Item 1 of this report under the heading “Properties.” U.S. borrowings under our senior secured credit facility are secured by our and certain of our domestic subsidiaries’ oil and gas properties, and Canadian borrowings under our senior secured credit facility are secured by QRCI’s, our and certain of our domestic subsidiaries’ oil and gas properties.
OIL AND GAS RESERVES
The following reserve quantity and future net cash flow information concerns our proved reserves that are located in the United States and Canada. Independent petroleum engineers with Schlumberger Data and Consulting Services and LaRoche Petroleum Consultants, Ltd. prepared our reserve estimates for our United States and Canadian properties, respectively. Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10(a) 2(i), 2(ii), 2(iii), (3) and (4), are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided by contractual arrangements, but not of escalations based upon expected future conditions. Prices include the effect of our derivative instruments. Future production and development costs include production and property taxes.
Proved developed oil and gas reserves are reserves that are expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for re-completion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.
The reserve data set forth in this document represents only estimates and is subject to inherent uncertainties. The determination of oil and gas reserves is based on estimates that are highly complex and interpretive. Reserve engineering is a subjective process that is dependent on the quality of available data and on engineering and geological interpretation and judgment. Although we believe the reserve estimates contained in this document are reasonable, reserve estimates are imprecise and are expected to change as additional information becomes available.
The following table summarizes our proved reserves and the standardized measure of discounted future net cash flows attributable to them at December 31, 2006, 2005 and 2004.
(1)
The natural gas and crude oil prices as of each respective year end were based, respectively, on NYMEX Henry Hub prices per MMBtu and NYMEX prices per Bbl, as adjusted to reflect local differentials.
(2)
Determined based on year-end unescalated prices and costs in accordance with the guidelines of the SEC, discounted at 10% per annum.
VOLUMES, SALES PRICES AND OIL AND GAS PRODUCTION EXPENSE
The following table sets forth certain information regarding production, average unit prices and costs for the periods indicated:
(1)
Includes production and ad valorem taxes.
DRILLING ACTIVITY
During the periods indicated, the Company drilled or participated in the drilling of the following exploratory and development wells:
ACQUISITION, EXPLORATION AND DEVELOPMENT CAPITAL EXPENDITURES
PRODUCTIVE OIL AND GAS WELLS
The following table summarizes productive oil and gas wells attributable to our direct interests as of December 31, 2006:
OIL AND GAS ACREAGE
Our principal natural gas and crude oil properties consist of non-producing and producing natural gas and crude oil leases, including reserves of natural gas and crude oil in place. The table found below indicates our interest in developed and undeveloped acreage held directly by us. Developed acres are defined as acreage spaced or allocated to wells that are producing or capable of producing. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil, condensate or natural gas, regardless of whether or not such acreage contains proved reserves. Gross acres are the total number of acres in which we have a working interest. Net acres are the sum of our fractional interests owned in the gross acres.
The following table lists the total number of net undeveloped acres as of December 31, 2006, and, with respect to those acres for 2007, 2008 and 2009, the number of net acres expiring, and, where applicable, the number of net acres expiring that are subject to options to extend. The option to extend varies from lease to lease and covers periods from one to five years; however, the majority of the options to extend are for two years.
All of the acreage scheduled to expire can be held through drilling operations. We believe that we have the ability to hold all of the expiring acreage that we feel is prospective of economic production through the drilling of wells and, where applicable, through the exercise of extension options to be followed by drilling prior to final expiration.
ITEM 3.
Legal Proceedings
In August 2001, a group of royalty owners, Athel E. Williams et al., brought suit against the Company and three of its subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd., one of Quicksilver’s subsidiaries, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who have yet to be determined. The pleadings of the plaintiffs seek damages in an unspecified amount and injunctive relief against future underpayments. On January 21, 2005, the Circuit Court issued an order certifying certain claims to proceed on behalf of a class. On July 25, 2006, the Michigan Court of Appeals reversed the certification of all claims on appeal and remanded the case to the trial court for further proceedings. Based on information currently available to us, we believe that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.
On October 13, 2006, we filed suit in the 342nd Judicial District Court in Tarrant County, Texas against Eagle Drilling, LLC and Eagle Domestic Drilling Operations, LLC (successor in interest to Eagle Drilling, together “Eagle”) regarding three contracts for drilling rigs in which we allege that the first rig furnished by Eagle exhibited operating deficiencies and safety defects. We seek a declaratory judgment that (i) the contracts are void and (ii) that Eagle is not entitled to early termination compensation provided for in the contracts. We also seek rescission of the contracts and claim we are entitled to recover damages incurred due to Eagle’s failure to perform. On October 23, 2006, Eagle Domestic Drilling sued us in District Court of Cleveland County, Oklahoma for (i) breach of contract as to each of the three drilling contracts alleging damages of $29 million plus punitive damages and interest and (ii) tortious breach of contract alleging damages in an unspecified amount in excess of $10,000. Eagle Domestic Drilling also sought a declaratory judgment that, among other things, the contracts are valid and binding. Subsequently, on January 19, 2007, Eagle Domestic Drilling and its parent, Blast Energy Services, Inc., filed for Chapter 11 bankruptcy the United States Bankruptcy Court for the Southern District of Texas, Houston Division. At the date of this filing, the suit in Tarrant County is still pending, but is stayed. On February 21, 2007, the lawsuit in Cleveland County was dismissed. Based upon information currently available, we believe that the final resolution of this matter will not have a material effect on our financial condition, results of operations, or cash flows.
ITEM 4.
Submission of Matters to a Vote of Security Holders
There were no matters submitted to a stockholder vote during the fourth quarter of 2006.
PART II.
ITEM 5.
Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities
Market Information
Our common stock is traded on the New York Stock Exchange under the symbol “KWK.”
The following table sets forth the quarterly high and low sales prices of our common stock for the periods indicated below.
(1)
Stock prices been have adjusted to reflect a three-for-two stock split effected in the form of a stock dividend in June 2005.
As of February 15, 2007, there were approximately 561 common stockholders of record.
We have not paid dividends on our common stock and intend to retain our cash flow from operations for the future operation and development of our business. In addition, our senior secured credit facility prohibits payments of dividends on our common stock and purchases of common stock. The indenture for our senior subordinated notes prohibits payments on our common stock.
Performance Graph
The following performance graph compares the cumulative total stockholder return on Quicksilver common stock with the Standard & Poor’s 500 Stock Index (the “S&P 500”) and the Dow Jones U.S. Exploration and Production Index (formerly the Dow Jones Secondary Oils Index) for the period from December 31, 2001 to December 31, 2006, assuming an initial investment of $100 and the reinvestment of all dividends, if any.
Comparison of Cumulative Five Year Total Return
Issuer Purchases of Equity Securities
The following table summarizes the Company’s repurchases of its common stock during the quarter ended December 31, 2006.
(1)
Represents shares of common stock surrendered by employees to satisfy the Company’s income tax withholding obligations arising upon the vesting of restricted stock issued under our Amended and Restated 1999 Stock Option and Retention Plan.
(2)
The Company does not currently have in place any publicly announced, specific plans or programs to purchase equity securities.
ITEM 6.
Selected Financial Data
The following table sets forth, as of the dates and for the periods indicated, our selected financial information. Our financial information is derived from our audited consolidated financial statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes thereto contained in this document. The following information is not necessarily indicative of our future results.
Selected Financial Data
(1)
Per share amounts have been adjusted to reflect a two-for-one stock split effected in the form of a stock dividend in June 2004 and a three-for-two stock split effected in the form of a stock dividend in June 2005.
(2)
Working capital consists of current assets and current liabilities, which include derivative contracts at estimated fair value and the related deferred income taxes.
ITEM 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following Management’s Discussion and Analysis (“MD&A”) is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Annual Report on Form 10-K, including: “Item 1. Business,” “Item 2. Properties,” “Item 6. Selected Financial Data,” and “Item 8. Financial Statements and Supplementary Data.” Our MD&A includes the following sections:
•
Overview - a general description of our business; the value drivers of our business; measurements; and opportunities, challenges and risks.
•
Financial Risk Management - information about debt financing and financial risk management.
•
Application of Critical Accounting Policies - a discussion of accounting policies that represent choices between acceptable alternatives and/or require critical judgments and estimates.
•
Results of Operations - an analysis of our consolidated results of operations for the three years presented in our financial statements. We continue to operate in the business of development, exploitation, exploration and production of natural gas, NGLs and crude oil. Except to the extent that differences between our geographic operating segments are material to an understanding of our business as a whole, we present this MD&A on a consolidated basis.
•
Liquidity, Capital Resources and Financial Position - an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments.
•
Forward-Looking Statements - cautionary information about forward-looking statements and a description of certain risks and uncertainties that could cause our actual results to differ materially from our historical results or our current expectations or projections.
OVERVIEW
We are a Fort Worth, Texas-based independent oil and gas company engaged in the development, exploitation, exploration, acquisition, and production of natural gas, NGLs, and crude oil primarily from unconventional reservoirs where hydrocarbons are found in challenging geological conditions such as fractured shales, coal beds and tight sands. We generate revenue, income and cash flows by producing and selling natural gas, NGLs, and crude oil. We produce these products in quantities and at prices that, in addition to generating operating income, allow us to conduct development, exploitation, exploration and acquisition activities to replace the reserves that have been produced.
At December 31, 2006, approximately 98% of our proved reserves were natural gas and natural gas liquids. Approximately 33% of our proved reserves were located in Michigan. Our activities in the Michigan Basin Antrim shale have allowed us to develop a technical and operational expertise in the development, exploitation, exploration, acquisition and production of unconventional natural gas reserves. Consistent with one of our business strategies, we have applied the expertise gained in our Michigan activities to our Canadian projects in Alberta, Canada and our Barnett Shale interests in the Fort Worth Basin in Texas. Our Texas and Alberta reserves made up about 45% and 20%, respectively of our proved reserves at December 31, 2006. The Delaware Basin in west Texas and the Mannville CBM in Alberta represent our most recent opportunities to apply this expertise.
