Quicksilver Resources 10K/A 2008 Annual report (amended)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

(Amendment No. 3)


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

For the fiscal year ended December 31, 2008


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

For the transition period from to

Commission file number: 001-14837

QUICKSILVER RESOURCES INC.

(Exact name of registrant as specified in its charter)


Delaware		75-2756163
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

777 West Rosedale St., Fort Worth, Texas		76104
(Address of principal executive offices)		(Zip Code)

817-665-5000
(Registrant’s telephone number, including area code)

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


Title of each class		Name of each exchange on which registered

Common Stock, $0.01 par value per share		New York Stock Exchange
Preferred Share Purchase Rights,
$0.01 par value per share		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yesþ Noo

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

Yeso Noþ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yesþ Noo

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.o

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


Large accelerated filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yeso Noþ

As of June 30, 2008, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $4,067,732,259 based on the closing sale price of $38.64 as reported on the New York Stock Exchange.

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


Class		Outstanding at February 13, 2009

Common Stock, $0.01 par value per share		168,752,835 shares

DOCUMENTS INCORPORATED BY REFERENCE


Document		Parts Into Which Incorporated

Proxy Statement for the Registrant’s May 20,		Part III
2009 Annual Meeting of Stockholders

Explanatory Note

This Amendment No. 3 to the Annual Report on Form 10-K (this “Amendment No. 3” or this “Report”) of Quicksilver Resources Inc. (“Quicksilver”) for the year ended December 31, 2008, originally filed on March 3, 2009 (as amended on March 9, 2009 and June 1, 2009, the “Original Form 10-K”) is being filed to correct certain footnote disclosures regarding amounts reported for Quicksilver’s guarantor and non-guarantor subsidiaries and to include disclosure of information for restricted subsidiaries that was not previously presented. Notes 14 and 21 in the Original Form 10-K have been corrected for these matters. In Note 21 Condensed Consolidating Financial Information, the Company has identified and corrected errors in the presentation of its guarantor and non-guarantor condensed consolidating financial information. Also, as previously disclosed in Note 14 Long Term Debt, the Company indicated that it was in compliance with its long term debt, other notes and loans. Subsequent to the issuance of the Original Form 10-K, the Company determined that financial information about the Company and its restricted subsidiaries should be included in the notes to the consolidated financial statements pursuant to its supplemental indentures. Accordingly, Note 14 has been restated to reference the inclusion within Notes 21 and 27 of the condensed consolidating financial information about the Company and its restricted subsidiaries. Note 27 in Item 8 of this Amendment No. 3 contains added and restated guarantor and non-guarantor unaudited interim condensed consolidating financial information.Management’s Discussion and Analysis of Financial Condition and Results of Operationin Item 7 has also been revised to provide information about the Company and its restricted subsidiaries. Also, Item 9AControls and Procedures has been amended to report the material weaknesses associated with the restatement described above and the risk factors in Item 1ARisk Factors have been similarly updated. Items previously included in the Original Form 10-K not affected by the restatement have been omitted.

Except for the adoption of accounting pronouncements more fully discussed below, this Amendment No. 3 does not alter or adjust the consolidated results of operation, financial position or cash flows in the Original 10-K. Unless otherwise noted, all of the information in this Amendment No. 3 is as of December 31, 2008 and reflects no events after that date other than the restatement and the adoption of accounting pronouncements described below. Our previously filed Quarterly Report on Form 10-Q for the three months ended March 31, 2009 originally filed on May 7, 2009 will also be amended and filed.

The consents of Schlumberger Data and Consulting Services, LaRoche Petroleum Consultants, Ltd., Netherland, Sewell & Associates Inc., PricewaterhouseCoopers LLP and Deloitte & Touche LLP and new certifications of Quicksilver’s principal chief executive officer and principal financial officer are also filed as exhibits to this Amendment No. 3 under Item 15.

Quicksilver is also amending the Original Form 10-K to revise certain financial information to correspond to the manner in which Quicksilver presents such financial information following its adoption of the accounting pronouncements described below. All changes to consolidated financial information solely relate to the adoption of accounting pronouncements and are unrelated to the error correction discussed above.

As previously disclosed in the Quarterly Report on Form 10-Q for the three months ended March 31, 2009, on January 1, 2009, we adopted the following accounting pronouncements (collectively the “Adopted Pronouncements”):

	•		SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51 (“SFAS No. 160”);

	•		FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (“FSP APB 14-1”); and

	•		FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payments Transactions Are Participating Securities” (“FSP EITF 03-6-1”).

This Report revises financial information to reflect the Company’s retrospective application of the Adopted Pronouncements including:

	•		Item 6. Selected Financial Data;

	•		Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations;

	•		Item 8. Financial Statements and Supplementary Data; and

	•		Item 15. Exhibits and Financial Statement Schedules.

INDEX TO ANNUAL REPORT ONFORM 10-K/A
For the Year Ended December 31, 2008

Except as otherwise specified and unless the context otherwise requires, references to the “Company,” “Quicksilver,” “we,” “us,” and “our” refer to Quicksilver Resources Inc. and its subsidiaries.

As further discussed in Note 21 (Restated) to our consolidated financial statements in Item 8 to this Report the Company has corrected financial information previously reported and has included information about the Company and its restricted subsidiaries, and the following risk factors have been updated to reflect risks associated therewith.



ITEM 1A.	Risk Factors

You should carefully consider the following risk factors together with all of the other information included in this annual report, including the financial statements and related notes, when deciding to invest in us. You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report could have a material adverse effect on our business, financial position, results of operations and cash flows.

Natural gas, NGL and crude oil prices fluctuate widely, and low prices could have a material adverse impact on our business, financial condition, results of operations and cash flows.

Our revenue, profitability and future growth depend in part on prevailing natural gas, NGL and crude oil prices. These prices also affect the amount of cash flow available to service our debt, pay for our capital expenditures and fund our other liquidity needs, as well as our ability to borrow, raise additional capital and comply with the terms of our debt agreements. Among other things, the amount we can borrow under our Senior Secured Credit Facility is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas, NGLs and crude oil that we can economically produce.

While prices for natural gas and crude oil may be favorable at any point in time, they fluctuate widely, particularly as evidenced by price movements in the latter half of 2008. Among the factors that can cause these fluctuations are:

	•		domestic and foreign demand for natural gas and crude oil;

	•		the level of domestic and foreign natural gas and crude oil supplies;

	•		the price and availability of alternative fuels;

	•		weather conditions;

	•		domestic and foreign governmental regulations;

	•		impact of trade organizations, such as OPEC;

	•		political conditions in oil and natural gas producing regions; and

	•		worldwide economic conditions.

Due to the volatility of natural gas and crude oil prices and our inability to control the factors that influence them, we cannot predict future pricing levels.

If natural gas, NGL or crude oil prices decrease, our exploration and development efforts are unsuccessful or our costs increase substantially, we may be required to recognize impairment of our oil and gas properties, which could have a material adverse effect on our financial condition, our results of operations and our ability to borrow under and comply with our debt agreements.

We employ the full cost method of accounting for our oil and gas properties, whereby all costs associated with acquiring, exploring for, and developing natural gas and crude oil reserves are capitalized and accumulated in separate country cost centers. These capitalized costs are amortized based on production from the reserves for each country cost center. Each capitalized cost pool cannot exceed the net present value of the underlying natural gas, NGL and crude oil reserves. Impairment to the carrying value of our oil and gas properties was recognized in the fourth quarter of 2008 and could occur again in the future if natural gas, NGL or crude oil prices at a reporting period end result in decreased value of our reserves. Increased operating and capitalized costs without incremental increases in natural gas and crude oil reserves could also trigger impairment based on decreased value of our reserves. In the event of impairment of our oil and gas properties, we reduce their carrying value and recognize expense in the amount of the impairment, which could be material and could adversely affect our financial condition and results of operations and our ability to borrow under and comply with the terms of our debt agreements.

Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

The process of estimating natural gas, NGL and crude oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves disclosed in our filings with the SEC.

In order to prepare these estimates, we and independent reserve engineers engaged by us must project production rates and timing of development expenditures. We and the engineers must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions with respect to natural gas and crude oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of natural gas, NGL and crude oil reserves are inherently imprecise.

Actual future production, natural gas, NGL and crude oil prices and revenue, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and crude oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed in this annual report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing petroleum prices and other factors, which may be beyond our control.

At December 31, 2008, approximately 37% of our estimated proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain than comparable developed reserves. Recovery of undeveloped reserves requires additional capital expenditures and successful drilling and completion operations. Our reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves and the costs associated with them in accordance with industry standards, there is risk that the estimated costs are inaccurate, that development will not occur as scheduled or that actual results will not be as estimated.

The present value of future net cash flows disclosed in Item 8 of this annual report is not necessarily the fair value of our estimated proved natural gas and crude oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of period end. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by natural gas, NGL and crude oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of natural gas and crude oil properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and natural gas industry in general will affect the appropriateness of the 10% discount factor in arriving at the reserves’ actual fair value.

Our production is concentrated in a small number of geographic areas.

Approximately 75% of our 2008 production was from Texas and approximately 24% was from Alberta, Canada. Because of our concentration in these geographic areas, any regional events that increase costs, reduce availability of equipment or supplies, reduce demand or limit production, including weather and natural disasters, may impact us more than if our operations were more geographically diversified.

Our Canadian operations present unique risks and uncertainties, different from or in addition to those we face in our domestic operations.

In addition to the various risks associated with our U.S. operations, risks associated with our operations in Canada, where we have substantial operations, include, among other things, risks related to increases in taxes and governmental royalties, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations. Laws and policies of the United States affecting foreign trade and taxation may also adversely affect our Canadian operations.

We may have difficulty financing our planned growth.

We have experienced capital expenditure and working capital needs, particularly as a result of our property acquisition and drilling activities. For 2009, we plan to operate our capital program within our operating cash flows.However, in the future, we may require additional financing above the level of cash generated by our operations to fund our growth. If revenue decreases as a result of lower petroleum prices or otherwise, our ability to expend the

capital necessary to replace our reserves or to maintain production of current levels may be limited, resulting in a decrease in production over time. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, we cannot be certain that additional financing will be available to us on acceptable terms or at all. In the event additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis.

We are vulnerable to operational hazards, transportation dependencies, regulatory risks and other uninsured risks associated with our activities.

The oil and natural gas business involves operating hazards such as well blowouts, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, treatment plant “downtime”, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could cause us to experience substantial losses. Also, the availability of a ready market for our natural gas and crude oil production depends on the proximity of reserves to, and the capacity of, natural gas and crude oil gathering systems, treatment plants, pipelines and trucking or terminal facilities.

U.S. and Canadian federal, state and provincial regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could adversely affect our ability to produce and market our natural gas, NGLs and crude oil. In addition, we may be liable for environmental damage caused by previous owners of properties purchased or leased by us.

As a result of operating hazards, regulatory risks and other uninsured risks, we could incur substantial liabilities to third parties or governmental entities. We maintain insurance against some, but not all, of such risks and losses in accordance with customary industry practice. Generally, environmental risks are not fully insurable. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.

The failure to replace our reserves could adversely affect our production and cash flows.

Our future success depends upon our ability to find, develop or acquire additional reserves that are economically recoverable. Our proved reserves will generally decline as reserves are produced, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves. In order to increase reserves and production, we must continue our development drilling and recompletion programs or undertake other replacement activities. Our current strategy is to maintain our focus on low-cost operations while increasing our reserve base and production through exploration and development of our existing properties. Our planned exploration or development projects or any acquisition activities that we may undertake might not result in meaningful additional reserves and we might not have continuing success drilling productive wells. Furthermore, while our revenue may increase if prevailing petroleum prices increase materially, our finding costs also could increase.

We have risk through our investment in BBEP.

We own a 41% limited partner interest in BBEP from which we expect to receive distributions. We have no management oversight over BBEP, its financial condition, its operating results or its financial reporting process and are subject to the risks associated with BBEP’s business and operations. Moreover, the management of BBEP has discretion over the amount, if any, that they distribute to unitholders.

The nature of our ownership interest in a publicly-traded entity subjects us to market risks associated with most ownership interests traded on a public exchange. Sales of substantial amounts of BBEP limited partner units, or a perception that such sales could occur, and various other factors, could adversely affect the market price of BBEP limited partner units. Impairment to the carrying value of BBEP limited partnership units was recognized in the forth quarter of 2008, and could occur again in the future if the market price for BBEP units declines further. In the event of impairment of our BBEP units, we reduce the carrying value of our BBEP units and recognize expense in the amount of the impairment, which could be material and could adversely affect our financial condition and results of operations and our ability to borrow under and comply with the provisions of our debt agreements.

We have risk through our ownership of KGS.

Through our ownership interest in KGS, we share in KGS’ results of operations and may be entitled to distributions from KGS. Accordingly, we have diminished control over assets owned by KGS and assets which KGS has a right to acquire. We are also subject to the risks associated with KGS’ business and operations, including, but not limited to:

	•		changes in general economic conditions;

	•		fluctuations in natural gas prices;

	•		failure or delays in us and third parties achieving expected production from natural gas projects;

	•		competitive conditions in the midstream industry;

	•		actions taken on non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers;

	•		changes in the availability and cost of capital;

	•		operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

	•		construction costs or capital expenditures exceeding estimated or budgeted amounts;

	•		the effects of existing and future laws and governmental regulations;

	•		the effects of future litigation; and

	•		other factors discussed in KGS’ Annual Report on Form 10-K and as are or may be detailed from time to time in KGS’ public announcements and other filings with the SEC.

