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Table of Contentsvalue hierarchy of items that are not measured at fair value in the statement of financial position but whose fair value must be disclosed. It also clarifies and expands upon existing requirements for measurement of the fair value of financial assets and liabilities as well as instruments classified in shareholders’ equity. This guidance became effective for us beginning with the quarter ended March 31, 2012. The adoption of this accounting pronouncement did not have an effect on the fair value measurement, but rather expanded upon existing disclosures. In December 2011, the FASB issued an amendment to the accounting guidance for disclosure of arrangements that permit offsetting assets and liabilities. The amendment expands the disclosure requirements to require both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The amendment is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013, and shall be applied retrospectively. We do not expect the adoption of this accounting pronouncement to have a material impact on our financial statements when implemented. No other pronouncements materially affecting our financial statements have been issued since the filing of our 2011 Annual Report on Form 10-K. 2. CRESTWOOD EARN-OUT In October 2010, we completed the sale of all of our interests in KGS to Crestwood. As part of the sale, we have the right to collect future earn-out payments through 2013. In February 2012, we collected $41 million of these earn-out payments which is presented as Crestwood earn-out in the condensed consolidated statement of income for the quarter ended March 31, 2012. We have the right to collect up to an additional $31 million in future earn-out payments in 2013, although we have recognized no assets related to these opportunities. Note 3 to the consolidated financial statements in our 2011 Annual Report on Form 10-K contains additional information regarding the Crestwood Transaction. 3. DERIVATIVES AND FAIR VALUE MEASUREMENTS The following table categorizes our commodity derivative instruments based upon the use of input levels:
The fair value of “Level 2” derivative instruments included in these disclosures was estimated using prices quoted in active market for the periods covered by the derivatives and the value reported by counterparties. The fair value of derivative instruments designated “Level 3” was estimated using prices quoted in markets where there is insufficient market activity for consideration as “Level 2” instruments. Currently, only our natural gas hedges with an original tenure of 10 years utilize “Level 3” inputs, primarily due to comparatively less market data available for the later portion of their term compared with our other shorter term hedges. The fair value of both the “Level 2” and the “Level 3” assets and liabilities are determined using discounted cash flow model based on the terms of the derivative instrument, market prices for the periods covered by the derivatives, and the risk-free interest rates. The “Level 3” unobservable inputs are the market prices for the latter half of the 10-year term as there is not an active market for that period of time. These unobservable inputs included within the fair value calculation range from $3.66 to $5.94 and are calculated using prices quoted in active markets for the period of time available and applying the differential from this period of time to the markets prices for the later years in the term. Changes in the “Level 3” inputs are correlated to the changes in the quoted market prices for the period of time available. Estimates were
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Table of Contentsdetermined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at the risk free rate. The following table identifies the changes in “Level 3” net asset derivative fair values for the periods indicated:
Commodity Price Derivatives As of March 31, 2012, we had price collars and swaps hedging our anticipated natural gas and NGL production as follows:
Interest Rate Derivatives In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We received cash of $41.5 million in the settlements, including $10.7 million for interest previously accrued and earned. Upon the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain of $30.8 million as a reduction of interest expense over the lives of our senior notes due 2015 and our senior subordinated notes. During both the 2012 quarter and the 2011 quarter, we recognized $1.2 million of those deferred gains as a reduction of interest expense. The remaining $20.7 million deferral of the 2010 early settlements from all interest rate swaps will continue to be recognized as a reduction of interest expense over the life of the associated underlying debt instruments currently scheduled as follows:
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Table of ContentsFair Value Disclosures The estimated fair value of our derivative instruments at March 31, 2012 and December 31, 2011 were as follows:
The increase in carrying value of our commodity price derivatives since December 31, 2011 principally resulted from the overall decrease in market prices for natural gas relative to the prices in our open derivative instruments as well as additional derivative instruments entered into during the three months ended March 31, 2012. The changes in the carrying value of our derivatives for the three months ended March 31, 2012 and 2011 are presented below:
Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months would result in a gain of $142.6 million net of income taxes. Hedge derivative ineffectiveness resulted in net losses of $3.2 million and $0.1 million for the three months ended March 31, 2012 and 2011, respectively. In January and February 2012, we terminated a number of our ten-year derivative instruments in exchange for derivative instruments with shorter durations at above market terms. The decrease in the fair value between the terminated ten-year instrument and the new shorter-term instrument was recognized in the current period as a realized loss. Unrealized losses recognized in 2012 is the difference between the estimated fair value at the inception date and transaction cost for ten-year derivative instruments entered into during the period.