For 2007, we plan to continue our focus on the continued development, exploitation and exploration of our properties in Texas and Alberta. We have allocated $502 million of our 2007 capital budget of $610 million for drilling activities. Approximately $425 million is allocated to our Barnett Shale position in the Forth Worth Basin in Texas and approximately $54 million is allocated to our Canadian CBM projects. Approximately $18 million of the 2007 drilling budget has been dedicated to our fractured shale projects in the Michigan Basin, with the remaining $5 million planned for our projects in Indiana/Kentucky and the Rockies.
Our Company focuses on three key value drivers:
•
reserve growth;
•
production growth; and
•
improving the Company’s cash flows.
The Company’s reserve growth is dependent upon our ability to apply the Company’s technical and operational expertise in our core operating areas to develop, exploit and explore unconventional natural gas reservoirs. We strive to increase reserves and production through aggressive management of operations and relatively low-risk development and exploitation drilling. We will also continue to identify high potential exploratory projects with higher levels of financial risk. Both our lower-risk development programs and higher-risk exploratory projects are aimed at providing the Company with opportunities to develop and exploit unconventional natural gas reservoirs to which our technical and operational expertise is well suited.
Our principal properties are well suited for production increases through development and exploitation drilling. We perform workover and infrastructure projects to reduce operating costs and increase current and future production. We regularly review operations on operated properties to determine if steps can be taken to profitably increase reserves and production.
As these elements are implemented, our results are measured through the following key measurements: reserve growth; production growth; cash flow from operating activities; and earnings per share.
(1)
This ratio is calculated by subtracting adjusted beginning of the year proved reserves (December 31, 2005 proved reserves less 2006 production) from end of the year proved reserves and dividing by beginning of the year proved reserves.
The possibility of decreasing prices received for production is among the several risks that we face. We seek to manage this risk by entering into natural gas sales contracts with price floors and natural gas and crude oil financial hedges. Our use of pricing collars and, to a lesser degree, fixed price swaps for both natural gas and crude oil helps to ensure a predictable base level of cash flow while allowing us to participate in a portion of any favorable price increases. This commodity price strategy enhances our ability to execute our development, exploitation and exploration programs, meet debt service requirements and pursue acquisition opportunities despite price fluctuations. If our revenues were to decrease significantly as a result of presently unexpected declines in natural gas prices or otherwise, we could be forced to curtail our drilling and acquisition activities. We might also be forced to sell some of our assets on an untimely or unfavorable basis.
Prices for natural gas and crude oil fluctuate widely. For example, the closing NYMEX wholesale price of natural gas was at an all-time high of approximately $13.91 per Mcf for October 2005 before dropping to approximately $4.20 per Mcf for October 2006. For February 2007 natural gas production, the wholesale price of natural gas was approximately $6.92 Mcf. Assuming natural gas prices remain at relatively favorable levels, we expect to fund more of our capital expenditures with cash flow from operating activities; however, we do not expect our cash flow from operating activities to be sufficient to satisfy our total budgeted capital expenditures. We plan to use cash flows from operations, credit facility utilization, possible sales of assets and issuance of debt or equity securities to fund our total budgeted capital expenditures in 2007.
Our wholly-owned subsidiary that will hold Cowtown Plant and the Cowtown Pipeline has filed a registration statement on Form S-1 relating to the offering of approximately 19% of its limited partner interests to the public. Numerous factors, such as general market conditions and market conditions in the oil and gas industry in particular, could result in this offering not being completed.
FINANCIAL RISK MANAGEMENT
We have established policies and procedures for managing risk within our organization, including internal controls. The level of risk assumed by us is based on our objectives and capacity to manage risk.
Our primary risk exposure is related to natural gas and crude oil commodity prices. We have mitigated the downside risk of adverse price movements through the use of long-term sales contracts, swaps and collars; however, in doing so, we have also limited future gains from favorable price movements.
Commodity Price Risk
We enter into long-term natural gas sales contracts and financial derivative contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas production. We sell approximately 10 MMcfd and 25 MMcfd of natural gas under long-term contracts with floor prices of $2.47 per Mcf and $2.49 per Mcf, respectively, through March 2009. Approximately 31.2 MMcfd of our natural gas production was sold under these contracts in 2006 and the remainder were third-party volumes controlled by us. We also enter into financial derivative contracts that include price floors, no-cost collars and fixed price swaps to hedge our exposure to commodity price risk associated with anticipated future production of natural gas, crude oil and condensate and NGLs.
Currently, natural gas price collars have been put in place to hedge 2007 anticipated production of approximately 123 MMcfd. Additionally, we have used price collar agreements to hedge approximately 1,250 Bbld of its crude oil, condensate and NGL anticipated production for 2007. Anticipated 2008 natural gas production of approximately 35 MMcfd has also been hedged using price collars and an additional 40 MMcfd of natural gas production has been hedged using fixed price swaps. We believe we will have more predictability of our natural gas and crude oil revenues as a result of these long-term sales and financial derivative contracts.
The following table summarizes our open financial derivative positions as of December 31, 2006 related to natural gas and crude oil production.
Utilization of our financial hedging program may result in natural gas and crude oil realized prices varying from market prices that we receive from the sale of natural gas and crude oil. Our revenue from natural gas and crude oil production was $15.5 million higher, $41.8 million lower and $43.9 million lower for 2006, 2005 and 2004, respectively.
We have also entered into financial derivative contracts to hedge exposure to commodity price risk associated with future contractual natural gas sales at fixed prices to third parties. As a result of our firm sale commitments, the associated financial derivative contracts qualified as fair value hedges for accounting purposes. Marketing revenues were $0.2 million lower and $0.1 million and $0.5 million higher as a result of our hedging activities in 2006, 2005 and 2004, respectively.
The following table summarizes our open financial swap positions and hedged firm commitments as of December 31, 2006 related to natural gas marketing.
Hedge ineffectiveness resulted in $0.1 million of net losses, $0.1 million of net gains and $0.1 million of net losses recorded to other revenue for 2006, 2005 and 2004, respectively.
Our remaining anticipated production for 2007 and beyond is subject to commodity price fluctuations. Under long-term sales contracts, natural gas volumes of 16.5 MMcfd are committed at market price through September 2008. During 2006, approximately 8.9 MMcfd of our natural gas production was sold under these contracts. The remaining contractual volumes were third-party volumes controlled by us.
Based on our 2006 average production and long-term natural gas sales contracts with floor prices of $2.47 per Mcf and $2.49 per Mcf, each $1.00 per Mcf increase/decrease in the price of natural gas would increase/decrease our revenue by approximately $42.0 million.
Interest Rate Risk
At December 31, 2006, we had no interest rate derivatives in effect. On September 10, 2003, we entered into an interest rate swap to hedge the $40.0 million of fixed-rate second lien notes issued on June 27, 2003. The swap converted the debt’s 7.5% fixed-rate debt to a floating six-month LIBOR base. In January 2004, the swap position was cancelled, and we received a cash settlement of $0.3 million that was recognized over the original term for the swap until the associated debt was retired in March 2006. At that time, the remaining deferred gain was recognized.
Interest expense for the years ended December 31, 2006, 2005 and 2004 was $0.1 million lower, $0.3 million lower and $0.8 million higher, respectively, as a result of the interest rate swaps.
If interest rates on our variable interest-rate debt of $421.1 million, as of December 31, 2006, increase or decrease by one percentage point, our annual pretax income will decrease or increase by $4.2 million.
Credit Risk
Credit risk is the risk of loss as a result of non-performance by counterparties of their contractual obligations. We sell a portion of our natural gas production directly under long-term contracts with the remainder of our natural gas and crude oil production sold at spot or short-term contract prices. All our natural gas and crude oil production is sold to large trading companies and energy marketing companies, refineries and other users of petroleum products. We also enter into hedge derivatives with financial counterparties. We monitor exposure to counterparties by reviewing credit ratings, financial statements and credit service reports. Exposure levels are limited and parental guarantees and collateral to support the obligations of our counterparty are required according to our established policy. Each customer and/or counterparty is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. In this manner, we reduce credit risk.
While we follow our credit policies at the time we enter into sales contracts, the credit-worthiness of counterparties could change over time. The credit ratings of the parent companies of the two counterparties to our long-term gas contracts were downgraded in early 2003 and remain below the credit ratings required for the extension of credit to new customers. Please see “Item 1A.
ITEM 7A.
Quantitative and Qualitative Disclosures About Market Risk
The information called for by this Item is incorporated herein by reference to the information in Item 7 of this report under the heading “Financial Risk Management.”
ITEM 8.
ITEM 8.
Financial Statements and Supplementary Data
QUICKSILVER RESOURCES INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
MANAGEMENT’S STATEMENT OF RESPONSIBILITIES
To the Stockholders of
Quicksilver Resources Inc.:
Management of Quicksilver Resources Inc. is responsible for the preparation, integrity and fair presentation of its published consolidated financial statements. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles and, as such, include amounts based on judgments and estimates made by management. The Company also prepared the other information included in the annual report and is responsible for its accuracy and consistency with the consolidated financial statements.
Management is also responsible for establishing and maintaining effective internal control over financial reporting. The Company’s internal control over financial reporting includes those policies and procedures that pertain to the Company’s ability to record, process, summarize and report reliable financial data. The Company maintains a system of internal control over financial reporting, which is designed to provide reasonable assurance to the Company’s management and board of directors regarding the preparation of reliable published financial statements and safeguarding of the Company’s assets. The system includes a documented organizational structure and division of responsibility, established policies and procedures, including a code of conduct to foster a strong ethical climate, which are communicated throughout the Company, and the careful selection, training and development of our people.