We cannot control the operations of gas processing and transportation facilities we do not own or operate.

We deliver our Canadian production to market primarily by either the TransCanada or ATCO systems. We have no influence over the operation of these facilities and must depend upon their owners to minimize any loss of processing and transportation capacity.

The loss of key personnel could adversely affect our ability to operate.

Our operations are dependent on a relatively small group of key management personnel, including our executive officers. There is a risk that the services of all of these individuals may not be available to us in the future. Because competition for experienced personnel in our industry can be intense, we may be unable to find acceptable replacements with comparable skills and experience and their loss could have an adverse effect on us.

Competition in our industry is intense, and we are smaller and have a more limited operating history than many of our competitors.

We compete with major and independent oil and natural gas companies for property acquisitions. We also compete for the equipment and labor required to develop and operate our properties. Many of our competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be able to absorb the burden of any changes in federal, state, provincial and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and productive natural gas and crude oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and crude oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to complete transactions in this highly competitive environment. Furthermore, the oil and natural gas industry competes with other industries in supplying the energy and fuel needs of industrial, commercial, and other consumers.

Hedging our production may result in losses or limit our ability to benefit from price increases.

To reduce our exposure to petroleum price fluctuations, we have entered into financial hedging arrangements which may limit the benefit we would receive from increases in petroleum prices. These hedging arrangements also expose us to risk of financial losses in some circumstances, including the following:

	•		our production could be materially less than expected; or

	•		the other parties to the hedging contracts could fail to perform their contractual obligations.

The result of natural gas market prices exceeding collar ceilings requires us to make monthly cash payments. If we choose not to engage in hedging arrangements in the future, we could be more affected by changes in natural gas, NGL and crude oil prices than our competitors who engage in hedging arrangements.

Delays in obtaining oil field equipment and increases in drilling and other service costs could adversely affect our ability to pursue our drilling program and our results of operations.

As natural gas, NGL and crude oil prices increase, demand and costs for drilling equipment, crews and associated supplies, equipment and services can increase significantly. We cannot be certain that in a higher petroleum price environment we would be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we could experience shortages of, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services. Any such delays and price increases could adversely affect our ability to pursue our drilling program and our results of operations.

Our activities are regulated by complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.

Natural gas, NGL and crude oil operations are subject to various U.S. and Canadian federal, state, provincial and local government laws and regulations that could change in response to economic or political conditions. Matters that are typically regulated include:

	•		discharge permits for drilling operations;

	•		water obtained for drilling purposes;

	•		drilling permits and bonds;

	•		reports concerning operations;

	•		spacing of wells;

	•		disposal wells;

	•		unitization and pooling of properties;

	•		environmental protection; and

	•		taxation.

From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and crude oil wells below actual production capacity to conserve supplies of natural gas and crude oil. We also are subject to changing and extensive tax laws, the effects of which cannot be predicted.

The development, production, handling, storage, transportation and disposal of natural gas and crude oil, by-products and other substances and materials produced or used in connection with our operations are also subject to laws and regulations primarily relating to protection of human health and the environment. The discharge of natural gas, crude oil or pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may result in the assessment of civil or criminal penalties or require us to incur substantial costs of remediation.

Legal and tax requirements frequently are changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We cannot assure you that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, will not materially adversely affect our business, results of operations and financial condition.

The risks associated with our debt could adversely affect our business, financial condition and results of operations and the value of our securities.

Subject to the limits contained in our various debt agreements, we may incur additional debt. Our ability to incur additional debt and to comply with the terms of our debt agreements is affected by a variety of factors, including natural gas, NGL and crude oil prices and their effects on our financial condition, results of operations and

cash flows. Among other things, our ability to borrow under our Senior Secured Credit Facility is subject to the quantity and value of our proved reserves and other assets, including our investment in BBEP. If we incur additional debt or fail to increase the quantity and value of our proved reserves, the risks that we now face as a result of our indebtedness could intensify.

We have demands on our cash resources in addition to interest expense, including operating expenses, principal payments under our debt and funding of our capital expenditures. Our level of debt, the value of our oil and gas properties and other assets, the demands on our cash resources, and the provisions of our debt agreements could have important effects on our business and on the value of our securities. For example, they could:

	•		make it more difficult for us to satisfy our obligations with respect to our debt;

	•		require us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing the amount of our cash flow available for working capital, capital expenditures, acquisitions and other general corporate purposes;

	•		require us to make principal payments if the quantity and value of our proved reserves are insufficient to support our level of borrowings;

	•		limit our flexibility in planning for, or reacting to, changes in the oil and natural gas industry;

	•		place us at a competitive disadvantage compared to our competitors who may have lower debt service obligations and greater financing flexibility than we do;

	•		limit our financial flexibility, including our ability to borrow additional funds;

	•		increase our interest expense on our variable rate borrowings if interest rates increase;

	•		limit our ability to make capital expenditures to develop our properties;

	•		increase our vulnerability to exchange risk associated with Canadian dollar denominated indebtedness;

	•		increase our vulnerability to general adverse economic and industry conditions; and

	•		result in a default or event of default under our debt agreements, which, if not cured or waived, could adversely affect our financial condition, results of operations and cash flows.

Our ability to pay principal and interest on our debt, to otherwise comply with the provisions of our debt agreements and to refinance our debt may be affected by economic and capital markets conditions and other factors that may be beyond our control. If we are unable to service our debt and fund our other liquidity needs, we will be forced to adopt alternative strategies that may include:

	•		reducing or delaying capital expenditures;

	•		seeking additional debt financing or equity capital;

	•		selling assets;

	•		restructuring or refinancing debt; or

	•		reorganizing our capital structure.

We cannot assure you that we would be able to implement any of these strategies on satisfactory terms, if at all, and our inability to do so could cause the holders of our securities to experience a partial or total loss of their investment in us.

Our debt agreements restrict our ability to engage in certain activities.

Our debt agreements restrict our ability to, among other things:

	•		incur additional debt;

	•		pay dividends on or redeem or repurchase capital stock;

	•		make certain investments;

	•		incur or permit certain liens to exist;

	•		enter into certain types of transactions with affiliates;

	•		merge, consolidate or amalgamate with another company;

	•		transfer or otherwise dispose of assets, including capital stock of subsidiaries; and

	•		redeem subordinated debt.

Our debt agreements, among other things, also require the maintenance of financial covenants that are more fully described in Note 14 to the consolidated financial statements in Item 8 of this annual report. Our ability to comply with these covenants and other provisions of our debt agreements may be affected by events beyond our control, and we may be unable to comply with all aspects of our debt agreements in the future. In addition, our ability to borrow under our Senior Secured Credit Facility is dependent upon the quantity and value of our proved reserves and other assets, including our investment in BBEP.

The provisions of our debt agreements may affect the manner in which we obtain future financing, pursue attractive business opportunities and plan for and react to changes in business conditions. In addition, failure to comply with the provisions of our debt agreements could result in an event of default which could enable the applicable creditors, subject to the terms and conditions of the applicable agreement, to declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. Moreover, any of our debt agreements that contain a cross-default or cross-acceleration provision could also be subject to acceleration. If we were unable to repay the accelerated amounts, the creditors could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, there can be no assurance that our assets would be sufficient to repay such debt in full, and the holders of our securities could experience a partial or total loss of their investment.

Parties with whom we do business may become unable or unwilling to timely perform their obligations to us.

We enter into contracts and transactions with various third parties, including contractors, suppliers, customers, lenders and counterparties to hedging arrangements, under which such third parties incur performance or payment obligations to us. Any delay or failure on the part of one or more of such third parties to perform their obligations to us could, depending upon the nature and magnitude of such failure or failures, have a material adverse effect on our business, financial condition and results of operations.

A small number of existing stockholders exercise significant control over our company, which could limit your ability to influence the outcome of stockholder votes.

Members of the Darden family, together with entities controlled by them, beneficially owned approximately 30% of our common stock as of December 31, 2008. As a result, they are generally able to significantly affect the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our charter or bylaws and the approval of mergers and other significant corporate transactions.

A large number of our outstanding shares and shares to be issued upon conversion of our outstanding convertible debentures or exercise of our outstanding options may be sold into the market in the future, which could cause the market price of our common stock to drop significantly, even if our business is performing well.

Our shares that are eligible for future sale may adversely affect the price of our common stock. There were more than 167 million shares of our common stock outstanding at December 31, 2008. Approximately 116 million of these shares are freely tradable without substantial restriction or the requirement of future registration under the Securities Act. In addition, when the conditions permitting conversion of our convertible debentures are satisfied, the holders could elect to convert such debentures. Based on the applicable conversion rate at December 31, 2008, the holders’ election to convert such debentures could result in an aggregate of 9,816,270 shares of our common stock being issued. We also had 1,103,336 options outstanding to purchase shares of our common stock at December 31, 2008 as detailed in Note 20 to the consolidated financial statements in Item 8 of this annual report.

Sales of substantial amounts of common stock, or a perception that such sales could occur, and the existence of conversion and option rights to acquire shares of common stock at prices that may be below the then current market price of the common stock, could adversely affect the market price of our common stock and could impair our ability to raise capital through the sale of our equity securities.

Our amended and restated certificate of incorporation, restated bylaws and stockholder rights plan contain provisions that could discourage an acquisition or change of control without our board of directors’ approval.

Our amended and restated certificate of incorporation and restated bylaws contain provisions that could discourage an acquisition or change of control without our board of directors’ approval. In this regard:

	•		our board of directors is authorized to issue preferred stock without stockholder approval;

	•		our board of directors is classified; and

	•		advance notice is required for director nominations by stockholders and actions to be taken at annual meetings at the request of stockholders.

In addition, we have adopted a stockholder rights plan which could also impede a merger, consolidation, takeover or other business combination involving us, even if that change of control might be beneficial to stockholders, thus increasing the likelihood that incumbent directors will retain their positions. In certain circumstances, the fact that corporate devices are in place that will inhibit or discourage takeover attempts could reduce the market value of our common stock.

We have identified material weaknesses in our internal controls that, if not properly corrected, could result in material misstatements in our financial statements.

We and our auditors have identified two material weaknesses in our system of internal control over financial reporting as of December 31, 2008. A material weakness is a deficiency, or combination of deficiencies in internal controls over financial reporting that results in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

The first material weakness related to the preparation of combined financial information within our condensed consolidating financial information. The condensed consolidating information previously reported contained errors that included “combining adjustments” for non-guarantor subsidiaries being reported within “consolidating eliminations” and in the amounts reported for equity earnings of wholly owned subsidiaries. These errors did not affect the amounts previously reported in our consolidated financial statements. To remedy this material weakness, we have revised our process to better structure the preparation and allow for further review of our consolidating financial information.

The second material weakness related to the monitoring of our financial reporting requirements, particularly with respect to the form and content of our condensed consolidating financial information and the financial information about the Company and our restricted subsidiaries. To remedy this material weakness we have enhanced our process for documenting and satisfying the full extent of our financial reporting requirements.

Although there can be no assurances, we believe these enhancements and improvements, when repeated in future periods, will remediate the material weaknesses described above. If we are not able to remedy the material weaknesses in a timely manner, we may be unable to provide our securityholders with the required financial information in a timely and reliable manner and we may incorrectly report financial information, either of which could subject us to litigation and regulatory enforcement actions.

As further discussed in Note 2 to our consolidated financial statements included in Item 8 of this Report, our consolidated financial statements for each period presented have been adjusted for the retrospective application of the Adopted Pronouncements.

Item 6. Selected Financial Data

The following table sets forth, as of the dates and for the periods indicated, our selected financial information which for each of the three years in the period ended December 31, 2008 and as of December 31, 2008 and 2007 is derived from the consolidated financial statements included in Item 8. The remaining data is derived from the audited financial statements from earlier periods not included in this Report. 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 Report. The following information is not necessarily indicative of our future results.