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Table of Contents4. INVESTMENT IN BBEP At March 31, 2011, we owned 15.6 million BBEP Units, or 26%, of BBEP, whose price closed at $21.73 per unit as of that date. During the fourth quarter of 2011, we sold all of our remaining BBEP Units. Changes in the balance of our investment in BBEP for the three months ended March 31, 2011 were as follows:
We accounted for our investment in BBEP Units using the equity method, utilizing a one-quarter lag from BBEP’s publicly available information. Summarized estimated financial information for BBEP is as follows:
5. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consisted of the following:
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Table of ContentsCeiling Test Analysis We recorded impairment expense of $62.3 million and $0.4 million for our U.S. and Canadian oil and gas properties, respectively, at March 31, 2012. For our U.S. oil and gas properties, we computed the March 31, 2012 ceiling amount using a Henry Hub price of $3.73 MMBtu of natural gas, calculated as the unweighted average of the preceding 12-month first-day-of-the-month prices. The Henry Hub natural gas price used to compute the ceiling amount at March 31, 2012 was 9.5% lower than the comparable price used at December 31, 2011. For our Canadian oil and gas properties, we computed the March 31, 2012 ceiling amount using an AECO price of $3.64 MMBtu of natural gas, calculated as the unweighted average of the preceding 12-month first-day-of-the-month prices. The AECO natural gas price used to compute the ceiling amount at March 31, 2012 was 1% lower than the comparable price used at December 31, 2011. As of March 31, 2012, our U.S. and Canadian ceiling tests included $252 million and $103 million, respectively, in value for our derivatives treated as hedges. Absent this recognition, after tax we would have recognized $164 million of additional impairment expense for our U.S. oil and gas properties and $78 million for our Canadian oil and gas properties. Because of the volatility of oil and natural gas prices and prevailing prices subsequent to March 31, 2012, it is reasonably possible we may experience additional impairment in future periods. Notes 2 and 8 to the consolidated financial statements in our 2011 Annual Report on Form 10-K contain additional information regarding our property, plant and equipment and our quarterly ceiling test analysis. 6. LONG-TERM DEBT Long-term debt consisted of the following:
Credit Facilities The Combined Credit Agreements’ global borrowing base remained at $1.075 billion and the global letter of credit capacity was $175 million. At March 31, 2012, we had $679 million available under the facility. Summary of All Outstanding Debt As of March 31, 2012, the following subsidiaries are guarantors under our indentures for our senior notes and senior subordinated notes: Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P.,
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Table of ContentsSilver Stream Pipeline Company LLC and Barnett Shale Operating LLC. The following table summarizes other significant aspects of our long-term debt outstanding at March 31, 2012:
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Note 11 to the consolidated financial statements in our 2011 Annual Report on Form 10-K contains a more complete description of our long-term debt. 7. ASSET RETIREMENT OBLIGATIONS The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the three months ended March 31, 2012.
8. COMMITMENTS AND CONTINGENCIES Contractual Obligations, Commitments and Contingencies On July 26, 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arises out of press releases in 2011 questioning the projected decline curves and economics of shale gas wells. There have been no significant changes to our contractual obligations and commitments as reported in our 2011 Annual Report on Form 10-K which contains a more complete description of our contractual obligations, commitments and contingencies. 9. FORTUNE CREEK In December 2011, we entered into an agreement to form a midstream partnership, Fortune Creek, dedicated to the construction and operation of midstream assets to support natural gas producers primarily in British Columbia.