The Board of Directors, acting through its Audit Committee, is responsible for the oversight of the Company’s accounting policies, financial reporting and internal control. The Audit Committee of the Board of Directors is comprised entirely of outside directors who are independent of management. The Audit Committee is responsible for the appointment and compensation of the independent registered public accounting firm. It meets periodically with management, the independent registered public accounting firm and the internal auditors to ensure that they are carrying out their responsibilities. The Audit Committee is also responsible for performing an oversight role by reviewing and monitoring the financial, accounting and auditing procedures of the Company in addition to reviewing the Company’s financial reports. Internal auditors monitor the operation of the internal control system and report findings and recommendations to management and the Audit Committee. Corrective actions are taken to address control deficiencies and other opportunities for improving the system as they are identified. The independent registered public accounting firm and the internal auditors have full and unlimited access to the Audit Committee, with or without management, to discuss the adequacy of internal control over financial reporting, and any other matters which they believe should be brought to the attention of the Audit Committee.
Management recognizes that there are inherent limitations in the effectiveness of any system of internal control over financial reporting, including the possibility of human error and the circumvention or overriding of internal control. Accordingly, even effective internal control over financial reporting can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect misstatements. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.
Management assessed the Company’s internal control system as of December 31, 2006 in relation to criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the Company has determined that, as of December 31, 2006, the Company’s system of internal control over financial reporting was effective.
The consolidated financial statements have been audited by the independent registered public accounting firm, Deloitte & Touche LLP, which was given unrestricted access to all financial records and related data, including minutes of all meetings of stockholders, the Board of Directors and committees of the Board. Reports of the independent registered public accounting firm, which includes the independent registered public accounting firm’s attestation of management’s assessment of internal controls, are also presented within this document.
/s/ Glenn Darden
President and Chief Executive Officer
/s/ Philip Cook
Senior Vice President - Chief Financial Officer
Fort Worth, Texas
February 28, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Quicksilver Resources Inc.
Fort Worth, Texas
We have audited the accompanying consolidated balance sheets of Quicksilver Resources Inc. and subsidiaries (the “Company”) as of December 31, 2006 and 2005 and the related consolidated statements of income and comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Quicksilver Resources Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (Revised 2004), Share-Based Payment.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Fort Worth, Texas
February 28, 2007
QUICKSILVER RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
As of December 31, 2006 and 2005
In thousands, except for share data
The accompanying notes are an integral part of these consolidated financial statements.
QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2006, 2005 and 2004
In thousands, except for per share data
The accompanying notes are an integral part of these consolidated financial statements.
QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2006, 2005 and 2004
In thousands, except for share data
The accompanying notes are an integral part of these consolidated financial statements.
QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years End December 31, 2006, 2005 and 2004
In thousands
The accompanying notes are an integral part of these consolidated financial statements.
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
For The Years Ended December 31, 2006, 2005 and
1.
NATURE OF OPERATIONS
Quicksilver Resources Inc. (“Quicksilver” or the “Company”) is an independent oil and gas company incorporated in the state of Delaware and headquartered in Fort Worth, Texas. Quicksilver engages in the development, exploitation, exploration, acquisition and production and sale of natural gas, NGLs and crude oil as well as the marketing, processing and transmission of natural gas. Substantial portions of Quicksilver’s reserves are located in Michigan, Texas, Indiana, Kentucky, the Rocky Mountains and Alberta, Canada. Quicksilver has U.S. offices in Gaylord, Michigan; Corydon, Indiana; Cut Bank, Montana; Granbury, Texas and a Canadian subsidiary, Quicksilver Resources Canada Inc. (“QRCI”) located in Calgary, Alberta.
Quicksilver’s results of operations are largely dependent on the difference between the prices received for its natural gas and crude oil products and the cost to find, develop, produce and market such resources. Natural gas and crude oil prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond Quicksilver’s control. These factors include worldwide political instability, quantities of natural gas in storage, foreign supply of natural gas and crude oil, the price of foreign imports, the level of consumer demand and the price of available alternative fuels. Quicksilver manages a portion of the operating risk relating to natural gas and crude oil price volatility through hedging and fixed price contracts.
2.
SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The Company’s consolidated financial statements include the accounts of Quicksilver and all its majority-owned subsidiaries and companies over which the Company exercises control through majority voting rights after elimination of all significant inter-company balances and transactions. The Company accounts for its ownership in unincorporated partnerships and companies under the equity method of accounting as it has significant influence over those entities, but because of terms of the ownership agreements, Quicksilver does not meet the criteria for control which would require consolidation of the entities. The Company’s share of the results from these entities are included as a component of operating income as operations of the entities are necessary for the Company to process and deliver natural gas from certain of its properties. The Company also consolidates its pro-rata share of oil and gas joint ventures. All significant inter-company transactions are eliminated.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires 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 revenues and expenses, including stock compensation 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 the Company’s estimates. Significant estimates underlying these financial statements include the estimated quantities of proved natural gas and crude oil reserves used to compute depletion of natural gas and crude oil properties and the related present value of estimated future net cash flows therefrom (see Supplemental Information found in Note 23), estimates of current revenues based upon expectations for actual deliveries and prices received, the estimated fair value of financial derivative instruments and the estimated fair value of asset retirement obligations.
Cash and Cash Equivalents
Cash equivalents consist of time deposits and liquid debt investments with original maturities of three months or less at the time of purchase.
Accounts Receivable
The Company’s customers are natural gas and crude oil purchasers. Each customer and/or counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although the Company does not require collateral, appropriate credit ratings are required and, in some instances, parental guarantees are obtained. Receivables are generally due in 30-60 days. When collections of specific amounts due are no longer reasonably assured, an allowance for doubtful accounts is established. During 2006 and 2005, one purchaser accounted for approximately 10% of the Company’s total consolidated natural gas, NGL and crude oil sales. Two purchasers accounted for approximately 15% and 14% of the Company’s total consolidated 2004 sales.
Hedging
The Company enters into financial derivative instruments to hedge price risk for its natural gas and crude oil sales and interest rate risk. Hedging is accounted for in accordance with Statements of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, which amended SFAS No. 133 (see Note 4). The Company does not enter into financial derivatives for trading or speculative purposes.
All derivatives are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and losses that qualify as hedges are recognized in revenues or interest expense in the period in which the hedged transaction is recognized. Gains or losses on derivative instruments terminated prior to their original expiration date are deferred and recognized as income or expense in the period in which the hedged transaction is recognized. Fair value is determined by reference to published future market prices or interest rates. Ineffective portions of hedges, if any, are recognized currently in earnings.
The Company’s long-term contracts for delivery of 25 MMcfd and 10 MMcfd at a floor of $2.49 and $2.47 per Mcf, respectively, through March 2009 are not considered derivatives but have been designated as normal sales contracts under SFAS No. 133. Approximately 31.2 MMcfd of the Company’s natural gas production was sold under these contracts during 2006. The remaining volumes sold under these contracts were third-party volumes controlled by the Company.
Parts and supplies
Parts and supplies consist of well equipment, spare parts and supplies carried on a first-in, first-out basis at the lower of cost or market.
Investments in Equity Affiliates
Income from equity affiliates is included as a component of operating income as the operations of the affiliates are associated with processing and transportation of the Company’s natural gas production.
Property, Plant, and Equipment
The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, geological and geophysical expenses, dry holes, leasehold equipment and overhead charges directly related to acquisition, exploration and development activities are capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized.
The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves as determined
by independent petroleum engineers. Excluded from amounts subject to depletion are costs associated with unevaluated properties. Natural gas and crude oil are converted to equivalent units based upon the relative energy content, which is six thousand cubic feet of natural gas to one barrel of crude oil.
Net capitalized costs are limited to the lower of unamortized cost net of deferred tax or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge the Company’s oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, (iii) the lower of cost or market value of unproved properties included in the cost being amortized less (iv) income tax effects related to differences between the book and tax basis of the natural gas and crude oil properties. Such limitations are imposed separately for the U.S. and Canadian cost centers.
All other properties and equipment are stated at original cost and depreciated using the straight-line method based on estimated useful lives from five to forty years.
Revenue Recognition
Revenues are recognized when title to the products transfer to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue, so that the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2006 and 2005, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.
Environmental Compliance and Remediation
Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred. Environmental remediation costs, which improve the condition of a property, are capitalized.
Income Taxes
Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that will be in effect in years in which the temporary differences are expected to reverse. QRCI, the Company’s Canadian subsidiary, computes taxes at rates in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested by QRCI and thus not considered available for distribution to the parent Company. Net operating loss carry forwards and other deferred tax assets, are reviewed annually for recoverability, and if necessary, are recorded net of a valuation allowance.
Disclosure of Fair Value of Financial Instruments
The Company’s financial instruments include cash, time deposits, accounts receivable, notes payable, accounts payable, long-term debt and financial derivatives. The fair value of long-term debt is estimated at the present value of future cash flows discounted at rates consistent with comparable maturities for credit risk. The carrying amounts reflected in the balance sheet for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value.
Minority Interest
Minority interest in consolidated subsidiaries held by third parties is subject to provisions for redemption outside of the Company’s control and is accounted for as mezzanine equity. These interests are recorded at fair value at the date of issue and will be subsequently evaluated to determine the redemption value at each balance sheet date.
At December 31, 2006, the carrying amounts of these interests exceed their redemption amounts; therefore no adjustments to the carrying amounts have been recorded.
Foreign Currency Translation
The Company’s Canadian subsidiary, QRCI, uses the Canadian dollar as its functional currency. All balance sheet accounts of Canadian operations are translated into U.S. dollars at the year-end rate of exchange and statement of income items are translated at the weighted average exchange rates for the year. The resulting translation adjustments are made directly to a separate component of accumulated other comprehensive income within stockholders’ equity. Gains and losses from foreign currency transactions are included in the consolidated statement of income.
Earnings per Share
Basic net income or loss per common share is computed by dividing the net income or loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income or loss per common share is computed using the treasury stock method, which also considers the impact to net income and common shares for the potential dilution from stock options, stock warrants and outstanding convertible securities.