	Years Ended December 31,
	2008⁽²⁾			2007⁽³⁾		2006		2005		2004
	(In thousands, except for per share data and ratios)

Operating Results Information
Total revenues	$	800,641		$	561,258	$	390,362	$	310,448	$	179,729
Operating income (loss)		(249,697	)		803,581		174,196		149,129		60,693
Income (loss) before income taxes		(585,077	)		730,806		126,248		122,658		44,597
Net income (loss) attributable to Quicksilver		(378,276	)		475,390		90,006		83,979		30,720
Diluted earnings (loss) per common share⁽¹⁾	$	(2.33	)	$	2.87	$	0.58	$	0.54	$	0.21
Dividends paid per share		—			—		—		—		—
Cash provided by operating activities	$	456,566		$	319,104	$	242,186	$	140,242	$	84,847
Capital expenditures		2,279,927			1,020,684		619,061		331,805		215,106
Financial Condition Information
Property, plant and equipment — net	$	3,797,715		$	2,142,346	$	1,679,280	$	1,112,002	$	802,610
Total assets		4,498,208			2,773,751		1,881,052		1,241,437		886,850
Long-term debt		2,586,046			788,518		887,917		469,330		357,282
Long-term obligations excluding debt		47,715			34,473		25,058		20,891		17,967
Total equity		1,211,563			1,192,468		602,119		406,399		330,515


⁽¹⁾		Per share amounts have been adjusted to reflect a three-for-two stock split effected in the form of a stock dividend in June 2005 and a two-for-one stock split effected in the form of a stock dividend in January 2008

⁽²⁾		Operating loss for 2008 includes a charge of $633.5 million for impairment associated with our U.S. oil and gas properties. Net loss also includes $93.3 million for pretax income attributable to the Company’s proportionate ownership of BBEP and a pretax charge of $320.4 million for impairment of that investment

⁽³⁾		Operating income includes a gain of $628.7 million recognized from the divestiture of the Company’s Northeast Operations and a charge of $63.5 million associated with the Michigan Sales Contract (See Notes 5 and 6 to the consolidated financial statements in Item 8 of this Report)

As further discussed in Note 2 to our consolidated financial statements included in Item 8 of this Report, our consolidated financial statements for each period presented, as well as the financial information in the following discussion, have been adjusted for the retrospective application of the Adopted Pronouncements. Supplemental information has also been provided regarding the Company’s “restricted” subsidiaries under the caption “Quicksilver Resources Inc. and its Restricted Subsidiaries” below.

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, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this annual report. We conduct our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller gathering and processing segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis.

Our MD&A includes the following sections:

	•		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.

	•		Results of Operations— an analysis of our consolidated results of operations for the three years presented in our financial statements.

	•		Liquidity, Capital Resources and Financial Position —an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments.

	•		Critical Accounting Estimates— a discussion of critical accounting estimates that represent choices between acceptable alternatives and/or require management judgments and assumptions.

OVERVIEW

We are a Fort Worth, Texas-based independent oil and gas company engaged in the acquisition, exploration, exploitation, development and production of natural gas, NGLs, and crude oil. We focus primarily on unconventional reservoirs where hydrocarbons may be 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. Our production generates earnings and cash flow that allow us to conduct acquisition, exploration, exploitation, development and production activities to replace the reserves that we produce.

At December 31, 2008, approximately 99% of our proved reserves were natural gas and NGLs. Consistent with one of our business strategies, we have developed and applied the expertise gained in developing our now divested Northeast Operations to our projects in Alberta, Canada and our Barnett Shale interests in Texas. Our Texas and Alberta reserves made up approximately 84% and 15%, respectively, of our proved reserves at December 31, 2008. Our acreage in the Horn River Basin in British Columbia will provide additional opportunity for further application of this expertise.

For 2009, we plan to continue our focus on the development and exploitation of our properties in Texas and Alberta and to begin exploration in the Horn River Basin. We have allocated $400 million of our 2009 consolidated capital budget of $600 million for drilling and completion activities. Approximately $330 million is allocated to projects in Texas and approximately $57 million is allocated to our Canadian projects. Approximately $155 million of the 2009 capital budget has been allocated to construction of natural gas processing and gathering assets, including $35 million to be funded directly by KGS.

Our Company focuses on three key value drivers:

	•		reserve growth;

	•		production growth; and

	•		maximizing the Company’s operating cash flows.

Our reserve growth relies on our ability to apply our 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 through relatively low-risk development and exploitation drilling. We will also continue to identify high-potential exploratory projects with comparatively higher levels of financial risk. All of our development and exploratory programs are aimed at providing us with opportunities to develop and exploit unconventional natural gas reservoirs which align our technical and operational expertise.

Our core operating areas and the acreage that we hold are well suited for production increases through development and exploitation drilling. We perform workover and infrastructure projects to reduce ongoing operating costs and increase current and future production rates. We regularly review our operated properties to determine if steps can be taken to profitably increase reserves and production.

In evaluating the result of our efforts, we consider the capital efficiency of our drilling program and also measure the following key indicators: reserve growth; production volumes; cash flow from operating activities; and earnings per share.


	Years Ended December 31,
	2008			2007			2006
Organic reserve growth⁽¹⁾		29	%		59	%		46	%
Production volumes (Bcfe)		96.2			77.9			61.3
Cash flow from operating activities (in millions)	$	456.6		$	319.1		$	242.2
Diluted earnings (loss) per share⁽²⁾	$	(2.33	)	$	2.87		$	0.58


⁽¹⁾		Organic growth excludes reserves acquired or divested from beginning and ending reserves and from production. This ratio is calculated by subtracting adjusted beginning of the year proved reserves from adjusted end of the year proved reserves and dividing by adjusted beginning of the year proved reserves. Adjusted beginning of the year reserves are calculated by deducting sold reserves and adjusted current year production from beginning of the year reserves. Adjusted current year production excludes production from purchased reserves. Adjusted end of the year reserves are calculated by deducting purchased reserves from end of the year reserves.

⁽²⁾		Operating loss for 2008 includes a pretax charge of $633.5 million for impairment associated with our U.S. oil and gas properties. Net loss also includes $93.3 million of pretax income attributable to the Company’s proportionate ownership of BBEP and a pretax charge of $320.4 million for impairment of that investment.

FINANCIAL RISK MANAGEMENT

We have established internal control policies and procedures for managing risk within our organization. The possibility of decreasing prices received for our natural gas, NGL and crude oil production is among the several risks that we face. We seek to manage this risk by entering into financial hedges. We have mitigated the downside risk of adverse price movements through the use of derivatives but, in doing so, have also limited our ability to benefit from favorable price movements. This commodity price strategy enhances our ability to execute our development, exploitation and exploration programs, meet debt service requirements and pursue acquisition opportunities even in periods of price volatility.

RESULTS OF OPERATIONS

Revenue

Natural Gas, NGL and Crude Oil

Production Revenue:


	Natural Gas							NGL								Oil and Condensate									Total
	2008			2007		2006		2008			2007			2006		2008			2007			2006			2008			2007		2006
	(In millions)
Texas	$	371.1		$	121.6	$	63.0	$	198.1		$	106.7		$	22.8	$	30.4		$	9.2		$	5.0		$	599.6		$	237.5	$	90.8
Northeast Operations		—			100.8		137.5		—			4.5			5.4		—			18.6			21.2			—			123.9		164.1
Other U.S.		0.6			0.3		0.8		0.8			0.6			0.5		14.8			10.2			9.5			16.2			11.1		10.8
Hedging		(2.2	)		26.3		5.4		(8.6	)		(5.2	)		—		(7.1	)		(0.7	)		(0.5	)		(17.9	)		20.4		4.9

Total U.S.		369.5			249.0		206.7		190.3			106.6			28.7		38.1			37.3			35.2			597.9			392.9		270.6
Canada		182.7			126.4		106.0		0.4			0.2			0.3		—			—			—			183.1			126.6		106.3
Hedging		(0.2	)		25.6		9.7		—			—			—		—			—			—			(0.2	)		25.6		9.7

Total Canada		182.5			152.0		115.7		0.4			0.2			0.3		—			—			—			182.9			152.2		116.0

Total	$	552.0		$	401.0	$	322.4	$	190.7		$	106.8		$	29.0	$	38.1		$	37.3		$	35.2		$	780.8		$	545.1	$	386.6

Average Daily Production Volumes:


	Natural Gas						NGL						Oil and Condensate						Equivalent Total
	2008		2007		2006		2008		2007		2006		2008		2007		2006		2008		2007		2006
	(MMcfd)						(Bbld)						(Bbld)								(MMcfed)
Texas		122.8		50.1		23.9		11,425		6,395		1,579		873		349		215		196.6		90.6		34.7
Northeast Operations		—		56.1		71.7		—		331		419		—		799		930		—		62.9		79.8
Other U.S.		0.3		0.3		0.3		36		29		31		447		452		463		3.2		3.2		3.3

Total U.S.		123.1		106.5		95.9		11,461		6,755		2,029		1,320		1,600		1,608		199.8		156.7		117.8
Canada		63.0		56.8		50.0		3		13		14		—		—		—		63.0		56.9		50.0

Total		186.1		163.3		145.9		11,464		6,768		2,043		1,320		1,600		1,608		262.8		213.6		167.8

Average Realized Prices:


	Natural Gas							NGL								Oil and Condensate									Equivalent Total
	2008			2007		2006		2008			2007			2006		2008			2007			2006			2008			2007		2006
	(per Mcf)							(per Bbl)								(per Bbl)									(per Mcfe)
Texas	$	8.26		$	6.65	$	7.22	$	47.38		$	45.70		$	39.56	$	95.16		$	72.37		$	63.62		$	8.33		$	7.18	$	7.18
Northeast Operations		—			4.92		5.25		—			37.36			35.27		—			63.81			62.33			—			5.40		5.63
Other U.S.		7.43			4.68		6.85		70.52			52.35			46.55		89.41			61.49			56.25			13.92			9.63		9.03
Hedging — U.S.		(0.05	)		0.81		0.18		(2.06	)		(2.10	)		—		(14.72	)		(1.19	)		(0.77	)		(0.25	)		0.45		0.11
Total U.S.	$	8.20		$	6.40	$	5.90	$	45.39		$	43.22		$	38.78	$	78.83		$	63.87		$	59.99		$	8.18		$	6.87	$	6.29
Canada		7.92			6.10		5.82		325.52			48.02			49.03		—			—			—			7.94			6.10		5.82
Hedging — Canada		(0.01	)		1.23		0.53		—			—			—		—			—			—			(0.01	)		1.23		0.53
Total Canada	$	7.91		$	7.33	$	6.35	$	325.52		$	48.02		$	49.03	$	—		$	—		$	—		$	7.93		$	7.33	$	6.35
Total	$	8.10		$	6.73	$	6.05	$	45.44		$	43.23		$	38.85	$	78.83		$	63.87		$	59.99		$	8.12		$	6.99	$	6.31

The following table summarizes the changes in our natural gas, NGL and crude oil revenue:


	Natural
	Gas		NGL		Oil			Total
	(In thousands)
Revenue for 2006	$	322,357	$	28,978	$	35,205		$	386,540
Volume changes		42,735		74,546		(171	)		117,110
Price changes		35,897		3,263		2,279			41,439

Revenue for 2007	$	400,989	$	106,787	$	37,313		$	545,089
Volume changes		57,227		74,591		(6,463	)		125,355
Price changes		93,830		9,288		7,226			110,344

Revenue for 2008	$	552,046	$	190,666	$	38,076		$	780,788

Our natural gas revenue for 2008 increased as a result of both a $1.37 per Mcf increase in realized prices and a 22.8 MMcfd increase in volumes as compared to 2007. Natural gas production in the U.S. increased 72.7 MMcfd as a result of the impact of new wells placed into production partially offset by production declines for existing wells, primarily in the Fort Worth Basin. The November 2007 divestiture of our Northeast Operations reduced our natural gas production by 56.1 MMcfd and the Alliance Acquisition increased production by 17.0 MMcfd on an annualized basis. Additional wells on our Canadian interests increased production by 6.2 MMcfd from 2007.

NGL revenue for 2008 increased as a result of production increases and realized prices that were $2.21 per Bbl higher than 2007 NGL realized prices. Additional Texas natural gas production in the high-BTU area of the Barnett Shale and processing improvements during 2008 increased NGL volumes 5,030 Bbld when compared to 2007. Partially offsetting the Texas production and pricing increases was the absence of production due to the divestiture of the Northeast Operations.

Crude oil revenue for 2008 was higher than 2007 due to a $14.96 per Bbl increase in realized prices. Production increases of 524 Bbld from the Fort Worth Basin in 2008 partially offset the divested production from the Northeast Operations.

Our natural gas revenue for 2007 increased from 2006 as a result of both a $0.68 per Mcf increase in realized natural gas prices and a 17.4 MMcfd increase in volumes as compared to 2006. Natural gas revenue in the U.S. increased 10.6 MMcfd as a result of new wells placed into production, primarily in the Fort Worth Basin. The November 2007 divestiture of our Northeast Operations reduced our natural gas production as did natural production declines in this area. Additional wells on our Canadian interests increased production by 6.8 MMcfd from 2006.

NGL revenue for 2007 was almost three times higher than 2006, which primarily resulted from an incremental 1,724 MBbl increase in NGL production resulting from additional Texas natural gas production in the high-BTU area of the Barnett Shale during 2007. Also, more favorable pricing of $4.38 per Bbl contributed to the increase when compared to 2006 NGL revenue.

Crude oil revenue for 2007 was higher than 2006 due to a $3.88 per Bbl increase in realized prices. Fort Worth Basin production in 2007 increased to partially offset the impact of the divestiture of our Northeast Operations.

Other Revenue

Other revenue, consisting primarily of revenue from the processing, gathering and marketing of natural gas, was $19.9 million for 2008, an increase of $3.7 million compared with 2007. Throughput from third parties in our gathering and processing assets operated by KGS increased other revenue by $6.2 million. Partially offsetting the increase was the absence of $4.9 million of Canadian government grants for new drilling techniques we received in 2007.

Other revenue was $16.2 million for 2007, an increase of $12.3 million compared with 2006. This increase is primarily due to $5.1 million from higher throughput from third parties in our gathering and processing assets operated by KGS and $4.3 million more in Canadian government grants for new drilling techniques compared to 2006. Hedge ineffectiveness in 2007 also increased other revenue $1.0 million compared to 2006.