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Table of ContentsThe partnership established an area of mutual interest for the midstream business covering approximately 30 million potential acres which includes transportation and processing infrastructure and agreements. In connection with the partnership formation, we contributed an existing 20-mile, 20-inch gathering line, its related compression facilities, we committed to minimum annual capital expenditures of $100 million for drilling and completion activities in our Horn River Asset for 2012, 2013 and 2014, and we dedicated for ten years beginning 2012 gas production from our Horn River Asset, as more fully described below. KKR contributed $125 million cash in exchange for a 50% interest in the partnership. Our Canadian subsidiary has responsibility for the day-to-day operations of Fortune Creek. Our Canadian subsidiary entered into a firm gathering agreement with Fortune Creek which is guaranteed by us. At our election, KKR has the responsibility to fund all of the capital contributions associated with the development of the new gas treatment facility in exchange for preferential cash flow distributions. If our subsidiary does not meet its obligations under the gathering agreement, KKR has the right to liquidate the partnership and consequently we have recorded the funds contributed by KKR as a liability in our consolidated financial statements. We recognize accretion expense to reflect the rate of return earned by KKR via its investment. Based on an analysis of the entities equity at risk, we have determined the partnership to be a VIE. Further, based on our ability to direct the activities surrounding the production of natural gas and our direct management of the operations of the facilities, we have determined we are the primary beneficiary and therefore, we consolidate Fortune Creek. Note 12 contains financial information for Fortune Creek in our condensed consolidating financial statements. 10. QUICKSILVER STOCKHOLDERS’ EQUITY Common Stock, Preferred Stock and Treasury Stock We are authorized to issue 400 million shares of common stock with a $0.01 par value per share and 10 million shares of preferred stock with a $0.01 par value per share. At March 31, 2012 and December 31, 2011, we had 173.3 million and 171.6 million shares of common stock outstanding, respectively. Note 17 to the consolidated financial statements in our 2011 Annual Report on Form 10-K contains additional information about our equity-based compensation plan. Stock Options Options to purchase shares of common stock were granted in 2012 with an estimated fair value of $8.4 million. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the three months ended March 31, 2012:
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Table of ContentsThe following table summarizes our stock option activity for the three months ended March 31, 2012:
As of March 31, 2012 we estimate that a total of 5.5 million stock options will become vested including those options already exercisable. Compensation expense related to stock options of $1.9 million was recognized for each of the three months ended March 31, 2012 and 2011. Cash received from the exercise of stock options totaled less than $0.1 million for the three months ended March 31, 2012. The total intrinsic value of those options exercised was less than $0.1 million. Restricted Stock The following table summarizes our restricted stock and stock unit activity for the three months ended March 31, 2012:
As of December 31, 2011, the unrecognized compensation cost related to outstanding unvested restricted stock was $17.3 million, which is expected to be recognized in expense through March 2014. Grants of restricted stock and RSUs during the three months ended March 31, 2012 had an estimated grant date fair value of $20.4 million. The fair value of RSUs settled in cash was $2.9 million at March 31, 2012. For the three months ended March 31, 2012 and 2011, compensation expense of $4.0 million and $3.6 million, respectively, was recognized. The total fair value of shares vested during the three months ended March 31, 2012 was $9.5 million.
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Table of Contents11. EARNINGS PER SHARE The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income per common share.
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Table of Contents12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION Note 19 to the consolidated financial statements in our 2011 Annual Report on Form 10-K contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted subsidiaries. The following tables present financial information about Quicksilver and our restricted subsidiaries for the three-month periods covered by the consolidated financial statements. Under the indentures for our senior notes and senior subordinated notes, Fortune Creek is not considered to be a subsidiary and therefore it is presented separately from the other subsidiaries for these purposes. Condensed Consolidating Balance Sheets
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Table of ContentsCondensed Consolidating Statements of Income
Condensed Consolidating Statements of Cash Flows
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13. SEGMENT INFORMATION We operate in two geographic segments, the U.S. and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. Additionally, we operate a significantly smaller midstream segment in the U.S. and Canada, where we provide natural gas gathering and processing services. Following our announced partnership with KKR, beginning in January 2012, we have additional midstream operations in Canada through Fortune Creek. Based on the immateriality of our midstream segment, we have combined U.S. and Canadian information. We evaluate performance based on operating income and property and equipment costs incurred.