The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income per common share. Total per share amounts may not add due to rounding. No outstanding options were excluded from the diluted net income per share calculation for any of the years presented.
Adoption of SFAS No. 123 (revised 2004)
In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS 123(R)”). This statement requires the cost resulting from all share-based payment transactions be recognized in the financial statements at their fair value on the grant date. SFAS 123(R) was adopted by the Company on January 1, 2006. The Company previously accounted for stock awards under the recognition and measurement principles of APB No. 25, Accounting for Stock Issued to Employees, and related Interpretations. Stock-based employee compensation expense for restricted stock and stock unit grants was reflected in net income, but no compensation expense was recognized for options granted with an exercise price equal to the market value of the underlying common stock on the date of grant.
The Company adopted SFAS 123(R) using the modified prospective application method described in the statement. Under the modified prospective application method, the Company applied the standard to new awards and to awards modified, repurchased, or cancelled after January 1, 2006. Additionally, compensation cost for the unvested portion of stock option awards outstanding as of January 1, 2006 has been recognized as compensation expense as the requisite service is rendered after January 1, 2006. The compensation cost for unvested stock option awards granted before adoption of SFAS 123(R) shall be attributed to periods beginning January 1, 2006 using the
attribution method that was used under SFAS 123. At January 1, 2006, the Company had total compensation cost of $1.1 million related to unvested stock options with a weighted average remaining vesting period of 1.5 years. The adoption of the statement reduced income before income taxes by $0.7 million and reduced income from continuing operations and net income by $0.6 million in 2006. The adoption had no effect on cash flows from operating activities or financing activities. Basic and diluted earnings per share were each $0.01 lower as a result of SFAS No. 123(R) adoption in 2006. At December 31, 2006, the Company had $0.4 million of expense remaining in unrecognized compensation cost for the unvested portion of stock options awarded prior to 2006.
At January 1, 2006, the Company had total compensation cost of $3.3 million related to unvested restricted stock and stock unit awards. Additionally, restricted stock and stock units granted in 2006 had total compensation cost of $18.3 million at the time of grant. During 2006, the Company recognized $5.8 million of expense for vesting of restricted stock and stock units. Total unvested compensation cost was $14.2 million at December 31, 2006 with a weighted average remaining vesting period of 1.3 years.
Prior to the adoption of SFAS 123(R), the Company presented any tax benefits of deductions resulting from the exercise of stock options within operating cash flows in the condensed consolidated statements of cash flow. SFAS 123(R) requires tax benefits resulting from tax deductions in excess of the compensation cost recognized for those options (“excess tax benefits”) to be classified and reported as both an operating cash outflow and a financing cash inflow upon adoption of SFAS 123(R). As a result of the Company’s net operating losses, the excess tax benefits that would otherwise be available to reduce income taxes payable have the effect of increasing the Company’s net operating loss carry forwards. Accordingly, because the Company is not able to realize these excess tax benefits, such benefits have not been recognized in the condensed consolidated statement of cash flows for the year ended December 31, 2006.
The following table reflects pro forma net income and the associated earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123, Accounting for Stock-based Compensation, to stock-based employee compensation.
Additional description and disclosure of the Company’s stock-based compensation plans and activities is included in Note 16.
Recently Issued Accounting Standards
The Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140, in February 2006. SFAS No. 155 addresses accounting for beneficial interests in securitized financial instruments. The guidance allows fair value remeasurement for any hybrid financial instrument containing an embedded derivative that would otherwise require bifurcation and clarifies which interest-only and principal-only strips are not subject to SFAS No. 133. SFAS No. 155 also established a requirement to evaluate interests in securitized financial assets to identify any interests that are either freestanding derivatives or contain an embedded derivative requiring bifurcation. The statement is effective for all financial instruments issued or acquired after the beginning of the first fiscal year that begins after September 15, 2006. Quicksilver’s management does not believe application of this Statement will have a material impact on the Company’s financial position, results of operations or cash flows.
SFAS No. 157, Fair Value Measurements, was issued by the FASB in September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”) and expands disclosures about fair value measurements. The Statement applies under other accounting pronouncements that require or permit fair value measurement. No new requirements are included in SFAS No. 157, but application of the Statement will change current practice. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Company management does not expect adoption of SFAS No. 157 will have a material impact on the Company’s financial position, results of operations or cash flows.
The FASB issued FASB Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109, in June 2006. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 defines a criterion that an individual tax position must meet for any part of the benefit of that position to be recognized in an enterprise’s financial statements. FIN 48 also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company’s management has evaluated the impact of FIN 48 and expects to record an adjustment to retained earnings of approximately $0.4 million to provide for additional deferred income tax liabilities.
On February 15, 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The FASB believes the statement will improve financial reporting by providing companies the opportunity to mitigate volatility in reported earnings by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Use of the statement will expand the use of fair value measurements for accounting for financial instruments. The Company does not believe SFAS No. 159 will have a material impact on its financial position, results of operations or cash flows.
In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses the SEC staff’s views regarding the process by which misstatements in financial statements are evaluated to determine whether financial statement restatement is necessary. SAB 108 is effective for fiscal years ending after November 15, 2006. SAB 108 did not have a material impact on the Company’s financial position, results of operations or cash flows.
3.
HEDGING
The Company hedges a portion of its equity production of natural gas and crude oil using various financial derivatives. All derivatives are evaluated using the hedge criteria established under SFAS Nos. 133 and 138. If hedge criteria are met, the change in a derivative’s fair value (for a cash flow hedge) is deferred in stockholders’ equity as a component of accumulated other comprehensive income. These deferred gains and losses are recognized
into income in the period in which the hedged transaction is recognized in revenues to the extent the hedge is effective. The ineffective portions of hedges are recognized currently in earnings.
During 2006, the Company entered into fixed price firm natural gas sale commitments and hedged these commitments with financial price swaps that extend through March 2007. The financial price swaps qualify as fair value hedges.
On September 11, 2003, the Company entered into a fair value interest swap covering $40 million of its fixed rate 2003 Second Mortgage Notes. The swap converted the debt’s 7.5% fixed rate to a floating six-month LIBOR base rate plus 4.07% through the termination of the notes. In January 2004, the swap position was cancelled and the Company received a cash settlement of $0.3 million that was recognized during the original term of the hedge until the associated 2003 Second Mortgage Notes were retired in March 2006.
The change in carrying value of the Company’s derivatives, firm sale and purchase commitments accounted for as hedges in the Company’s balance sheet since December 31, 2005 resulted from the decrease in market prices for natural gas and crude oil. The change in fair value of all cash flow hedges was reflected in accumulated other comprehensive income, net of deferred tax effects. Natural gas and crude oil derivative assets and liabilities reflected as current in the December 31, 2006 balance sheet represent the estimated fair value of contract settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas and crude oil as of the balance sheet date. These settlement amounts are not due and payable until the monthly period in which the related underlying hedged gas or oil sales transaction occurs. Settlement of the underlying hedged transactions occurs in the following 25 to 60 days.
The estimated fair values of all derivatives and the associated fixed price firm sale commitments of the Company as of December 31, 2006 and 2005 are provided below. The associated carrying values of these swaps are equal to the estimated fair values for each period presented. The assets and liabilities recorded in the balance sheet are netted where derivatives with both gain and loss positions are held by a single third party.
The fair value of all natural gas and crude derivatives and firm sale and purchase commitments accounted for as hedges as of December 31, 2006 and 2005 was estimated based on market prices of natural gas and crude oil for the periods covered by the derivatives. The net differential between the prices in each derivative and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to
arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. The fair value of the interest rate swap was based upon counterparty estimates of the fair value of such swaps. As a result, the fair value of the Company’s derivatives and commitments does not necessarily represent the value a third party would pay or expect to receive to assume the Company’s contract positions. Derivative assets of $64.1 million have been classified as current at December 31, 2006 based on the maturity of the derivative instruments, resulting in $42.7 million of after-tax gains to be reclassified from accumulated other comprehensive income in 2007.
4.
FINANCIAL INSTRUMENTS
The Company has established policies and procedures for managing risk within its organization, including internal controls. The level of risk assumed by the Company is based on its objectives and capacity to manage risk.
Quicksilver’s primary risk exposure is related to natural gas and crude oil commodity prices. The Company has mitigated the downside risk of adverse price movements through the use of swaps, futures and forward contracts; however in doing so, it has also limited future gains from favorable price movements.
Commodity Price Risk
The Company enters into long-term sales contracts and financial derivative contracts to hedge its exposure to commodity price risk associated with anticipated future natural gas, crude oil and NGL production. These contracts can include physical sales contracts and financial derivatives including price ceilings and floors, no-cost collars and fixed price swaps. As of December 31, 2006, Quicksilver sells approximately 10 MMcfd and 25 MMcfd of natural gas under long-term contracts with floors of $2.47 per Mcf and $2.49 per Mcf, respectively, through March 2009, respectively. Approximately 31.2 MMcfd of the Company’s natural gas production was sold under these contracts during 2006. The remaining volumes sold under these contracts were third-party volumes controlled by the Company. These contracts are not considered derivatives, but rather have been designated as normal sales contracts under SFAS No. 133.
Natural gas price collars have been put in place to hedge 2007 anticipated production of approximately 123 MMcfd. Additionally, the Company has used price collar agreements to hedge approximately 1,250 Bbld of its anticipated crude oil, condensate and NGL production in 2007. Anticipated natural gas production of approximately 40 MMcfd has been hedged for the first quarter of 2008 using price collars and an additional 40 MMcfd of natural gas production has been hedged using fixed price swaps. These financial derivative contracts allow the Company to benefit from significant predictability of its natural gas and crude oil revenues.
The following table summarizes the Company’s open financial derivative positions as of December 31, 2006 related to its natural gas and crude oil production.