Operating Expenses

Oil and Gas Production Expenses


	Years Ended December 31,
	2008				2007				2006
	(In thousands, except per unit amounts)
			Per				Per				Per
			Mcfe				Mcfe				Mcfe
Texas
Cash expense	$	92,096	$	1.28	$	53,726	$	1.63	$	24,692	$	1.95
Equity compensation		1,130		0.02		339		0.01		105		0.01

	$	93,226	$	1.30	$	54,065	$	1.64	$	24,797	$	1.96
Northeast Operations
Cash expense	$	—	$	—	$	48,489	$	2.11	$	44,151	$	1.51
Equity compensation		—		—		422		0.02		817		0.03

	$	—	$	—	$	48,911	$	2.13	$	44,968	$	1.54
Other U.S.
Cash expense	$	6,318	$	5.35	$	3,278	$	2.97	$	3,385	$	2.89
Equity compensation		190		0.16		193		0.16		101		0.08

	$	6,508	$	5.51	$	3,471	$	3.13	$	3,486	$	2.97
Total U.S.
Cash expense	$	98,414	$	1.34	$	105,493	$	1.84	$	72,228	$	1.68
Equity compensation		1,320		0.02		954		0.02		1,023		0.02

	$	99,734	$	1.36	$	106,447	$	1.86	$	73,251	$	1.70
Canada
Cash expense	$	33,781	$	1.47	$	28,415	$	1.37	$	20,862	$	1.14
Equity compensation		2,146		0.09		1,969		0.09		1,063		0.06

	$	35,927	$	1.56	$	30,384	$	1.46	$	21,925	$	1.20
Total Company
Cash expense	$	132,195	$	1.37	$	133,908	$	1.72	$	93,090	$	1.52
Equity compensation		3,466		0.04		2,923		0.04		2,086		0.03

	$	135,661	$	1.41	$	136,831	$	1.76	$	95,176	$	1.55

Oil and gas production expense for 2008 was almost unchanged from 2007. The absence of production expense of $48.9 million for the divested Northeast Operations was offset by the growth of our operations in the Fort Worth Basin and Canada that increased production expense $39.2 million and $5.5 million, respectively, as production volumes increased 117% and 11%, respectively, for 2008 as compared to 2007, as discussed previously.

Although oil and gas production expense for our Fort Worth Basin operations were $39.2 million higher for 2008, production expense per Mcfe decreased 21% to $1.30 per Mcfe when compared to 2007. The improvement in production expense on a Mcfe-basis was primarily the result of higher production levels, cost containment initiatives, new completion techniques used in our capital program and higher utilization of automation during 2008. Canadian production expense increased primarily as a result of the 11% increase in production volumes and an increase in personnel costs plus higher prevailing exchange rates during 2008.

Oil and gas production expense for 2007 increased by $41.7 million from 2006 levels, primarily due to costs associated with higher production levels. On a Mcfe-basis, our costs increased 14% compared to 2006 levels. Although overall costs increased in Texas, our production and number of producing properties increased while our cost per Mcfe of production decreased. Our 2007 production costs for the Northeast Operations reflected $6.3 million of employee severance cost associated with its divestiture. Northeast Operations unit costs were also impacted by production declines. The total cost increases reflect salary increases of $3.7 million associated with headcount increases. Canadian production expense increased $8.5 million due to an estimated $1.4 million for currency effects of the strengthening Canadian dollar, $1.2 million higher gathering and processing costs, $2.0 million in increased direct operating cost associated with new producing properties and more than $5.0 million of overhead costs, including higher salaries, stock-based compensation, incentive compensation and rent.

Production and Ad Valorem Taxes


	Years Ended December 31,
	2008				2007				2006
	(In thousands, except per unit amounts)
			Per				Per				Per
			Mcfe				Mcfe				Mcfe
Production and ad valorem taxes
U.S.	$	14,060	$	0.19	$	13,005	$	0.23	$	13,948	$	0.32
Canada		2,734	$	0.12		3,137	$	0.15		1,671	$	0.09

Total production and ad valorem taxes	$	16,794	$	0.17	$	16,142	$	0.21	$	15,619	$	0.25

Production and ad valorem tax expense for 2008 increased slightly as compared to 2007. Production and ad valorem taxes increased $11.2 million due to the development of our Fort Worth Basin properties and increased production. This increase was nearly offset by the absence of production and ad valorem taxes associated with the divested Northeast Operations. We have historically experienced low severance tax expense for our Texas production as a result of exemptions and rate reductions for development of our acreage positions with wells deemed by the taxing authorities to be “high cost wells.” We expect severance tax rates in Texas to increase in future quarters as fewer of our wells to be drilled in 2009 and beyond will qualify for severance tax exemptions and rate reductions because we expect our Fort Worth Basin drilling and completion costs to continue to decrease while the cost threshold for exemptions and rate reductions will increase.

Production and ad valorem tax expense for 2007 was relatively flat when compared to 2006 as a $2.1 million increase in ad valorem tax expense was mostly offset by a decrease in production taxes. Ad valorem tax expense increased primarily as a result of the growth in our Texas and Canadian property values associated with our 2007 capital expenditure program while production tax expense decreased as a result of a higher percentage of our production in Texas that is partially or fully exempted from production taxes.

Depletion, Depreciation and Accretion


	Years Ended December 31,
	2008				2007				2006
	(In thousands, except per unit amounts)
			Per				Per				Per
			Mcfe				Mcfe				Mcfe
Depletion
U.S.	$	120,845	$	1.65	$	65,020	$	1.14	$	40,051	$	0.93
Canada		40,337		1.75		34,666		1.67		25,618		1.40

Total depletion		161,182		1.68		99,686		1.28		65,669		1.07
Depreciation of other fixed assets:
U.S.	$	21,751	$	0.30	$	15,389	$	0.27	$	8,715	$	0.20
Canada		3,780		0.16		4,115		0.20		3,129		0.17

Total depreciation		25,531		0.27		19,504		0.25		11,844		0.19
Accretion		1,483		0.01		1,507		0.02		1,287		0.02

Total depletion, depreciation and accretion	$	188,196	$	1.96	$	120,697	$	1.55	$	78,800	$	1.29

Higher depletion expense for 2008 resulted from a 31% increase in the depletion rate and a 23% increase in production volumes. Our 2008 depletion rate was impacted by the addition of the proved oil and gas properties obtained in the Alliance Acquisition as well as the capital costs incurred for proved reserves added from our existing properties and increases in estimated future capital expenditures. Depreciation expense for 2008 was $10.4 million higher than 2007 primarily due to additions of Fort Worth Basin field compression and KGS midstream infrastructure, partially offset by the absence of $4.1 million of depreciation expense associated with the divested Northeast Operations depreciable assets. We expect depreciation expense will further increase when KGS places its $110 million Corvette Plant into service in the first quarter of 2009 and we expect that depletion for our U.S. properties will be approximately $1.80 per Mcfe after the impairment recognized in the fourth quarter of 2008.

Depletion expense in 2007 increased from 2006 primarily as a result of a 27% increase in production. Our 2007 consolidated depletion rate increased $0.21 per Mcfe as a result of increased future development costs due in part to a higher percentage of undeveloped proved reserves for 2007 year-end as compared to 2006, and higher finding costs in 2007 in Texas. Depreciation expense for 2007 was $7.7 million higher than 2006 primarily resulting from increased capacity at our Cowtown Gas Plant, additions to our Cowtown Pipeline and new Canadian gas processing facilities.

Impairment of Oil and Gas Properties

We recognized a noncash pretax charge of $633.5 million ($411.8 million after tax) for impairment related to our U.S. oil and gas properties in December 2008. As required under full cost accounting rules, we performed a ceiling test by comparing the book value of our oil and gas properties, net of related deferred tax liability and asset retirement obligations, to the year-end ceiling limitation, which is the after-tax value of the future net cash flows from proved oil and gas reserves, including the effect of hedges. As also required under full cost accounting rules prescribed by the SEC, the ceiling amount was based upon year-end prices and costs, discounted at 10% per year. Under these rules, management has little ability to influence the ceiling amounts with respect to such factors as pricing, discount rate, cost structure and timing. Consequently, the ceiling amount is not necessarily indicative of the fair value of our oil and gas properties, which could have a wide range of potential fair values. Included below is an alternate valuation of our oil and gas reserves that supplements the ceiling amount and which management believes is more indicative of our oil and gas properties’ fair value as it incorporates the valuation techniques we employ in making investment decisions. The alternate value presented below would have, if permitted in place of the ceiling amount, eliminated any recognition of impairment during 2008. This valuation was calculated in the same manner as the scenario used in the ceiling test, except for the following changes:

	•		the forward strip prices on December 31, 2008, which featured future price increases and more appropriately reflect expected future realized prices, were used in place of year-end prices held constant;

	•		production expense was adjusted to reflect actual consolidated oil and gas production expenses; and

	•		income tax considerations are excluded from the analysis although they are required for the ceiling test computation.

Management’s alternate pretax valuation related to its proved oil and gas reserves at December 31, 2008 as described above was as follows:


	United States			Canada			Total
	(In thousands)
Future revenues	$	13,047,702		$	2,012,958		$	15,060,660
Future production costs		(4,300,591	)		(550,345	)		(4,850,936	)
Future development costs		(1,195,503	)		(112,330	)		(1,307,833	)

Future net pretax cash flows		7,551,608			1,350,283			8,901,891
10% discount		(4,188,201	)		(721,623	)		(4,909,824	)

Management’s estimate of pretax discounted future cash flows relating to proved reserves	$	3,363,407		$	628,660		$	3,992,067

General and Administrative Expense


	Years Ended December 31,
	2008				2007				2006
	(In thousands, except per unit amounts)
			Per				Per				Per
			Mcfe				Mcfe				Mcfe
General and administrative expense
Cash expense	$	49,982	$	0.52	$	38,595	$	0.49	$	21,182	$	0.35
Litigation resolution		9,633		0.10		—		—		—		—
Equity compensation		12,639		0.13		8,465		0.11		4,454		0.07

Total general and administrative expense	$	72,254	$	0.75	$	47,060	$	0.60	$	25,636	$	0.42

We recognized a charge of $9.6 million in 2008 as a result of the settlement of litigation as discussed in Note 17 to our consolidated financial statements in Item 8 of this Report. The most significant increase in recurring general and administrative expense for 2008 was a $14.4 million increase in employee compensation and benefits, including increases of $4.2 million of non-cash expense for vesting of stock-based compensation and $1.3 million in performance-based compensation. The remaining $8.9 million increase in employee compensation is related to additional headcount which was necessary to bring our infrastructure to a level needed to accommodate growth in our operations and production. After consideration of the BreitBurn Transaction investment banking fees of $2.0 million recognized in 2007, fees for legal, accounting and other professional services increased general and administrative expense by approximately $2.8 million, which resulted from additional regulatory filing requirements, litigation costs, expenses associated with evaluation of complex business transactions and the full year effect of KGS being a publicly-traded partnership.

General and administrative expense for 2007 increased due to a $4.1 million increase in stock-based compensation and $1.9 million in performance-based compensation. These increases relate to increased headcount at our corporate offices to develop additional capabilities necessary to support our growth. General and administrative costs increased year over year by $4.1 million for legal and professional fees which relate to professional services provided for the KGS IPO and our Northeast Operations divestiture.

Other Components of Operating Income

During 2007, we recognized a gain of $628.7 million as a result of our divestiture of the Northeast Operations, and we recorded a loss on the Michigan Sales Contract related to delivery of volumes in Michigan. Further information regarding these transactions is included in Item 8 of this Report.

BreitBurn-Related Income and Expenses

During 2008, we recognized $93.3 million associated with the equity earnings in our investment in BBEP for the period from November 1, 2007, when we acquired the BBEP units, through September 30, 2008. This amount reflects our prevailing ownership interests for the applicable period before and after our ownership increased from 32% to 41% by virtue of BBEP’s purchase and retirement of units during 2008. BBEP has experienced significant volatility in their net earnings due to changes in value of their derivative instruments, for which they do not employ hedge accounting.

During the fourth quarter of 2008, the Company considered the fair value of the BBEP units along with the fair value trend of its peers, the trend and future petroleum strip prices and the limited availability of credit which occurred in the latter half of 2008. Based on these factors, the Company determined that the decrease in fair value of BBEP units was other-than-temporary and recorded a pretax charge of $320.4 million to reduce the carrying value of our investment in BBEP to its fair value. Management believes that certain alternative fair value measures, such as BBEP’s liquidation value, the estimated value of its properties and reserves, the present value of existing distribution levels and other calculations would have eliminated or materially lowered the impairment charge. However, the prescriptive nature of the relevant GAAP requires the Company to ignore these alternative measures based upon availability of Level 1 inputs as described in SFAS No. 157.

Interest Expense


	Years Ended December 31,
	2008			2007			2006
	(in thousands)
Interest costs	$	118,323		$	77,753		$	51,655
Less: Interest capitalized		(9,225	)		(1,091	)		(1,882	)

Interest expense	$	109,098		$	76,662		$	49,773

Interest costs for 2008 were higher than 2007 primarily because of higher average debt outstanding due to the issuance of our Senior Notes and our Senior Secured Second Lien Facility due in 2013, partially offset by a decrease in our average consolidated interest rate. The higher debt levels in 2008 relate to the Alliance Acquisition and the funding of our 2008 capital program. The increase in capitalized interest relates to more projects and costs within those projects being subject to capitalization. Interest was capitalized in 2008 for our exploration projects in the Horn River Basin and West Texas and construction of the Corvette Plant by KGS.