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Table of Contents14. SUPPLEMENTAL CASH FLOW INFORMATION Cash paid (received) for interest and income taxes was as follows:
Other significant non-cash transactions were as follows:
15. TRANSACTIONS WITH RELATED PARTIES As of March 31, 2012, members of the Darden family and entities controlled by them beneficially own approximately 30% of our outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of Quicksilver. During the first three months of 2012 and 2011, we paid $0.1 million and $0.2 million, respectively, for use of an airplane owned by an entity controlled by members of the Darden family. Usage rates were determined based upon comparable rates charged by third parties. Payments received from Mercury for sublease rentals, employee insurance coverage and administrative services were negligible for the first three months of 2012 and 2011.
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The following Management’s Discussion and Analysis (“MD&A”) is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Quarterly Report as well as our 2011 Annual Report on Form 10-K. We conduct our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller midstream segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis. Our MD&A includes the following sections:
2012 HIGHLIGHTS Master Limited Partnership On February 10, 2012, we filed a Form S-1 with the SEC to begin the registration and sale of limited partnership interests in a master limited partnership holding certain of our mature properties in our Barnett Shale Asset. We expect to amend the registration statement in late May to include financial statements for 2011 and to address comments received from the SEC. We expect this registration statement to become effective in the second or third quarter of 2012. Emerging Basins We deployed a rig in March 2012 to commence drilling operations on our West Texas Asset. Our plan for 2012 is to drill and complete up to five wells. We hold a position of approximately 155,000 net acres in the Delaware and Midland basins, at least 2/3 of which we believe is prospective for oil, including from the Wolfcamp and Bone Springs formations. In the first quarter of 2012, we retained an investment bank to help evaluate the opportunities for a joint venture partner to acquire an interest in and participate in the development of our West Texas acreage. We set surface pipe on one well during the first quarter in our Sand Wash Asset, however wildlife stipulations prevent us from finishing the drilling process until September 2012. We expect to begin drilling operations on additional wells in May 2012. We plan to drill a mix of four to seven vertical and horizontal wells in 2012. We hold approximately 260,000 net acres in the Sand Wash Basin, at least 200,000 of which are prospective of oil. At December 31, 2011, we had recognized no proved oil reserves in our Sand Wash Asset. Crestwood Earn-Out In October 2010, we completed the sale of all of our interests in KGS to Crestwood. As part of the sale, we have the right to collect future earn-out payments through 2013. In February 2012, we collected $41 million of these earn-out payments, which is presented as Crestwood earn-out in the condensed consolidated statement of income for the quarter ended March 31, 2012. We have the right to collect up to an additional $31 million in future earn-out payments in 2013, although we have recognized no assets related to these opportunities. 2012 CAPITAL PROGRAM We had capital expenditures of $174.9 million for the first three months of 2012. We expect our capital spending for the remainder of 2012 to be in line with the 2012 capital program as presented in the 2011 Annual Report on Form 10-K.
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Table of ContentsAverage production for the second quarter of 2012 is expected to be flat with first quarter 2012. RESULTS OF OPERATIONS The following discussion compares the results of operations for the three months ended March 31, 2012 and 2011, or the 2012 quarter and 2011 quarter, respectively. “Other U.S.” refers to the combined amounts for our Sand Wash Asset and Bakken Asset. Revenue Natural Gas, NGL and Oil Production Revenue:
Average Daily Production Volume:
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Table of ContentsAverage Realized Price:
The following table summarizes the changes in our natural gas, NGL and oil revenue:
Natural gas revenue for the 2012 quarter decreased from the 2011 quarter despite the increase in hedge revenue. Realized prices, without hedge gains, were 35% lower for the 2012 quarter as compared to the 2011 quarter. The 5% decrease in natural gas volume from our Barnett Shale Asset was primarily due to production decline resulting from the aging of existing wells and our capital spending pattern. NGL revenue for the 2012 quarter was higher than the 2011 quarter as a result of hedge losses recognized in the 2011 quarter of $7.2 million. Utilization of derivatives to hedge our sales of natural gas and NGL may result in realized prices varying from market prices that we receive from the sale of our production. Our production revenue for the 2012 quarter and 2011 quarter was higher by $48.8 million and $24.0 million, respectively, because of our hedging activities. We are engaged in the process of reviewing the economic impact of continuing to produce from certain of our wells in the current price environment. As a result, we may shut-in wells. However, we believe these shut-ins would result in increases to operating income and operating cash flows, and have only an immaterial impact on our production volumes.