Utilization of the Company’s financial hedging program may result in natural gas and crude oil realized prices that vary from actual prices that the Company receives from the sale of natural gas and crude oil. As a result of the hedging programs, revenues from production in 2006, 2005 and 2004 were $15.5 million higher, and $41.8 million and $43.9 million lower, respectively, than if the hedging programs had not been in effect.
The Company entered into various financial contracts to hedge exposure to commodity price risk associated with future contractual natural gas sales with financial swaps. As the natural gas sales contracts meet the definition of a firm commitment, the associated financial price swaps qualify as fair value hedges. Marketing revenues were $0.2 million lower and $0.1 million and $0.5 million higher as a result of its hedging activities in 2006, 2005 and 2004, respectively.
The following table summarizes our open financial swap positions and hedged firm commitments as of December 31, 2006 related to natural gas marketing.
Hedge ineffectiveness resulted in $0.1 million of net losses, $0.1 million of net gains and $0.1 million of net losses in 2006, 2005 and 2004, respectively.
Commodity price fluctuations affect the remaining natural gas and crude oil volumes as well as the Company’s NGL volumes. Natural gas volumes of 16.5 MMcfd of natural gas are committed at market price through September 2008. During 2006, approximately 8.9 MMcfd of Quicksilver’s natural gas production was sold under these contracts. Approximately 7.6 MMcfd sold under these contracts were third-party volumes controlled by the Company.
The fair values of fixed price and floating price natural gas and crude oil derivatives and associated firm commitments as of December 31, 2006 and 2005 were estimated based on market prices of natural gas and crude oil for the periods covered by the contracts. The net differential between the prices in each contract and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. As a result, the natural gas and crude oil financial swap and firm commitment fair value does not necessarily represent the value a third party would pay or expect to receive to assume the Company’s contract positions.
Interest Rate Risk
The Company manages its exposure associated with interest rates by entering into interest rate swaps. As of December 31, 2006 and 2005, the Company had no interest rate swaps in effect. As of December 31, 2004, the interest payments for $75.0 million notional variable-rate debt were hedged with an interest rate swap that converted a floating three-month LIBOR base to a 3.74% fixed-rate through March 31, 2005. The liability associated with the swap was $0.2 million at December 31, 2004.
On September 10, 2003, the Company entered into an interest rate swap to hedge the $40.0 million of fixed-rate second lien notes issued on June 27, 2003. The swap converted the debt’s 7.5% fixed-rate debt to a floating six-month LIBOR base. In January 2004, the swap position was cancelled and the Company received a cash settlement of $0.3 million that was recognized over the original term of the swap until the second lien mortgage notes were retired in March 2006. Upon retirement of the notes, the remaining portion of the deferred gain was recognized.
Credit Risk
Credit risk is the risk of loss as a result of non-performance by counterparties of their contractual obligations. The Company sells a portion of its natural gas production directly under long-term contracts, and the remainder of its natural gas and crude oil is sold to large trading companies and energy marketing companies, refineries and other users of petroleum products at spot or short-term contracts. Quicksilver also enters into hedge derivatives with financial counterparties. The Company monitors its exposure to counterparties by reviewing credit ratings, financial statements and credit service reports. Exposure levels are limited and parental guarantees are required according to
Company policy. Each customer and/or counterparty of the Company is reviewed as to credit-worthiness prior to the extension of credit and on a regular basis thereafter. In this manner, the Company reduces credit risk.
While Quicksilver follows its credit policies at the time it enters into sales contracts, the credit-worthiness of counter parties could change over time. The credit ratings of the parent companies of the two counter parties to the Company’s long-term gas contracts were downgraded in early 2003 and remain below the credit ratings required for the extension of credit to new customers.
Performance Risk
Performance risk results when a financial counterparty fails to fulfill its contractual obligations such as commodity pricing or volume commitments. Typically, such risk obligations are defined within the trading agreements. The Company manages performance risk through management of credit risk. Each customer and/or counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter.
Foreign Currency Risk
The Company’s Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, the Company is exposed to foreign currency exchange rate risk. In 2005, foreign currency transaction losses of $0.1 million were recorded as a result of losses in the Canadian-$ value of U.S.-$ bank balances in each of those years. During October and November 2004, Quicksilver loaned QRCI approximately $11.4 million. To reduce its exposure to exchange rate risk, QRCI entered into a forward contract that fixed the Canadian-to-US exchange rate. The balance of the loan was repaid at the end of November and upon settlement of the forward contract, QRCI recognized a gain of $0.2 million.
5.
ACCOUNTS RECEIVABLE
Accounts receivable consist of the following:
6.
OTHER CURRENT ASSETS
Other current assets consist of the following:
7.
PROPERTY, PLANT AND EQUIPMENT
Property and equipment consist of the following:
Unevaluated Natural Gas and Crude Oil Properties Excluded From Depletion
Under full cost accounting, the Company may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties excluded from natural gas and crude oil properties being amortized at December 31, 2006 and 2005 and the year in which they were incurred as follows:
Costs are transferred into the amortization base on an ongoing basis, as the projects are evaluated and proved reserves established or impairment determined. Pending determination of proved reserves attributable to the above costs, the Company cannot assess the future impact on the amortization rate. As of December 31, 2006, approximately $150.8 million and $34.4 million of the total unevaluated costs of $191.7 million related to the Company’s Texas and Canadian projects, respectively. These costs will be transferred into the amortization base as the undeveloped projects and areas are evaluated. The Company anticipates that the majority of this activity should be completed over the next two to three years.
Capitalized Costs
Capitalized overhead costs that directly relate to exploration and development activities were $3.2 million, $5.3 million and $3.1 million for the years ended December 31, 2006, 2005 and 2004, respectively.
Depletion per Mcfe was $1.07, $0.91 and $0.78 for the years ended December 31, 2006, 2005 and 2004, respectively.
8.
OTHER ASSETS
Other assets consist of the following:
Costs related to the acquisition of debt are deferred and amortized over the term of the debt.
9.
ACCRUED LIABILITIES
Accrued liabilities consist of the following:
10.
NOTES PAYABLE AND LONG-TERM DEBT
Long-term debt consists of the following:
Maturities are as follows, in thousands of dollars:
On July 28, 2004, the Company extended its senior secured credit facility to July 28, 2009 to provide for revolving loans and letters of credit from time to time in an aggregate amount not to exceed the lesser of the borrowing base or $600 million. At December 31, 2006, the current borrowing base was $600 million. The borrowing base was subject to annual redeterminations and certain other redeterminations, based upon several factors. The lenders’ commitments under the facility were allocated between U.S. and Canadian commitments, with the U.S. commitment available for borrowings by the Company and the Canadian commitment available for borrowings by the Company’s Canadian subsidiary, QRCI. U.S. borrowings under the facility were guaranteed by most of Quicksilver’s domestic subsidiaries and are secured by Quicksilver’s and certain of its subsidiaries’ oil and gas properties. Canadian borrowings under the facility were secured by QRCI’s oil and gas properties. The loan agreements for the credit facility prohibit the declaration or payment of dividends by the Company and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio. Based upon the Company’s 2006 year-end reserves, the Company is limited under the indenture agreement to $750 million of borrowing under our senior secured credit facility. The Company was in compliance with all such covenants at December 31, 2006. The senior credit facility was also used to issue letters of credit. At December 31, 2006, the Company had $0.6 million in letters of credit and approximately $178 million available under the senior revolving credit facility.
On February 9, 2007, the Company extended its senior secured credit facility to February 9, 2012 and to provide for revolving loans, swingline loans and letters of credit from time to time in an aggregate amount not to exceed the lesser of the borrowing base which is calculated based on several factors and is initially equal to
$850 million. The borrowing base is subject to annual redeterminations and certain other redeterminations. The lenders have agreed to initial revolving credit commitments in an aggregate amount equal to $1.2 billion, and the Company has an option to increase the facility to $1.45 billion with the consent of the lenders. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. funds available for borrowing by the Company and Canadian funds being available for borrowing by the Company’s Canadian subsidiary, QRCI in U.S. or Canadian funds. The facility offers the option to extend the maturity up to two additional years with requisite lender consent. U.S. borrowings under the facility are guaranteed by most of Quicksilver’s domestic subsidiaries and are secured by, among other things Quicksilver’s and certain of its domestic subsidiaries’ oil and gas properties. Canadian borrowings under the facility are secured by, among other things, QRCI’s, Quicksilver’s and certain of Quicksilver’s domestic subsidiaries’ oil and gas properties. The loan agreements for the credit facility prohibit the declaration or payment of dividends by the Company and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio.
On March 16, 2006, the Company issued $350 million in principal amount of Senior Subordinated Notes due 2016 (“Senior Subordinated Notes”). The Senior Subordinated Notes are unsecured, senior subordinated obligations of the Company and bear interest at an annual rate of 7.125% payable semiannually on April 1 and October 1 of each year. The terms and conditions of the Senior Subordinated Notes require the Company to comply with certain covenants, which primarily limit certain activities, including, among other things, levels of indebtedness, restricted payments, payments of dividends, capital stock repurchases, investments, liens, restrictions on restricted subsidiaries to make distributions, affiliate transactions and mergers and consolidations. At December 31, 2006, the Company was in compliance with such covenants. Under the indenture, the maximum amount of borrowings from the senior credit facility was $750 million. At December 31, 2006, the fair value of the $350 million in principal amount of Senior Subordinated Notes was $342.1 million.
In March 2006, the Company used $70 million of the proceeds from the issuance of the Senior Subordinated Notes to retire the second lien mortgage notes. As a result of the repayment, the Company recognized additional interest expense of $1.0 million consisting of a prepayment premium of $0.8 million and a charge of $0.3 million for associated unamortized deferred financing costs, partially offset by recognition of an associated deferred hedging gain of $0.1 million.