For 2007, interest expense increased $26.9 million from 2006 primarily as a result of both higher debt balances and higher prevailing rates on the variable portion of our debt. The increases in 2007 debt balances primarily relate to the drilling and midstream expansion programs undertaken in 2007, but were partially offset by our debt reductions in November, funded by proceeds from our Northeast Operations’ divestiture.

Income Taxes


	Years Ended December 31,
	2008			2007			2006
	(in thousands)
Income tax expense (benefit)	$	(211,455	)	$	254,361		$	36,151
Effective tax rate		36.1	%		34.8	%		28.6	%

The 2008 provision for income taxes changed dramatically from 2007 due to the loss generated by U.S. operations for 2008. Pretax results for 2008 compared with 2007 were most significantly influenced by the impairment charges recognized on U.S. oil and gas properties and on our investment in BBEP. Also, 2007 results included the gain resulting from our divestiture of our Northeast Operations. Higher Canadian pretax income and the absence of tax credits received in 2007 increased the provision for income taxes in Canada by $11.1 million. In 2008, the effective rate exceeds the statutory rate of 35% due to the benefit of lower taxes in Canada partially offset by impact of permanent differences for executive compensation and meals and entertainment.

Income tax expense for 2007 was $254.4 million which yielded the effective rate of 34.8%. The 620 basis point increase in the effective rate is principally due to taxes on the gain associated with the divestiture of our Northeast Operations at the U.S. statutory rate, which is higher than the comparable Canadian rate. Thus our taxable income was more heavily weighted toward the U.S. in 2007 compared with 2006. Also, the recognition in 2007 of tax expenses pursuant to FIN 48 and a decrease in the tax credits generated by our Canadian operations increased the effective rate, offset in part by a reduction for the effect of a future tax rate reduction in Canada. Our U.S. income tax expense of approximately 35.5% was established using the statutory U.S. federal rate of 35% plus the effects of the Texas margin tax that was enacted in May 2006. Our Canadian tax expense was established using the combined federal and provincial rate of 29% and the effects of tax rate reductions that were enacted in 2007.

Quicksilver Resources Inc. and its Restricted Subsidiaries

The indentures under both the Company’s Senior Notes and the Company’s Senior Subordinated Notes distinguish between “restricted” subsidiaries and “unrestricted” subsidiaries. The Company’s unrestricted subsidiaries consist of:

	•		Quicksilver Gas Services Holdings LLC;
	•		Quicksilver Gas Services GP LLC;
	•		Quicksilver Gas Services LP;
	•		Quicksilver Gas Services Operating LLC;
	•		Quicksilver Gas Services Operating GP LLC;
	•		Cowtown Pipeline Partners L.P.; and
	•		Cowtown Gas Processing Partners L.P.

All of the Company’s other subsidiaries are restricted subsidiaries (collectively, the “Restricted Subsidiaries”). The Company and its Restricted Subsidiaries conduct all of the Company’s exploration and production activities, and the “unrestricted subsidiaries” only conduct midstream operations.

The combined results of operations for the Company and its restricted subsidiaries are substantially similar to the Company’s consolidated results of operations, which are discussed above under “Results of Operations.” The combined financial position of the Company and its restricted subsidiaries and the Company’s consolidated financial position are materially the same except for the property, plant and equipment purchased by the unrestricted subsidiaries since the KGS IPO, the borrowings under the KGS credit facility and the equity of the unrestricted subsidiaries. The other balance sheet items are discussed below in “Financial Position.” The combined operating cash flows, financing cash flows and investing cash flows for the Company and its restricted subsidiaries are substantially similar to the Company’s consolidated operating cash flows, financing cash flows and investing cash flows, which are discussed below in “Liquidity, Capital Resources and Financial Position.” Further information regarding the Company, its restricted subsidiaries and its unrestricted subsidiaries is included in Item 8 of this Report.

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

Cash Flow Activity

Operating Cash Flows


	Years Ended December 31,
	2008		2007		2006
	(In thousands)
Net cash provided by operating activities	$	456,566	$	319,104	$	242,186

Cash flows provided by operating activities in 2008 were $456.6 million, an increase of $137.5 million or 43% from 2007. The increase in operating cash flows results from a 23% production increase and a 16% increase in realized price per Mcfe. Payments of $46.6 million for income taxes and other uses of working capital partially offset the increase in net income.

Cash flows provided by operating activities in 2007 were $319.1 million, an increase of $76.9 million or 32% from 2006. The cash flows increased due to a 27% production increase, an 11% realized price increase and higher cash flows provided by working capital.

Investing Cash Flows


	Years Ended December 31,
	2008			2007			2006
	(In thousands)
Purchases of property, plant and equipment	$	(1,286,715	)	$	(1,020,684	)	$	(619,061	)
Alliance Acquisition		(993,212	)		—			—
Return of investment from equity affiliates		—			9,635			1,923
Proceeds from sales of properties & equipment		1,339			741,297			5,113

Net cash used by investing activities	$	(2,278,588	)	$	(269,752	)	$	(612,025	)

For each of the three years ended December 31, 2008, we have spent significant cash resources for the development of our large acreage positions in our core areas in the Fort Worth Basin and the CBM properties in Alberta. In addition, our expenditures for gas processing and gathering assets have grown significantly as part of our growth in the Barnett Shale. In 2008 and 2007, our investing cash flows included the $1.0 billion cash portion of the Alliance Acquisition and net cash proceeds of $741.1 million from the divestiture of our Northeast Operations, respectively. Of the $2.3 billion of cash paid for property, plant and equipment during 2008, 88% was invested in our oil and natural gas properties and 12% was invested in our gas processing and gathering operations.

Our 2008 purchases of property, plant and equipment reflect our expansion in our two core operating areas, the Fort Worth Basin and the Western Canadian Sedimentary Basin in Alberta. In 2008, we purchased approximately 90 producing wells in the Alliance Acquisition and drilled 296 (259.7 net) wells in the Fort Worth Basin and 373 (156.9 net) wells in Canada. Additionally, the assets purchased in the Alliance Acquisition included a gathering system and we invested $230.4 million and $4.3 million for Fort Worth Basin and Canadian gas processing and gathering facilities, respectively.

Capital costs incurred for development, exploitation and exploration activities in 2007 were $852.5 million, primarily for expansion in our two core operating areas. In 2007, we drilled 244 (219.4 net) wells in the Fort Worth Basin and an additional 356 (184.1 net) wells in Canada. Additionally, we invested $168.5 million and $3.4 million for Fort Worth Basin and Canadian gas processing and gathering facilities, respectively.

Capital costs incurred for development, exploitation and exploration activities in 2006 were $544.7 million. Those expenditures also reflect our two core operating areas. In 2006, we drilled 123 (111.3 net) wells in the Fort Worth Basin and an additional 400 (215.2 net) wells in Canada. Additionally, we invested $82.3 million and $7.6 million for Fort Worth Basin and Canadian gas processing and gathering facilities, respectively.

We currently estimate that our spending for property, plant and equipment in 2009 will be approximately $600 million, of which we have allocated $400 million for drilling activities, $155 million for gathering and processing facilities (including $35 million to be funded directly by KGS), $40 million for acquisition of additional leasehold interest and $5 million for other property and equipment.

Financing Cash Flows


	Years Ended December 31,
	2008			2007			2006
	(In thousands)
Cash flow provided by financing activities:
Issuance of debt	$	2,948,672		$	817,821		$	694,682
Repayments of debt		(1,096,163	)		(968,557	)		(350,754	)
Debt issuance costs		(25,219	)		(5,130	)		(9,213	)
Noncontrolling interest contributions		—			109,809			7,291
Noncontrolling interest distributions		(8,644	)		(8,794	)		—
Proceeds from exercise of stock options		1,244			21,387			19,689
Excess tax benefit on exercise of stock options		—			2,755			—
Purchase of treasury stock		(23,137	)		(1,567	)		(384	)

Net cash provided (used) by financing activities	$	1,796,753		$	(32,276	)	$	361,311

Net cash flows from financing activities during 2008 were significantly impacted by the Alliance Acquisition and our 2008 capital program. We funded our capital program in excess of operating cash flow through the issuance of our Senior Notes and additional borrowing under our Senior Secured Credit Facility. The Alliance Acquisition was funded by a $700 million five-year Senior Secured Second Lien Facility and additional borrowing under our Senior Secured Credit Facility.

Net cash flows from financing activities during 2007 were significantly impacted by the KGS IPO and the divestiture of our Northeast Operations. The KGS IPO resulted in cash proceeds of $110 million primarily used to repay debt. The divestiture of our Northeast Operations generated net cash proceeds of $741.1 million included in investing activities, however those proceeds were used to pay down debt previously outstanding which affected financing cash flows.

Liquidity and Borrowing Capacity

On February 9, 2007, we extended our Senior Secured Credit Facility to February 9, 2012. The facility provides for revolving loans, swingline loans and letters of credit from time to time in an aggregate amount not to exceed the borrowing base which is calculated based on several factors. As of December 31, 2008, the borrowing base was equal to $1.2 billion, and is subject to annual redeterminations and certain other redeterminations. The lenders agreed to provide $1.2 billion of revolving credit commitments and the Company has an option to increase the facility to $1.45 billion. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with U.S. currency available for borrowing by the Company and either U.S. or Canadian currency available for borrowing in Canada. The facility offers the option to extend the maturity up to two additional years with lender approval. U.S. borrowings under the facility are secured by, among other things, Quicksilver’s and its domestic subsidiaries’ oil and gas properties including applicable reserves. Canadian borrowings under the facility are secured by, among other things, all of our oil and gas properties including applicable reserves. The Company also pledged the equity interests in BBEP it received as part of the BreitBurn Transaction to secure its obligations under the Senior Secured Credit Facility.

The credit facility contain covenants that are more fully described in Note 14 to the consolidated financial statements in Item 8 of this Report. At December 31, 2008, approximately $369 million was available for borrowing under our Senior Secured Credit Facility and we were in compliance with all covenants. As of January 31, 2009, we had borrowed an additional $130 million under the credit facility. Our ability to remain in compliance with the financial covenants in our credit facility may be affected by events beyond our control, including market prices for our products. Any future inability to comply with these covenants, unless waived by the requisite lenders, could adversely affect our liquidity by rendering us unable to borrow further under our credit facilities and by accelerating the maturity of our indebtedness.

In connection with the KGS IPO, KGS entered into a five-year $150 million senior secured revolving credit facility (“KGS Credit Agreement”). In October 2008, the lenders increased the facility to $235 million. Additionally, the revised KGS Credit Agreement features an accordion option of $115 million that allows for the facility to increase to $350 million upon lender approval. KGS must maintain certain financial ratios that can limit its borrowing capacity. The KGS Credit Agreement contains covenants that are more fully described in Note 14 to the consolidated financial statements in Item 8 of this Report. At December 31, 2008, KGS’ borrowing capacity was $235 million, and KGS had $175 million in borrowings outstanding under the KGS Credit Agreement. KGS was in compliance with all covenants as of December 31, 2008. KGS’s ability to remain in compliance with the financial covenants in its credit facility may be affected by events beyond our control. Any future inability to comply with these covenants, unless waived by the requisite lenders, could adversely affect our liquidity by rendering KGS unable to borrow further under its credit facility and by accelerating the maturity of its indebtedness.

As of December 31, 2008, 2007 and 2006, our total capitalization was as follows:


	Years Ended December 31,
	2008		2007		2006
	(In thousands)
Long-term and short-term debt:
Senior secured credit facility	$	827,868	$	310,710	$	421,123
Senior secured second lien facility		641,555		—		—
Senior notes		469,062		—		—
Senior subordinated notes		350,000		350,000		350,000
Convertible subordinated debentures		129,240		122,808		116,794
KGS credit agreement		174,900		5,000		—
Various loans		—		34		400

Total debt		2,592,625		788,552		888,317
Total equity		1,211,563		1,192,468		602,119

Total capitalization	$	3,804,188	$	1,981,020	$	1,490,436

We believe that our capital resources are adequate to meet the requirements of our existing business. We anticipate that our 2009 capital expenditure budget of approximately $600 million will be funded by cash flow from operations, including application of anticipated income tax refunds and cash distributions received from BBEP. We may, from time to time during 2009, make borrowings under the credit facility, but expect that for all of 2009 to require no incremental borrowings from ending 2008 levels.

Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or other securities, other possible capital markets transactions or the sale of assets, the proceeds of which could be used to refinance current indebtedness or for other corporate purposes. We will also consider from time to time additional acquisitions of, and investments in, assets or businesses that complement our existing asset portfolio. Acquisition transactions, if any, are expected to be financed through cash on hand and from operations, bank borrowings, the issuance of debt or other securities or a combination of those sources.

Financial Position

The following impacted our balance sheet as of December 31, 2008, as compared to our balance sheet as of December 31, 2007:

	•		Our accounts receivable balance increased $53.1 million primarily as a result of accrual for the refund of U.S. federal income taxes paid in 2008 for the 2007 tax year. The refund is the result of incurring a loss for the 2008 tax year.