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Table of ContentsSales of Purchased Natural Gas and Costs of Purchased Natural Gas
Other Revenue
Other revenue for the three months ended March 31, 2012 decreased from the 2011 quarter due to the recognition of realized losses in 2012 from our restructuring of our hedge platform. In January and February 2012, we terminated a number of our ten-year derivative instruments in exchange for derivative instruments with shorter durations at above market terms. The decrease in the fair value between the terminated ten-year instrument and the new shorter-term instrument was recognized in the current period as a realized loss. Losses from hedge ineffectiveness were $3.2 million for the 2012 quarter as compared to less than $0.1 million for the 2011 quarter as our derivative instruments are based on NYMEX pricing and our production is sold at market prices other than NYMEX. At March 31, 2012, we do not have any basis swaps to offset the price differential. Unrealized losses recognized in 2012 is the difference between the estimated fair value at the inception date and transaction cost for ten-year derivative instruments entered into during the period.
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Table of ContentsOperating Expense Lease Operating
The Barnett Shale Asset experienced higher gas lift costs, workover expense and saltwater disposal costs compared to prior year due to the aging of existing wells and costs to maintain production. Other U.S. lease operating costs were impacted on a gross and unit basis by increased production and costs for our Sand Wash Asset. Lease operating expense for the 2012 quarter in Canada was flat compared to the 2011 quarter.
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Table of ContentsGathering, Processing and Transportation
Canadian GPT increased for the 2012 quarter as compared to 2011 quarter both in total dollars and on a per Mcfe basis primarily as a result of fixed costs under our firm agreements with third parties. GPT per Mcfe was flat in the U.S. Production and Ad Valorem Taxes
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Table of ContentsDepletion, Depreciation and Accretion
U.S. depletion for the 2012 quarter reflected a 12% increase in the U.S. depletion rate partially offset by a 4% decrease in U.S. production when compared to the 2011 quarter. Canadian depletion decreased in 2012 due to a reduction in the carrying value of the Canadian oil and gas properties in the 2011 quarter. Following the impairment recognized in the 2012 quarter, we expect U.S. and Canadian depletion rates will be relatively unchanged. U.S. depreciation for the 2012 quarter was lower than the 2011 quarter primarily because of reduced carrying value of our midstream assets following their impairment in late 2011. Canada depreciation was higher due to the increased capital spending on the Fortune Creek non-oil and gas properties in the second half of 2011. Impairment Expense As required under GAAP, we perform quarterly ceiling tests to assess impairment of our oil and gas properties. We also assess our fixed assets reported outside the full-cost pool when circumstances indicate impairment may have occurred. The calculation of impairment expense is more fully described in Note 5 to the condensed consolidated financial statements in Item 1 of this Quarterly Report. In the 2012 quarter, we recognized $62.3 million and $0.4 million in non-cash charges for impairment of our U.S. and Canadian oil and gas properties, respectively, as of March 31, 2012. In performing our quarterly ceiling tests, we utilize first of month prices for the preceding 12 months. Due to the decrease in natural gas prices in the second quarter 2012 compared to the second quarter 2011, there is a significant likelihood of impairment of oil and gas properties. As of March 31, 2012, our U.S. and Canadian ceiling tests included $252 million and $103 million, respectively, in value for our derivatives treated as hedges. Absent this recognition, after tax we would have recognized $164 million of additional impairment expense for our U.S. oil and gas properties and $78 million for our Canadian oil and gas properties. If any of our derivatives we treat as hedges become ineligible for hedge treatment, it could significantly impact the amount of impairment that we recognize.
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Table of ContentsGeneral and Administrative
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