On November 1, 2004, the Company sold $150 million $1.875% convertible subordinated debentures due November 1, 2024, which are contingently convertible into shares of Quicksilver’s common stock (subject to adjustment). As of December 31, 2006 and 2005, the debentures were convertible into 4,908,128 shares of Quicksilver’s common stock. Each $1,000 debenture was issued at 98.5% of par and bears interest at an annual rate of 1.875% payable semi-annually on May 1 and November 1 of each year. Holders of the debentures can require the Company to repurchase all or a portion of their debentures on November 1, 2011, 2014 or 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into Quicksilver common stock at a rate of 32.7209 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events, holders of the debentures are not entitled to exercise their conversion rights, unless the closing price of Quicksilver’s stock price is $36.67 (120% of the conversion price per share) for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter. Upon conversion, the Company has the option to deliver in lieu of Quicksilver common stock, cash or a combination of cash and Quicksilver common stock. At December 31, 2006, the fair value of the $150 million in principal amount of contingently convertible debentures was $207.4 million.
11.
ASSET RETIREMENT OBLIGATIONS
The Company records the fair value of the liability for asset retirement obligations in the period in which it is incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by
increasing the carrying amount of the long-lived asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is allocated to expense using a systematic method over the asset’s useful life. Changes in the liability for the asset retirement obligations are recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows. During the years ended December 31, 2006, 2005 and 2004, accretion expense was recognized and included in depletion, depreciation and accretion expense reported in the consolidated statement of income for the period.
The following table provides a reconciliation of the changes in the estimated asset retirement obligation from January 1, 2005 through December 31, 2006.
During the years ended December 31, 2006, 2005 and 2004, accretion expense was recognized and included in depletion, depreciation and accretion expense reported in the statement of income for the year. Asset retirement obligations at December 31, 2006 and 2005 are $25.2 million and $21.0 million, respectively, of which $0.2 million and $0.1 million, respectively, was classified as current.
12.
INCOME TAXES
Deferred income taxes are established for all temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In addition, deferred tax balances must be adjusted to reflect tax rates that will be in effect in the years in which the temporary differences are expected to reverse. For years prior to 2004, the Company had accrued no U.S. deferred income taxes on QRCI’s undistributed earnings or on the related translation adjustments pursuant to FAS No. 109, Accounting for Income Taxes, and APB No. 23, Accounting for Income Taxes - Special Areas as the Company expected that QRCI’s undistributed earnings would be permanently reinvested for use in the development of its oil and gas reserves. In July 2004, however, a dividend distribution of $86.5 million was made by QRCI to Quicksilver. The distribution represented the repayment of Quicksilver’s capital contributions that had been made to QRCI for the period January 1, 2001 through July 27, 2004 in the amount of $114.4 million, Canadian. This dividend was reinvested in the U.S. under a qualified domestic reinvestment plan as defined under Internal Revenue Code Section 965(b)(4). The funds were used for capital expenditures in the Barnett Shale exploration and development program. After application of the 85% dividend exclusion on estimated accumulated earnings and profits of approximately $15.5 million, a current U.S. federal income tax of approximately $0.8 million was accrued on this dividend distribution in 2004 and paid in 2005. No other deferred taxes have been accrued on QRCI’s undistributed earnings, and the Company continues to expect that the balance of QRCI’s undistributed earnings will be permanently reinvested for use in the development of its oil and gas reserves.
In May 2006, the Texas business tax was amended by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component. As the tax base for computing Texas margin tax is derived from an income-based measure, the Company has determined the margin tax is an
income tax and, therefore, the provisions of SFAS No. 109, Accounting for Income Taxes (“SFAS 109”), regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets and liabilities of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, the Company has recalculated its deferred tax assets and liabilities for Texas based upon the new margin tax and recorded a deferred tax provision of $1.6 million for the Texas margin tax in 2006.
During the third quarter of 2006, the Company was notified that IRS audits of Terra Energy Ltd. (“Terra”), a wholly-owned subsidiary of Quicksilver, were closed for all years prior to its acquisition by the Company in 2000. As a result, the Company reversed a $0.9 million deferred tax liability for items associated with differences in book basis and tax basis for Terra prior to its acquisition.
Tax rate reductions were enacted during 2006 by the Canadian federal government as well as several provinces. As required by SFAS 109, the Company’s Canadian deferred income tax balances were revalued to reflect the changes in these tax rates. The Company recorded a $3.8 million income tax benefit in the second quarter of 2006 as a result of the Canadian rate reductions.
Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2006 and 2005 are as follows:
The provisions for income taxes for the years ended December 31, 2006, 2005 and 2004 are as follows:
Reconciliations of the statutory federal income tax rate and the effective tax rate for the years ended December 31, 2006, 2005 and 2004 are as follows:
Income tax benefits recognized as additional paid-in capital for the years ended December 31, 2005 and 2004 are as follows:
Included in deferred tax assets are net operating losses of approximately $117.8 million that are available for carryover beginning in the year 2006 to reduce future U.S. taxable income. The net operating losses will expire in 2007 through 2026. These net operating losses have not been reduced by a valuation allowance, because management believes that future taxable income will more likely than not be sufficient to utilize substantially all of its tax carry forwards prior to their expirations. However, under Internal Revenue Code Section 382, a change of ownership was deemed to have occurred for our predecessor, MSR Exploration Ltd. (“MSR”) in 1998. Due to the limitations imposed by Section 382, a portion of MSR’s net operating losses could not be utilized and are not included in deferred tax assets.
The Company’s 2004 consolidated federal income tax return is being audited by the Internal Revenue Service. Any required adjustments will be made upon completion of the IRS audit.
13.
COMMITMENTS AND CONTINGENCIES
The Company leases office buildings and other property under operating leases. Future minimum lease payments, in thousands, for operating leases with initial non-cancelable lease terms in excess of one year as of December 31, 2006, were as follows:
Rent expense for operating leases with terms exceeding one month was $3.5 million in 2006, $2.3 million in 2005 and $1.5 million in 2004.
As of December 31, 2006, the Company had approximately $0.6 million in letters of credit outstanding related to various state and federal bonding requirements.
In August 2001, a group of royalty owners, Athel E. Williams et al., brought suit against the Company and three of its subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd, one of Quicksilver’s subsidiaries, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who have yet to be determined. The pleadings of the plaintiffs seek damages in an unspecified amount and injunctive relief against future underpayments. On January 21, 2005, the Circuit Court issued an order certifying certain claims to proceed on behalf of a class. On July 25, 2006, the Michigan Court of Appeals reversed the certification of all claims on appeal and remanded the case to the trial court for further proceedings. Based on information currently available to the Company, the Company’s management believes that the final resolution of this matter will not have a material effect on its financial position, results of operations, or cash flows.
The Company has contracts for the use of drilling rigs in its drilling and exploration programs for periods ranging from one to three years at estimated day rates ranging from $18,500 to $22,000 per day. Each of the contracts requires payment of the specified day rate for the entire lease term of each contract regardless of the Company’s utilization of the drilling rigs. As of December 31, 2006, commitments under these contracts, in thousands, were as follows:
On October 13, 2006, we filed suit in the 342nd Judicial District Court in Tarrant County, Texas against Eagle Drilling, LLC and Eagle Domestic Drilling Operations, LLC (successor in interest to Eagle Drilling, together “Eagle”) regarding three contracts for drilling rigs in which the Company alleges that the first rig furnished by Eagle exhibited operating deficiencies and safety defects. The Company seeks a declaratory judgment that (i) the contracts are void and (ii) that Eagle is not entitled to early termination compensation provided for in the contracts. The Company also seeks rescission of the contracts and claim we are entitled to recover damages incurred due to Eagle’s failure to perform. On October 23, 2006, Eagle Domestic Drilling sued Quicksilver in District Court of Cleveland County, Oklahoma for (i) breach of contract as to each of the three drilling contracts alleging damages of $29 million plus punitive damages and interest and (ii) tortious breach of contract alleging damages in an unspecified amount in excess of $10,000. Eagle Domestic Drilling also sought a declaratory judgment that, among
other things, the contracts are valid and binding. Subsequently, on January 19, 2007, Eagle Domestic Drilling and its parent, Blast Energy Services, Inc., filed for Chapter 11 bankruptcy the United States Bankruptcy Court for the Southern District of Texas, Houston Division. At the date of this filing, the suit in Tarrant County is still pending, but is stayed. On February 21, 2007, The lawsuit in Cleveland County was dismissed. The final resolution of this matter is not expected to have a material effect on the Company’s financial condition, results of operations, or cash flows.
The Company entered into firm transportations contract with pipelines during 2006. Under the contracts, we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our production committed to the pipelines is expected to meet, or exceed, the daily volumes provided in the contracts. As of December 31, 2006, commitments under these contracts, in thousands, were as follows:
The Company is subject to various possible contingencies, which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.
14.
MINORITY INTEREST
Effective April 1, 2006, the Company contributed its Cowtown gas processing facility to Cowtown Gas Processing Partners LP (“Processing Partners”) for a 95% interest in Processing Partners (1% interest as the general partner and 94% as a limited partner) through its wholly-owned subsidiary Cowtown Gas Processing LP. As general partner, the Company receives $15,000 per month for management of Processing Partners. A minority owner initially contributed $1.4 million to Processing Partners for a 5% limited partnership interest in Processing Partners. The minority owner contributed an additional $1.7 million to Processing Partners to fund capital expenditures in 2006. The minority owner’s share of partnership loss in 2006 was $0.1 million.
Also effective April 1, 2006, Quicksilver contributed its Cowtown pipeline assets to Cowtown Pipeline Partners LP (“Pipeline Partners”) for a 93% interest in Pipeline Partners (1% as the general partner and 92% as a limited partner) through its wholly-owned subsidiary Cowtown Pipeline LP. As general partner, the Company receives $5,000 per month for management of Pipeline Partners. Two minority owners initially contributed a total of $3.1 million to Pipeline Partners for limited partnership interests totaling 7%. The minority owners contributed an additional $0.9 million to Pipeline Partners to fund capital expenditures in 2006. Minority interest expense for the minority owners’ share of partnership income in 2006 was $0.2 million.