	•		Our current and deferred derivative assets increased $160.9 million and $115.7 million, respectively, as our current and deferred derivative obligations decreased $54.2 million and $16.3 million, respectively. Our current derivative obligations

			include the $8.1 million fair value loss for the remaining term of the Michigan Sales Contract. Additionally, our current deferred income tax asset decreased $19.0 million and our current deferred income tax liability increased $52.4 million as a result overall higher valuations of our derivative valuations.

	•		Investments in equity affiliates decreased primarily due to the recognition of a $320 million impairment of our investment in BBEP during 2008.

	•		The $1.7 billion increase in our net property, plant and equipment resulted primarily from $1.3 billion in capital expenditures for development, exploitation and exploration of our existing oil and gas properties and expansion of our gas processing and gathering assets in addition to the $1.3 billion of oil and gas properties and gathering assets purchased in the Alliance Acquisition. Offsetting these increases were the $634 million impairment of our U.S. oil and gas properties and ongoing DD&A.

	•		Long-term debt increased due to borrowings needed to fund the Alliance Acquisition and our 2008 capital program.

Contractual Obligations and Commercial Commitments

Contractual Obligations.Information regarding our contractual and scheduled interest obligations, at December 31, 2008, is set forth in the following table.


	Payments Due by Period
			Less than		1-3		4-5		More than
	Total		1 Year		Years		Years		5 Years
	(In thousands)
Long-term debt	$	2,632,373	$	6,579	$	1,022,505	$	628,289	$	975,000
Scheduled interest obligations		485,995		71,428		202,342		134,130		78,095
Transportation contracts		399,016		8,768		100,240		93,121		196,887
Purchase obligations		13,800		13,800		—		—		—
Natural gas supply contract		8,063		8,063		—		—		—
Drilling rig contracts		71,550		45,620		25,930		—		—
Asset retirement obligations		35,193		440		189		126		34,438
Financial derivative obligations		1,865		1,865		—		—		—
Unrecognized tax benefits		9,255		—		9,255		—		—
Operating lease obligations		7,484		3,612		3,863		9		—

Total obligations	$	3,664,594	$	160,175	$	1,364,324	$	855,675	$	1,284,420

	•		Long-Term Debt.As of December 31, 2008, our outstanding indebtedness included $828 million outstanding under our Senior Secured Credit Facility, $655 million under our Senior Secured Second Lien Facility, $475 million of Senior Notes, $350 million of Senior Subordinated Notes, $150 million face value ($129.2 million carrying value) of convertible debentures and $175 million outstanding under the KGS credit facility (all before discount). Based upon our debt outstanding and interest rates in effect at December 31, 2008, we anticipate interest payments, including our scheduled interest obligations of $71.4 million, to be approximately $146.3 million in 2009. Although we do not expect year-over-year increased borrowings under our Senior Secured Credit Facility during 2009, should we be required to increase those borrowings and based on interest rates in effect at December 31, 2008, an additional $50 million in borrowings would result in additional annual interest payments of approximately $1.7 million. If the borrowing base under our Senior Secured Credit Facility were to be fully utilized by year-end 2009 at interest rates in effect at December 31, 2008, we estimate that interest payments would increase by approximately $12.8 million. If interest rates on our December 31, 2008 variable debt balance of $1.7 billion increase or decrease by one percentage point, our annual pretax income would decrease or increase by $1.7 million.

	•		Scheduled Interest Obligations.As of December 31, 2008, we had scheduled interest payments of $39.2 million annually on our $475 million of Senior Notes due July 1, 2015, $24.9 million annually on our $350 million of Senior Subordinated Notes due March 31, 2016 and $2.8 million annually on our $150 million of contingently convertible debentures due November 1, 2024.

	•		Transportation Contracts.Under contracts with various pipeline companies, we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any volume 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.

	•		Purchase Obligations.At December 31, 2008, we were under contract to purchase goods and services for completion of the Corvette Plant and for compressors. Total remaining cash obligations for such items were $13.8 million, including $1.2 million of goods and services recognized during 2008. The Corvette Plant was placed into service during the first quarter of 2009.

	•		Natural Gas Supply Contract.During 2007, we determined we would no longer deliver a portion of our natural gas production to supply the contractual volumes under the Michigan Sales Contract. We recorded a loss of $63.5 million for the fair value of the remaining contractual volumes during 2007. At December 31, 2008, we had a remaining liability of $8.1 million covering the remaining volumes under the contract that ends March 31, 2009.

	•		Drilling Rig Contracts.We lease drilling rigs from third parties for use in our development and exploration programs. The outstanding drilling rig contracts require payment of a specified day rate ranging from $20,000 to $23,200 for the entire lease term regardless of our utilization of the drilling rigs.

	•		Asset Retirement Obligations.Our obligations result from the acquisition, construction or development and the normal operation of our long-lived assets.

	•		Financial Derivative Obligations.We utilize financial derivatives to manage price risk associated with our production revenue. The recorded assets and liabilities associated with our derivative obligations were estimated based on published market prices of commodities for the periods covered by the contracts. These amounts do not necessarily reflect the payments that will be made to settle these obligations.

	•		Unrecognized Tax Benefits.We have recorded obligations that have resulted from tax benefit claims in our tax returns that do not meet the recognition standard of more likely than not to be sustained upon examination by tax authorities. The $9.3 million balance of unrecognized tax benefits includes $8.9 million of amounts that, if recognized, would reduce our effective tax rate.

	•		Operating Lease Obligations.We lease office buildings and other property under operating leases. Our operating lease obligations include $0.6 million of future lease payments to an affiliated entity, which is owned by members of the Darden family.

Commercial Commitments.We had the following commercial commitments as of December 31, 2008:


	Amounts of Commitments by Expiration Period
			Less than		1-3		4-5		More than
	Total		1 Year		Years		Years		5 Years
	(In thousands)
Purchase commitments	$	3,400	$	3,400	$	—	$	—	$	—
Surety bonds		41,284		41,284		—		—		—
Standby letters of credit		3,047		3,047		—		—		—

Total	$	47,731	$	47,731	$	—	$	—	$	—

	•		Purchase Commitments.Purchase commitments have been made to ensure delivery of material and parts required for our drilling and completion programs and KGS infrastructure expansions.

	•		Surety Bonds.Our surety bonds have been issued to fulfill contractual, legal or regulatory requirements. All of our surety bonds have an annual renewal option.

	•		Standby Letters of Credit.Our letters of credit have been issued to fulfill contractual or regulatory requirements. All of these letters of credit were issued under our Senior Secured Credit Facility and have an annual renewal option.

CRITICAL ACCOUNTING ESTIMATES

Our consolidated financial statements are prepared in accordance with GAAP. In connection with the preparation of our financial statements, we are required to make assumptions and estimates about future events, and apply judgments that affect the reported amounts of assets, liabilities, revenue, expenses and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.

Our significant accounting policies are discussed in Item 8 of this Report. Management believes that the following accounting estimates are the most critical in fully understanding and evaluating our reported financial results, and they require management’s most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain. Management has reviewed these critical accounting estimates and related disclosures with our Audit Committee.

Full Cost Ceiling Calculations

Policy Description

We use the full cost method to account for our oil and gas properties. Under the full cost method, all costs associated with the development, exploration and acquisition of oil and gas properties are capitalized and accumulated in cost centers on a country-by-country basis. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. 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 application of the full cost method generally results in higher capitalized costs and higher depletion rates compared to its alternative, the successful efforts method. 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 basis using estimated proved oil and gas reserves. Excluded from amounts subject to depletion are costs associated with unevaluated properties.

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, 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 bases of the oil and gas properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required.

Judgments and Assumptions

The discounted present value of future net revenue for our proved oil, natural gas and NGL reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of reserve estimation requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data.

The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. In the past five years, annual revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 1% of the previous year’s estimate (excluding revisions due to price changes). However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a ceiling test-related impairment. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling limitation, estimation of proved reserves is also a significant component of the calculation of depletion expense.

While the quantities of proved reserves require substantial judgment, the associated prices of natural gas, NGL and crude oil reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation requires that a 10% discount factor be used and that prices and costs in effect as of the last day of the period are held constant indefinitely. Therefore, the future net revenue associated with the estimated proved reserves is not based on our assessment of future prices or costs. Rather, they are based on such prices and costs in effect as of the end of each period when the ceiling calculation is performed. In calculating the ceiling, we adjust the period-end price by the effect of derivative contracts in place that hedge future prices. This adjustment requires little judgment as the period-end price is adjusted using the contract prices for such hedges.

Because the ceiling calculation dictates that prices in effect as of the last day of the applicable year are held constant indefinitely, and requires a 10% discount factor, the resulting value is not necessarily indicative of the fair value of the reserves or the oil and gas properties. Oil and natural gas prices have historically been volatile. At any period end, prices can be either substantially higher or lower than our long-term price forecast. Also, marginal borrowing rates may be well below the required 10% used in the calculation. Rates below 10%, if they could be utilized, would have the effect of increasing the otherwise calculated ceiling amount. Therefore, oil and gas property ceiling test-related impairments that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Oil and Gas Reserves

Policy Description

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Prices include consideration of changes in existing prices provided only by contractual arrangements, which do not include financial derivatives that hedge our oil and gas revenue. Our estimates of proved reserves are made and reassessed at least annually using available geological and reservoir data as well as production performance data. Revisions may result from changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions.

Judgments and Assumptions

All of the reserve data in this annual report are based on estimates. Estimates of our crude oil, natural gas and NGL reserves are prepared in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural gas and NGLs that are ultimately recovered. Estimates of proved crude oil, natural gas and NGL reserves significantly affect our depletion expense. For example, if estimates of proved reserves decline, the depletion rate will increase, resulting in a decrease in net income.

Derivative Instruments

Policy Description

We enter into financial derivative instruments to mitigate risk associated with the prices received from our production. We may also utilize financial derivative instruments to hedge the risk associated with interest rates on our outstanding debt. We account for our derivative instruments by recognizing qualifying derivative instruments on our balance sheet as either assets or liabilities measured at their fair value determined by reference to published future market prices and interest rates. For derivative instruments that qualify as cash flow hedges, the effective portions of gains or losses are deferred in other comprehensive income and recognized in earnings during the period in which the hedged transactions are realized. Gains or losses on qualified 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. If the hedged transaction becomes probable of not occurring, the deferred gain or loss would be immediately recorded to earnings. The ineffective portion of the hedge relationship is recognized currently as a component of other revenue.

The fair value of our natural gas derivatives and associated firm sales commitments as of December 31, 2008 was estimated based on published market prices of natural gas for the periods covered by the contracts. Estimates were determined by applying the net differential between the prices in each derivative and commitment and market prices for future periods, to the volumes stipulated in each contract to arrive at an estimated value of future cash flow streams. These estimated future cash flow values were then discounted for each contract at rates commensurate with federal treasury instruments with similar contractual lives to arrive at estimated fair value.

Judgments and Assumptions

The estimates of the fair values of our commodity derivative instruments require substantial judgment. Valuations are based upon multiple factors such as futures prices, volatility data from major oil and gas trading points, time to maturity and interest rates. We compare our estimates of fair value for these instruments with valuations obtained from independent third parties and counterparty valuation confirmations. The values we report in our financial statements change as these estimates are revised to reflect actual results.

Stock-based Compensation

Policy Description

SFAS No. 123 (revised 2004),Share-Based Payment(SFAS 123R) requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors based on estimated fair value.

Judgments and Assumptions

Option-pricing models and generally accepted valuation techniques require management to make assumptions and to apply judgment to determine the fair value of our awards. These assumptions and judgments include estimating the future volatility of our stock price, expected dividend yield, future employee turnover rates and future employee stock option exercise behaviors. Changes in these assumptions can materially affect the fair value estimate.

We do not believe there is a reasonable likelihood that there will be a material change in the future estimates or assumptions that we use to determine stock-based compensation expense. However, if actual results are not consistent with our estimates or assumptions, we may be exposed to changes in stock-based compensation expense that could be material. If actual results are not consistent with the assumptions used, the stock-based compensation expense reported in our financial statements may not be representative of the actual economic cost of the stock-based compensation.

Income Taxes

Policy Description

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 we expect will be in effect during years in which we expect the temporary differences will reverse. Canadian taxes are computed at rates in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested in Canada and thus are not considered available for distribution to us. 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.

Judgments and Assumptions

We must assess the likelihood that deferred tax assets will be recovered from future taxable income and provide judgment on the amount of financial statement benefit that an uncertain tax position will realize upon ultimate settlement. To the extent that we believe that a more than 50% probability exists that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. Significant management judgment is required in determining any valuation allowance recorded against deferred tax assets and in determining the amount of financial statement benefit to record for uncertain tax positions. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed and consider the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. Evidence used for the valuation allowance includes information about our current financial position and results of operations

for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax assets and liabilities and tax planning strategies available to the Company. To the extent that a valuation allowance or uncertain tax position is established or changed during any period, we would recognize expense or benefit within our consolidated tax expense.

OFF-BALANCE SHEET ARRANGEMENTS

We have no off-balance sheet arrangements within the meaning of Item 303(a)(4) of SEC Regulation S-K.