15.
EMPLOYEE BENEFITS
Quicksilver has a 401(k) retirement plan available to all employees with three months of service and who are at least 21 years of age. Until January 1, 2006 the Company made discretionary contributions to the plan. Effective January 1, 2006, the Company’s Board of Directors approved amendments to the plan to provide for a Company
match of employees’ contributions and a fixed annual contribution by the Company in addition to discretionary contributions by the Company to the plan. Company contributions were $1.4 million, $1.0 million and $0.3 million for the years ended December 31, 2006, 2005 and 2004, respectively.
The Company maintains a self-funded health benefit plan that covers all eligible U.S. employees of the Company. The plan has been reinsured on an individual claim and total group claim basis. Quicksilver is responsible for payment of the first $50,000 for each individual claim. The claim liability for the total group was $2.2 million, $1.8 million and $2.2 million for the plan years ended June 30, 2006, 2005 and 2004, respectively. Aggregate level reinsurance is in place for payment of claims up to $1 million over and above the estimated maximum claim liability of $2.0 million for the plan year ending June 30, 2007. Administrative expenses for each of the plan years ended June 30, 2006, 2005 and 2004 were $0.4 million.
16.
STOCKHOLDERS’ EQUITY
Common Stock, Preferred Stock and Treasury Stock
The Company is authorized to issue 200 million shares of common stock with a par value per share of one cent ($0.01) and 10 million shares of preferred stock with a par value per share of one cent ($0.01). At December 31, 2006, the Company had 77,601,922 shares of common stock outstanding.
The following table shows common share and treasury share activity since January 1, 2004:
Stockholder Rights Plan
On March 11, 2003, the Company’s board of directors declared a dividend distribution of one preferred share purchase right for each outstanding share of common stock of the Company outstanding on March 26, 2003. As amended through December 31, 2006, each right, when it becomes exercisable, entitles stockholders to buy one one-thousandth of a share of the Company’s Series A Junior Participating Preferred Stock at an exercise price of $180.00.
The rights will be exercisable only if such a person or group acquires 15% or more of the common stock of Quicksilver or announces a tender offer the consummation of which would result in ownership by such a person or group (an “Acquiring Person”) of 15% or more of the common stock of the Company. This 15% threshold does not apply to certain members of the Darden family and affiliated entities, which collectively owned, directly or indirectly, approximately 34% of the Company’s common stock at December 31, 2006.
If an Acquiring Person acquires 15% or more of the outstanding common stock of the Company, each right will entitle its holder to purchase, at the right’s then-current exercise price, a number of common shares of the Company having a market value of twice such price. If Quicksilver is acquired in a merger or other business combination
transaction after an Acquiring Person has acquired 15% or more of the outstanding common stock of the Company, each right will entitle its holder to purchase, at the right’s then-current exercise price, a number of the acquiring company’s common shares having a market value of twice such price.
Prior to the acquisition by an Acquiring Person of beneficial ownership of 15% or more of the common stock of Quicksilver, the rights are redeemable for $0.01 per right at the option of the board of directors of the Company.
Employee Stock Plans
1999 and 2004 Plans
On October 4, 1999, the Board of Directors adopted the Company’s 1999 Stock Option and Retention Stock Plan (the “1999 Plan”), which was approved at the annual stockholders’ meeting held in June 2000. Upon approval of the 1999 Plan, 3.9 million shares of common stock were reserved for issuance pursuant to grants of incentive stock options, non-qualified stock options, stock appreciation rights and retention stock awards. Pursuant to an amendment approved at the annual shareholders meeting held in May 2004, an additional 3.6 million shares were reserved for issuance pursuant to the 1999 Plan.
In February 2004, the Board of Directors adopted the Company’s 2004 Non-Employee Director Equity Plan (the “2004 Plan”), which was approved at the annual stockholders’ meeting held in May 2004. There were 750,000 shares reserved under the 2004 Plan, which provided for the grant of non-qualified options and restricted stock awards to Quicksilver’s non-employee directors.
Under terms of the 1999 Plan and 2004 Plan, retention stock awards and options were granted to officers, employees and non-employee directors at an exercise price not less than 100% of the fair market value on the date of grant. Incentive stock options and non-qualified options may not be exercised more than ten years from date of grant. At December 31, 2005, 2,566,449 shares of common stock were available for issuance under the 1999 and 2004 Plans.
Equity Plan
On March 17, 2006, the Board of Directors of the Company approved the Company’s 2006 Equity Plan, subject to stockholder approval, and recommended that the 2006 Equity Plan be submitted to the Company’s stockholders at the annual meeting of stockholders in 2006. On May 23, 2006, the Company’s stockholders approved the 2006 Equity Plan. Upon approval of the 2006 Equity Plan, seven million shares of common stock were reserved for issuance pursuant to grants of stock options, appreciation rights, restricted shares, restricted stock units, performances shares and performances units and senior executive plan bonuses. Executive officers, other employees, consultants and non-employee directors of the Company or a subsidiary of the Company are eligible to participate in the 2006 Equity Plan. Under the terms of the 2006 Equity Plan, options may be granted at an exercise price that is not less than 100% of the fair market value on the date of grant and may not be exercised more than ten years from the date of grant. Upon approval of the 2006 Equity Plan, the Company ceased to grant additional awards under the 1999 Plan and the 2004 Plan. At December 31, 2006, 6,813,863 shares of common stock were available for issuance under the 2006 Equity Plan.
Stock Options
The following table summarizes the Company’s stock options activity for the three years ended December 31, 2006.
Cash received from the exercise of stock options totaled $19.7 million, $2.9 million and $2.5 million for the years ended December 31, 2006, 2005 and 2004, respectively.
The fair value of stock options was estimated on the grant date using the Black-Scholes option pricing model with the following weighted average assumptions:
The following table summarizes information about stock options outstanding at December 31, 2006.
The stock options vested and exercisable at December 31, 2006 had an intrinsic value of $23.5 million and a weighted average term of 2.2 years. The stock options vested or expected to vest at December 31, 2006 had an intrinsic value of $28.1 million and a weighted average terms of 2.4 years.
Restricted Stock
The following table summarizes the Company’s restricted stock and stock unit activity for the two years ended December 31, 2006.
The total fair value of shares vested during the years ended December 31, 2006 and 2005 was $2.1 million and $0.6 million, respectively. No restricted stock was outstanding at December 31, 2004.
17.
OTHER REVENUE
Other revenue consists of the following:
Revenue for processing of natural gas and gathering of natural gas and NGLs represents revenue earned from third parties.
18.
DISCONTINUED DRILLING OPERATIONS
On July 28, 2005, Quicksilver purchased three drilling rigs and other associated assets for $5.6 million. Thereafter, the Company took over drilling operations and began construction of two additional drilling rigs. The Company sold the drilling assets and drilling rigs under construction on September 29, 2005 for $8.2 million. The purchaser of these assets agreed to conduct drilling operations on the Company’s Barnett Shale properties, using the acquired rigs at market rates and on other customary contract terms. During the fourth quarter of 2005, Quicksilver received an additional $0.37 million for inventory, furniture and fixtures. The Company’s estimated book value for all drilling-related assets sold was $8.23 million. The Company recorded a $0.16 million gain before income tax expense from the sale. During the two-month operating period when the rigs were owned by Quicksilver, revenue earned in drilling operations was $1.9 million and operating income before income taxes was $0.1 million.
19.
CONDENSED CONSOLIDATING FINANCIAL INFORMATION
The following subsidiaries of Quicksilver are guarantors of Quicksilver’s Senior Subordinated Notes issued March 16, 2006: Mercury Michigan, Inc., Terra Energy Ltd., GTG Pipeline Corporation, Cowtown Pipeline Funding, Inc., Cowtown Pipeline Management, Inc., Terra Pipeline Company, Beaver Creek Pipeline, LLC, Cowtown Pipeline LP, and Cowtown Gas Processing, LP (collectively, the “Guarantor Subsidiaries”). Each of the
Guarantor Subsidiaries is 100% owned by Quicksilver. The guarantees are full and unconditional and joint and several. The condensed consolidating financial statements below present the financial position, results of operations and cash flows of Quicksilver, the Guarantor Subsidiaries and non-guarantor subsidiaries of Quicksilver.
Condensed Consolidating Balance Sheets
Condensed Consolidating Statement of Income
Condensed Consolidating Statements of Cash Flows
20.
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest and income taxes is as follows:
Other non-cash transactions are as follows:
21.
RELATED PARTY TRANSACTIONS
As of December 31, 2006, members of the Darden family, Mercury Exploration Company (“Mercury”) and Quicksilver Energy L.P., entities that are owned by members of the Darden family, beneficially owned approximately 34% of the Company’s outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.
Quicksilver and its associated entities paid $1.4 million, $1.03 million and $0.86 million for rent in 2006, 2005 and 2004, respectively, for rent on buildings owned by Pennsylvania Avenue LP (“PALP”), a Mercury affiliate. Rental rates were determined based on comparable rates charged by third parties. In February 2006, the Company entered into an amendment to its lease with PALP to increase the amount of office space covered thereby. In conjunction with this lease amendment, the Company also agreed to sublease a portion of the property it leases from PALP to Mercury. At December 31, 2006, the Company had future lease obligations to Pennsylvania of $4.6 million through 2009.
During 2006, the Company paid Regal Aviation LLC, an unrelated airplane management company, $0.2 million for use of an airplane owned by Sevens Aviation, LLC, a company owned indirectly by members of the Darden family. Usage rates were determined based on comparable rates charged by third parties. In 2005 and 2004, the Company also paid $11,400 and $5,600, respectively, for the use of an airplane owned by Panther City Aviation LLC, a limited liability company owned in part by Thomas Darden.
Payments received in 2006, 2005 and 2004 from Mercury for sublease rentals, employee insurance coverage and administrative services were $0.1 million, $0.1 million and $0.1 million, respectively. In August 2006, the Company agreed to purchase furniture from PALP for $75,000. The sales price was determined using comparable rates charged by third parties.
On June 23, 2006, Quicksilver received an assignment from KC7 Ranch Ltd. (“KC7”) of an oil and gas lease dated October 25, 2005 from Si Bar, KC Ranch, Ltd. as lessor to KC7 Ranch Ltd. as lessee covering 2,773 acres in exchange for $0.2 million in cash. Under the terms of the assignment of the lease, KC7 is entitled to a 3.3% overriding royalty interest, pursuant to which KC7 will receive payments from Quicksilver based on any future production of oil or gas from the acreage subject to the lease. On July 7, 2006, KC7 Ranch Ltd. as lessor granted an oil and gas lease to Quicksilver covering 2,773 acres in exchange for a cash payment of $0.3 million. The lease has a three year primary term and KC7 is entitled to receive a 20% royalty interest pursuant to which it will receive payments from Quicksilver based on any future production of oil or gas from the acreage subject to the lease. Future payments, if any, pursuant to the royalty and overriding royalty interests cannot be estimated at this time. KC7 is a limited partnership in which Quicksilver Energy LP, an entity controlled by members of the Darden family, owns an 80% limited partner interest and maintains additional preferences in distributions of profit from KC7; the other 20% limited partner interest is owned or controlled by Jeff Cook, our Executive Vice President - Operations, individually and as trustee for his two children. KC7’s general partner is owned equally by Glenn Darden, Thomas Darden, and Anne Darden Self. The purchase price to acquire the leases and the terms of the leases were determined based on comparable prices and terms paid and granted to third parties with respect to similar leases in the area. The approximate 80% net revenue interest that Quicksilver has in these leases is commensurate with that which Quicksilver has with respect to other leases in the area.
22.
SEGMENT INFORMATION
The Company operates in two geographic segments, the United States and Canada. Both areas are engaged in the exploration and production segment of the oil and gas industry. The Company evaluates performance based on operating income.
23.
SUPPLEMENTAL INFORMATION (UNAUDITED)
Proved oil and gas reserves estimates for the Company’s properties in the United States and Canada were prepared by independent petroleum engineers with Schlumberger Data and Consulting Services and LaRoche Petroleum Consultants, Ltd., respectively. The reserve reports were prepared in accordance with guidelines established by the Securities and Exchange Commission and, accordingly, were based on existing economic and operating conditions. Natural gas and crude oil prices in effect as of the date of the reserve reports were used without any escalation except in those instances where the sale of production was covered by contract, in which case the applicable contract prices, including fixed and determinable escalations, were used for the duration of the contract, and thereafter the year-end price was used (See “Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves” below for a discussion of the effect of the different prices on reserve quantities and values.) Operating costs, production and ad valorem taxes and future development costs were based on current costs with no escalation.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of the Company’s natural gas and crude oil reserves or the costs that would be incurred to obtain equivalent reserves.
The changes in proved reserves for the years ended December 31, 2004, 2005 and 2006 were as follows:
The capitalized costs relating to oil and gas producing activities and the related accumulated depletion, depreciation and accretion as of December 31, 2006, 2005 and 2004 were as follows:
Costs incurred in oil and gas property acquisition, exploration and development activities during the years ended December 31, 2006, 2005 and 2004 were as follows:
Results of operations from producing activities for the years ended December 31, 2006, 2005 and 2004 are set forth below:
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of the Company’s natural gas and crude oil properties. An estimate of such value should consider, among other factors, anticipated future prices of natural gas and crude oil, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by applying year-end prices, adjusted for contracts with price floors but excluding hedges, to the estimated future production of the year-end reserves. These prices have varied widely and have a significant impact on both the quantities and value of the proved reserves as reduced prices cause wells to reach the end of their economic life much sooner and also make certain proved undeveloped locations uneconomical, both of which reduce reserves. The following representative natural gas and crude oil year-end prices were used in the Standardized Measure. These prices were adjusted by field for appropriate regional differentials.
Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved natural gas and crude oil properties. Tax credits and net operating loss carry forwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
The standardized measure of discounted cash flows related to proved oil and gas reserves at December 31, 2006, 2005 and 2004 were as follows:
The primary changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2006, 2005 and 2004 were as follows:
24.
SELECTED QUARTERLY DATA (UNAUDITED)
25.
QUICKSILVER GAS SERVICES LP
On February 11, 2007 the Company’s wholly-owned subsidiary, Quicksilver Gas Services LP (“QGSLP”), filed a registration statement on Form S-1 with the Securities and Exchange Commission to become a publicly traded partnership through a proposed underwritten initial public offering. The registration statement contemplates the offering of 3,375,000 common units representing approximately 19% of the limited partner interests in QGSLP, with anticipated aggregate gross proceeds of approximately $67.5 million. Upon completion of the offering, the Company expects to retain common units and subordinated units representing an approximate 75% limited partner interest, and the entire 2% general partner interest in the publicly traded partnership.
QGSLP will engage in the business of gathering and processing natural gas produced from the Barnett Shale formation in the Fort Worth Basin of northern Texas. QGSLP will own a pipeline system and a natural gas processing plant in the southern portion of the Fort Worth Basin.
ITEM 9.
ITEM 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
ITEM 9A.
ITEM 9A.
Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us (including our consolidated subsidiaries) in reports that we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported on a timely basis.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in the Exchange Act Rule 13a-15(f). Our management conducted an assessment of our internal control over financial reporting based on the framework established by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework. Based on this assessment, our management has concluded that, as of December 31, 2006, our internal control over financial reporting is effective. Our independent registered public accounting firm, Deloitte & Touche LLP, have issued an attestation report on management’s assessment of our internal control over financial reporting, as stated in their report included herein.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Quicksilver Resources Inc.
Fort Worth, Texas
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Quicksilver Resources Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2006 of the Company and our report dated February 28, 2007 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the adoption of Statement of Financial Accounting Standards No. 123 (Revised 2004), Share-Based Payments.
/s/ Deloitte & Touche LLP
Fort Worth, Texas
February 28, 2007
ITEM 9B.
ITEM 9B.
Other Information
None.
PART III
ITEM 10.
ITEM 10.
Directors, Executive Officers and Corporate Governance
The information concerning our directors set forth under “Corporate Governance Matters - the Board of Directors” and “Corporate Governance Matters - Family Relationship Between Directors” in the proxy statement for our May 23, 2007 annual meeting of stockholders is incorporated herein by reference. The information concerning any changes to the procedure by which a security holder may recommend nominees to the board of directors set forth under “Corporate Governance Matters - Committees of the Board” in the proxy statement for our May 23, 2007 annual meeting of stockholders is incorporated herein by reference. Certain information concerning our executive officers is set forth under the heading “Business - Executive Officers” in Item 1 of this annual report. The information concerning compliance with Section 16(a) of the Exchange Act is set forth under “Section 16(a) Beneficial Ownership Reporting Compliance” in the proxy statement for our May 23, 2007 annual meeting of stockholders is incorporated herein by reference.
The information concerning our audit committee set forth under “Corporate Governance Matters - Committees of the Board” in the proxy statement for our May 23, 2007 annual meeting of stockholders is incorporated herein by reference.
The information regarding our Code of Ethics set forth under “Corporate Governance Matters - Corporate Governance Principles, Processes and Code of Business Conduct and Ethics” in the proxy statement for our May 23, 2007 annual meeting of stockholders is incorporated herein by reference.
ITEM 11.
ITEM 11.
Executive Compensation
The information set forth under “Corporate Governance Matters - Compensation of Directors,” “Executive Compensation,” “Compensation Discussion and Analysis,” and “Compensation Committee Report” in our proxy statement for our May 23, 2007 annual meeting of stockholders is incorporated herein by reference.
ITEM 12.
ITEM 12.
Security Ownership of Management and Certain Beneficial Owners and Management and Related Stockholder Matters
The information set forth under “Security Ownership of Management and Certain Beneficial Holders” in the proxy statement for our May 23, 2007 annual meeting of stockholders is incorporated herein by reference. The information regarding our equity plans under which shares of our common stock are authorized for issuance as set forth under “Equity Compensation Plan Information” in the proxy statement for our May 23, 2007 annual meeting of stockholders is incorporated herein by reference.
ITEM 13.
ITEM 13.
Certain Relationships and Related Transactions, and Director Independence
The information set forth under “Transactions with Management and Certain Stockholders,” and “Corporate Governance Matters - Independent Directors” in the proxy statement for our May 23, 2007 annual meeting of stockholders is incorporated herein by reference.
ITEM 14.
ITEM 14.
Principal Accountant Fees and Services
The information set forth under “Independent Registered Public Accountants” in the proxy statement for our May 23, 2007 annual meeting of stockholders is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
Exhibits and Financial Statement Schedules
We will furnish you, without charge, a copy of any exhibit to this Annual Report on Form 10-K upon written request. Written requests to obtain an exhibit should be sent to the Investor Relations Department at 777 West Rosedale Street, Suite 300, Fort Worth, Texas 76104.
The following documents are filed as part of this report:
1. Financial Statements:
The following financial statements of ours and the report of our Independent Auditors thereon are included on pages 53 through 98 of this Form 10-K.
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2006 and 2005
Consolidated Statements of Income and Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2006, 2005 and 2004
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
Notes to Consolidated Financial Statements for the Years Ended December 31, 2006, 2005 and 2004
2. Financial Statement Schedules:
All schedules are omitted because the required information is inapplicable or the information is presented in the financial statements or the notes thereto.
3. Exhibits:
*
Filed herewith.
+
Identifies management contracts and compensatory plans or arrangements.
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Quicksilver Resources Inc.
(the “Registrant”)
By:
/s/ Glenn Darden
Glenn Darden
President and Chief Executive Officer
Dated: March 1, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on behalf of the registrant and in the capacities and on the dates indicated have signed this report below.