RECENTLY ISSUED ACCOUNTING STANDARDS


•		Pronouncements Implemented During 2008

Adoption of SFAS No. 157— 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 under 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 has changed current practice. On February 12, 2008, the FASB issued FASB Staff Position 157-2 (“FSP 157-2”) which delayed the effective date of SFAS No. 157 for non-financial assets and liabilities. The delay allows companies additional time to consider the effect of various implementation issues that have arisen, or that may arise, from the application of SFAS No. 157. FSP FAS 157-3 was issued by the FASB on October 10, 2008 to clarify application of SFAS No. 157 when determining the fair value of a financial asset when the market for that financial asset is not active. The Company adopted SFAS No. 157 on January 1, 2008 for new fair value measurements of financial instruments, including its derivative instruments, and recurring fair value measurements of non-financial assets and liabilities. All financial instruments are measured using inputs from three levels of fair value hierarchy. The three levels are as follows:

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.

Level 2 inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

Level 3 inputs are unobservable inputs that reflect the Company’s assumptions about the assumptions that market participants would use in pricing an asset or liability.

Adoption of SFAS No. 159— In February 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 that are not currently required to be measured at fair value. While SFAS No. 159 became effective on January 1, 2008, the Company did not elect the fair value measurement option for any of its financial assets or liabilities.

Adoption of FSP No. 39-1— On April 30, 2007, the FASB issued FASB Staff Position (“FSP”) No. 39-1,Amendment of FASB Interpretation No. 39. The FSP amends GAAP to replace the terms “conditional contracts” and “exchange contracts” with the term “derivative instruments” as defined in SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. It also amends paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. The Company adopted FSP No. 39-1 on January 1, 2008 without significant impact.

Adoption of SFAS No. 162— In May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements in conformity with GAAP in the United States. This Statement is generally viewed as a necessary step in the ultimate convergence of global accounting rules. This Statement became effective on November 15, 2008, but had no impact on the Company’s financial statements or related disclosures.

On January 1, 2009, the Company also adopted FSP APB 14-1, SFAS No. 160 and FSP EITF 03-6-1 as more fully discussed previously.


•		Pronouncements Not Yet Implemented

SFAS No. 141 (revised 2007),Business Combinations, “SFAS No. 141(R)” was issued in December 2007. SFAS No. 141(R) replaces SFAS No. 141,Business Combinations, while retaining its fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) defines the acquirer as the entity that obtains control in the business combination and it establishes the criteria to determine the acquisition date. SFAS No. 141(R) applies to all transactions and events in which one entity obtains control over one or more other businesses. The Statement also requires an acquirer to recognize the assets acquired and liabilities assumed measured at their fair values as of the acquisition date. In addition, acquisition costs are required to be recognized as period expenses as incurred. The Statement will apply to any acquisition entered into after January 1, 2009, but otherwise had no effect on our financial statements upon adoption.

The FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities, in March 2008. Under SFAS No. 161, the Company will be required to disclose the fair value of all derivative and hedging instruments and their gains or losses in tabular format and information about credit risk-related features in derivative agreements, counterparty credit risk, and its strategies and objectives for using derivative instruments. SFAS No. 161 was adopted with prospective application by the Company on January 1, 2009. The adoption of SFAS No. 161 will change the Company’s disclosures about its derivative and hedging instruments, but had no impact on the Company’s previously reported results or financial position.

The SEC adopted revisions to its required oil and gas reporting disclosures in December 2008. The revisions impacting the Company include: 1) use of 12-month average of the first-day-of-the-month prices for determination of proved reserve values including in calculating full cost ceiling limitations; 2) limitations on the types of technologies that may be relied upon to establish the levels of certainty required to classify reserves; and 3) ability to disclose “probable” and “possible” reserves as defined by the SEC. The SEC also updated the required disclosure requirements and eliminated use of price recoveries subsequent to period end for use in the ceiling test. The Company will adopt these changes within the 2009 Annual Report on Form 10-K to be filed in 2010. The Company is still reviewing the implications of these revisions.

Item 8. Financial Statements and Supplementary Data

QUICKSILVER RESOURCES INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) for the Years Ended December 31, 2008, 2007 and 2006
Consolidated Balance Sheets as of December 31, 2008 and 2007
Consolidated Statements of Stockholders’ Equity for the Years ended December 31, 2008, 2007 and 2006
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006
Notes to Consolidated Financial Statements for the Years Ended December 31, 2008, 2007 and 2006 (Restated)

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, 2008 and 2007, and the related consolidated statements of income (loss) and comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2008. 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 Quicksilver Resources Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 14 and 21 to the consolidated financial statements, the accompanying 2008 financial statements have been restated.

As discussed in Note 2 to the consolidated financial statements, the accompanying consolidated financial statements have been adjusted for the retrospective application of Statement of Financial Accounting Standards No. 160,Noncontrolling Interests in Consolidated Financial Statements – an Amendment to ARB 51(“SFAS 160”), FASB Staff Position APB 14-1:Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)(“FSP APB 14-1”), and FASB Staff Position EITF 03-6-1:Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities(“FSP EITF 03-6-1”), all of which were adopted by the Company on January 1, 2009.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on the criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2009 (June 16, 2009 as to the effects of the material weaknesses discussed in Management’s Report on Internal Control Over Financial Reporting, as revised) expressed an adverse opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas
March 2, 2009 (June 16, 2009 as to the effects of the restatement as discussed in Notes 14 and 21, and as to the effects of the adoption of SFAS 160, FSP APB 14-1, and FSP EITF 03-6-1, and the related disclosures in Notes 2, 4, 12, 14, 16, 18 and 21)

QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006
In thousands, except for per share data


	2008			2007			2006
Revenues
Natural gas, NGL and crude oil	$	780,788		$	545,089		$	386,540
Other		19,853			16,169			3,822

Total revenues		800,641			561,258			390,362

Operating expenses
Oil and gas production expense		135,661			136,831			95,176
Production and ad valorem taxes		16,794			16,142			15,619
Other operating costs		3,918			2,792			1,461
Depletion, depreciation and accretion		188,196			120,697			78,800
General and administrative		72,254			47,060			25,636

Total expenses		416,823			323,522			216,692
Impairment related to oil and gas properties		(633,515	)		—			—
Income from equity affiliates		—			661			526
Gain on sale of oil and gas properties		—			628,709			—
Loss on natural gas sales contract		—			(63,525	)		—

Operating income (loss)		(249,697	)		803,581			174,196
Income from earnings of BBEP		93,298			—			—
Impairment of investment in BBEP		(320,387	)		—			—
Other income — net		807			3,887			1,825
Interest expense		(109,098	)		(76,662	)		(49,773	)

Income (loss) before income taxes		(585,077	)		730,806			126,248
Income tax (expense) benefit		211,455			(254,361	)		(36,151	)

Net income (loss)		(373,622	)		476,445			90,097
Net income attributable to noncontrolling interests		(4,654	)		(1,055	)		(91	)

Net income (loss) attributable to Quicksilver	$	(378,276	)	$	475,390		$	90,006

Other comprehensive income (loss)
Reclassification adjustments related to settlements of derivative contracts — net of income tax		11,969			(34,648	)		(9,707	)
Net change in derivative fair value — net of income tax		182,472			(14,794	)		83,410
Foreign currency translation adjustment		(49,403	)		29,409			(1,222	)

Comprehensive income (loss)	$	(233,238	)	$	455,357		$	162,487

Earnings (loss) per common share — basic	$	(2.33	)	$	3.04		$	0.58
Earnings (loss) per common share — diluted	$	(2.33	)	$	2.87		$	0.58
Basic weighted average shares outstanding		162,004			156,517			153,988
Diluted weighted average shares outstanding		162,004			168,029			166,266

The accompanying notes are an integral part of these consolidated financial statements.

QUICKSILVER RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2008 AND 2007
In thousands, except for share data


	2008			2007
ASSETS
Current assets
Cash and cash equivalents	$	2,848		$	28,226
Accounts receivable — net of allowance for doubtful accounts		143,315			90,244
Derivative assets at fair value		171,740			10,797
Current deferred income tax asset		—			18,946
Other current assets		75,433			42,188

Total current assets		393,336			190,401
Investments in equity affiliates		150,503			420,171
Property, plant and equipment — net
Oil and gas properties, full cost method (including unevaluated costs of $543,533 and $215,228, respectively)		3,142,608			1,764,400
Other property and equipment		655,107			377,946

Property, plant and equipment — net		3,797,715			2,142,346
Derivative assets at fair value		116,006			354
Other assets		40,648			20,479

	$	4,498,208		$	2,773,751

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	6,579		$	34
Accounts payable		282,636			192,855
Income taxes payable		40			46,601
Accrued liabilities		66,923			54,981
Derivative liabilities at fair value		9,928			64,104
Current deferred tax liability		52,393			—

Total current liabilities		418,499			358,575
Long-term debt		2,586,046			788,518
Asset retirement obligations		34,753			23,864
Derivative liabilities at fair value		—			16,327
Other liabilities		12,962			10,609
Deferred income taxes		234,385			383,390
Commitments and contingencies (Note 17)
Stockholders’ equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding		—			—
Common stock, $0.01 par value, 400,000,000 and 200,000,000 shares authorized, respectively; 171,742,699 and 160,633,270 shares issued, respectively		1,717			1,606
Paid in capital in excess of par value		656,958			378,622
Treasury stock of 4,572,795 and 2,616,726 shares, respectively		(35,441	)		(12,304	)
Accumulated other comprehensive income		185,104			40,066
Retained earnings		376,488			754,764

Quicksilver stockholders’ equity		1,184,826			1,162,754
Noncontrolling interests		26,737			29,714

Total equity		1,211,563			1,192,468

	$	4,498,208		$	2,773,751

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, 2008, 2007 AND 2006
In thousands, except for share data


	2008			2007			2006
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued	$	—		$	—		$	—

Common stock, $0.01 par value, 400,000,000 and 200,000,000 shares authorized
Balance at beginning of year		1,606			1,578			1,547
Issuance of common stock — Alliance Acquisition		104			—			—
Issuance of common stock — restricted stock		5			6			9
Issuance of common stock — stock options		2			22			22

Balance at end of year: 171,742,699, 160,633,270 and 157,783,515 shares issued at December 31, 2008, 2007 and 2006, respectively		1,717			1,606			1,578

Paid in capital in excess of par value
Balance at beginning of year		378,622			264,078			237,874
Stock issuance — Alliance Acquisition		261,988			—			—
Stock options exercised		1,242			21,365			19,667
Stock-based compensation expense recognized		15,106			11,108			6,537
Contributions received for subsidiary common units		—			79,316			—
Tax benefit related to stock options exercised		—			2,755			—

Balance at end of year		656,958			378,622			264,078

Treasury stock, at cost
Balance at beginning of year		(12,304	)		(10,737	)		(10,353	)
Acquisition of treasury stock		(23,137	)		(1,567	)		(384	)

Balance at end of year: 4,572,795, 2,616,726 and 2,579,671 shares at December 31, 2008, 2007, and 2006, respectively		(35,441	)		(12,304	)		(10,737	)

Accumulated other comprehensive income
Deferred gains (losses) on hedge derivatives
Balance at beginning of year		(4,248	)		45,194			(28,509	)
Reclassification adjustments related to settlements of derivative contracts		11,969			(34,648	)		(9,707	)
Net change in derivative fair value		182,472			(14,794	)		83,410

Balance at end of year		190,193			(4,248	)		45,194

Deferred foreign exchange adjustment
Balance at beginning of year		44,314			14,905			16,127
Foreign currency translation adjustment		(49,403	)		29,409			(1,222	)

Balance at end of year		(5,089	)		44,314			14,905

Total accumulated other comprehensive income		185,104			40,066			60,099

Retained earnings
Balance at beginning of year		754,764			279,719			189,713
Adoption of FIN 48		—			(345	)		—
Net income (loss)		(378,276	)		475,390			90,006

Balance at end of year		376,488			754,764			279,719

Quicksilver’s stockholders’ equity	$	1,184,826		$	1,162,754		$	594,737

Noncontrolling interest
Balance at beginning of year		29,714			7,382			—
Net income		4,654			1,055			91
Contributions by noncontrolling interests		—			29,942			7,291
Stock-based compensation expense		1,013			129			—
Distributions paid on KGS common units		(8,644	)		(8,794	)		—

Balance at end of year		26,737			29,714			7,382

Total Equity	$	1,211,563		$	1,192,468		$	602,119

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, 2008, 2007 AND 2006
In thousands


	2008			2007			2006
Operating activities:
Net income (loss)	$	(373,622	)	$	476,445		$	90,097
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion		188,196			120,697			78,800
Impairment related to oil and gas properties		633,515			—			—
Deferred income tax expense (benefit)		(166,440	)		207,796			35,878
(Gain) loss from sale of properties		605			(627,348	)		188
Non-cash (gain) loss from hedging and derivative activities		(1,139	)		62,515			—
Stock-based compensation		16,128			11,243			6,546
Amortization of deferred charges		1,014			2,189			226
Non-cash interest expense		12,201			8,185			7,782
Income from equity affiliates in excess of cash distributions		(50,762	)		—			—
Impairment of investment in BBEP		320,387			—			—
Provision for doubtful accounts		—			(349	)		701
Divestiture expenses		—			2,015			—
Changes in assets and liabilities
Accounts receivable		(53,071	)		(14,423	)		(1,100	)
Prepaid expenses and other assets		(5,448	)		(4,805	)		(5,021	)
Accounts payable		7,602			18,939			15,193
Income taxes payable		(46,561	)		46,012			308
Accrued and other liabilities		(26,039	)		9,993			12,588

Net cash provided by operating activities		456,566			319,104			242,186

Investing activities:
Purchases of property, plant and equipment		(1,286,715	)		(1,020,684	)		(619,061	)
Alliance Acquisition		(993,212	)		—			—
Return of investment from equity affiliates		—			9,635			1,923
Proceeds from sales of properties and equipment		1,339			741,297			5,113

Net cash used in investing activities		(2,278,588	)		(269,752	)		(612,025	)

Financing activities:
Issuance of debt		2,948,672			817,821			694,682
Repayments of debt		(1,096,163	)		(968,557	)		(350,754	)
Debt issuance costs		(25,219	)		(5,130	)		(9,213	)
Noncontrolling interest contributions		—			109,809			7,291
Noncontrolling interest distributions		(8,644	)		(8,794	)		—
Proceeds from exercise of stock options		1,244			21,387			19,689
Excess tax benefits on exercise of stock options		—			2,755			—
Purchase of treasury stock		(23,137	)		(1,567	)		(384	)

Net cash provided by (used in) financing activities		1,796,753			(32,276	)		361,311

Effect of exchange rate changes in cash		(109	)		5,869			(509	)

Net increase (decrease) in cash		(25,378	)		22,945			(9,037	)
Cash and cash equivalents at beginning of period		28,226			5,281			14,318

Cash and cash equivalents at end of period	$	2,848		$	28,226		$	5,281

The accompanying notes are an integral part of these consolidated financial statements.

QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

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, production and sale of natural gas, NGLs and crude oil as well as the marketing, processing and transmission of natural gas. As of December 31, 2008, substantial portions of Quicksilver’s oil and gas reserves and operations are located in Texas, the U.S. Rocky Mountains and Alberta, Canada. The Company has offices located in Fort Worth, Texas, Cut Bank, Montana, Glen Rose, Texas and in Calgary, Alberta. Until the Company completed the BreitBurn Transaction in 2007 (see Note 5), the Company also had significant oil and gas reserves and operations in Michigan, Indiana and Kentucky.

Quicksilver’s results of operations are largely dependent on the difference between the prices received for its natural gas, NGL and crude oil products and the cost to find, develop, produce and market such resources. Natural gas, NGL and crude oil prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other 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 actively manages a portion of the financial risk relating to natural gas, NGL and crude oil price volatility through derivative contracts.

2. ADJUSTMENTS AND SIGNIFICANT ACCOUNTING POLICIES

Adjustment for Retrospective Application of FSP APB 14-1, SFAS No. 160 and FSP EITF 03-6-1

We have adjusted the financial statements and notes thereto for the years ended December 31, 2008, 2007 and 2006 to reflect our adoption of FSP APB 14-1, SFAS No. 160 and FSP EITF 03-6-1.

FSP APB 14-1, Accounting for Convertible Debt Instruments That May be Settled in Cash upon Conversion

FSP APB 14-1 requires issuers to account separately for the liability and equity components of certain convertible debt instruments in a manner that reflects the issuer’s nonconvertible debt borrowing rate when interest expense is recognized. FSP APB 14-1 requires bifurcation of the debt and equity components of convertible debt. It also requires recognition of interest cost at an issuer’s effective interest rate instead of the stated or coupon rate. The Company adopted FSP APB 14-1 January 1, 2009, which also requires retrospective application to the terms of the Company’s instruments as they existed for all periods presented. The adoption of FSP APB 14-1 affects the accounting for the Company’s Convertible Debentures issued in 2004 and due 2024. The retrospective application of this pronouncement affects each of the years included in these consolidated financial statements and earlier periods and generally results in lower net earnings by virtue of higher interest expense.

SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements. SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary, formerly referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as equity. Among other requirements, SFAS No. 160 requires consolidated net income to include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated income statement. The retrospective application of this pronouncement affects years 2006 through 2008, but only affects the amounts reported on the balance sheet and the placement of amounts within the income statement. It has no effect on the net earnings (loss) or cash flows previously reported.

FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payments Transactions Are Participating Securities

Under FSP EITF 03-6-1, unvested share-based payment awards that contain nonforfeitable rights to dividends (whether paid or unpaid) are participating securities and should be included in the computation of earnings per share pursuant to the two-class method. The Company’s restricted stock grants issued as part of employees’ stock-based compensation have been identified as participating securities and have been included in the basic earnings per share calculation for the periods contained in this Report. The retrospective application of this pronouncement affects each of the years included in these consolidated financial statements and earlier periods, but only affects earnings per share and has no impact on net earnings (loss), cash flow or balance sheet amounts as previously reported.

The following table summarizes the effect of the retrospective application of the Adopted Pronouncements on certain previously reported line items:

Summarized Consolidated Statements of Operations information:


	Year Ended December 31,
	2008⁽¹⁾						2007⁽²⁾						2006⁽³⁾
				As Revised						As Revised						As Revised
	Originally			for New			Originally			for New			Originally			for New
(Amounts in $000’s, except per share data)	Reported			GAAP			Reported			GAAP			Reported			GAAP
Interest expense	$	102,510		$	109,098		$	70,527		$	76,662		$	44,061		$	49,773
Income (loss) before income taxes		(578,489	)		(585,077	)		736,941			730,806			131,960			126,248
Income tax (expense) benefit		209,149			211,455			(256,508	)		(254,361	)		(38,150	)		(36,151	)
Minority interest expense, net of tax		4,654			—			1,055			—			91			—
Net income (loss)		(373,994	)		(373,622	)		479,378			476,445			93,719			90,097
Net income attributable to noncontrolling interests		—			4,654			—			1,055			—			91
Net income (loss) attributable to Quicksilver		(373,994	)		(378,276	)		479,378			475,390			93,719			90,006
Earnings (loss) per common share — basic	$	(2.31	)	$	(2.33	)	$	3.08		$	3.04		$	0.61		$	0.58
Earnings (loss) per common share — diluted	$	(2.31	)	$	(2.33	)	$	2.86		$	2.87		$	0.58		$	0.58
Basic weighted average shares outstanding		161,622			162,004			155,475			156,517			153,413			153,988
Diluted weighted average shares outstanding		161,622			162,004			168,029			168,029			166,266			166,266


⁽¹⁾		Adjustments to 2008 are an increase to interest expense of $6,588, an increase to income tax benefit of $ 2,306 and an increase in basic and diluted weighted average shares outstanding of 382.

⁽²⁾		Adjustments to 2007 are an increase to interest expense of $6,135, a decrease to income tax expense of $2,147 and an increase in basic weighted average shares outstanding of 1,042.

⁽³⁾		Adjustments to 2006 are an increase to interest expense of $5,712, a decrease to income tax expense of $1,999 and an increase in basic weighted average shares outstanding of 575.

Consolidated Balance Sheet information:


	December 31, 2008⁽¹⁾				December 31, 2007⁽²⁾
			As Revised				As Revised
	Originally		for New		Originally		for New
(Amounts in $000’s, except per share data)	Reported		GAAP		Reported		GAAP
Other assets	$	43,011	$	40,648	$	22,574	$	20,479
Long-term debt		2,605,025		2,586,046		813,817		788,518
Deferred income tax liability		225,440		234,385		374,645		383,390
Deferred gain on sale of partnership interests		79,316		—		79,316		—
Minority interest in consolidated subsidiaries		29,867		—		30,338		—
Paid in capital in excess of par value		550,851		656,958		272,515		378,622
Retained earnings		392,478		376,488		766,472		754,764
Noncontrolling interests		—		26,737		—		29,714
Total equity		1,094,709		1,211,563		1,068,355		1,192,468


⁽¹⁾		Adjustments in 2008 include a decrease in other assets of $2,363, a decrease in long-term debt of $18,980, an increase in paid in capital in excess of par of $26,791, a decrease in retained earnings of $15,990 and an increase in deferred income tax liability of $5,816, all as a result of adopting FSP APB 14-1. Adjustments to 2008 also include an increase in deferred income tax liability of $3,130, a decrease in deferred gain on sale of partnership interests of $79,316, a decrease in minority interest in consolidated subsidiaries of $29,867, an increase in paid in capital in excess of par of $79,316 and an increase in noncontrolling interests of $26,737, all as a result of adopting SFAS No. 160.

⁽²⁾		Adjustments in 2007 include a decrease in other assets of $2,095, a decrease in long-term debt of $25,299, an increase in paid in capital in excess of par of $26,791, a decrease in retained earnings of $11,708 and an increase in deferred income tax liability of $8,121, all as a result of adopting FSP APB 14-1. Adjustments to 2008 also include an increase in deferred income tax liability of $624, a decrease to deferred gain on the sale of partnership interests of $79,316, a decrease in minority interest in consolidated subsidiaries of $30,338, an increase in paid in capital in excess of par of $79,316 and an increase in noncontrolling interests of $29,714, all as a result of adopting SFAS No. 160.

In addition, the adjustments pursuant to application of the Adopted Pronouncements resulted in changes to our consolidated statements of cash flows and stockholders’ equity and Notes 3, 4, 12, 14, 16, 18, 21 and 26.

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. We eliminate all inter-company balances and transactions in preparing consolidated financial statements. The Company accounts for its ownership in unincorporated partnerships and companies, including BBEP, under the equity method 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 trigger consolidation of the entities. The Company also consolidates its share of oil and gas joint ventures.

Stock Split

On January 7, 2008, Quicksilver announced that its Board of Directors declared a two-for-one stock split of Quicksilver’s outstanding common stock effected in the form of a stock dividend. The stock dividend was payable on January 31, 2008, to holders of record at the close of business on January 18, 2008. The split had no effect on shares held in treasury. The capital accounts, all share data and earnings per share data included in these consolidated financial statements for all years presented have been adjusted to retroactively reflect the January 2008 stock split.

Use of Estimates

The preparation of financial statements in conformity with GAAP in the U.S. 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 revenue 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, NGL and crude oil reserves used to compute depletion expense and future net cash flows from reserve production, estimates of current revenue 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, NGL 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 2008, two purchasers individually accounted for 17% and 10% of the Company’s consolidated natural gas, NGL and crude oil revenue. During 2007 and 2006, one purchaser accounted for approximately 13% and 10%, respectively, of the Company’s consolidated natural gas, NGL and crude oil revenue.

Hedging and Derivatives

The Company enters into financial derivative instruments to mitigate risk associated with the prices received from its natural gas, NGL and crude oil production. The Company may also utilize financial derivative instruments to hedge the risk associated with interest rates on its outstanding debt. All derivatives are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates. For derivatives instruments that qualify as cash flow hedges, the effective portions of gains and losses are deferred in other comprehensive income and recognized in revenue 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 earnings during the period in which the hedged transaction is recognized. If the hedged transaction becomes probable of not occurring, the deferred gain or loss would be immediately recorded to earnings. Changes in value of ineffective portions of hedges, if any, are recognized currently as a component of other revenue.

Until December 2007, the Michigan Sales Contract, which required delivery of 25 MMcfd of owned or controlled natural gas at a floor of $2.49 per Mcf through March 2009, had been excluded from derivatives as it was designated as a normal sales contract under accounting rules. In December 2007 and in connection with the divestiture of the Northeast Operations, the Company decided it would cease delivering a portion of its natural gas production to supply the contractual volumes. As the contract no longer qualified under the normal sales exclusion under derivative GAAP, the Company recognized a loss of $63.5 million at that time.

Until May 2007, the Company also had another long-term contract (the “CMS Contract”) for delivery of 10 MMcfd of owned or controlled natural gas at a floor price of $2.47 that was treated as a normal sales contract under SFAS No. 133. See Note 17 to these financial statements for more information regarding the CMS Contract.

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 when the operations of the affiliates are associated with processing and transportation of the Company’s natural gas production.

The Company accounts for it investment in BBEP using the equity method. The Company reviews its investment for impairment whenever events or circumstances indicate that the investment’s carrying amount may not be recoverable. The Company records its portion of BBEP’s earnings during the quarter in which their financial statements become publicly available. Thus, the Company’s 2008 results of operations reflect BBEP’s earnings from November 1, 2007, when the Company acquired the BBEP units, through September 30, 2008. The Company is not aware of any significant events or transactions subsequent to September 30, 2008 that will affect BBEP’s results of operations after that date. See Note 10 for more information on the BBEP investment.

Property, Plant, and Equipment

The Company follows the full cost method in accounting for its oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in cost centers on a country-by-country basis. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. 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. Excluded from amounts subject to depletion are costs associated with unevaluated properties.

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, 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. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required. Note 11 to these financial statements contains further discussion of the ceiling test.

All other properties and equipment are stated at original cost and depreciated using the straight-line method based on estimated useful lives ranging from five to forty years.

Revenue Recognition

Revenue is recognized when title to the products transfer to the purchaser. The Company uses the “sales method” to account for its production revenue, whereby the Company recognizes revenue on all natural gas, NGL 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, 2008 and 2007, the Company’s aggregate production imbalances were not material.

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 expected to be in effect in years in which the temporary differences reverse. Canadian taxes are calculated at rates in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested in Canada 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.

Stock-based Compensation

The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors based on their estimated fair value. At the discretion of the board of directors, the Company may issue awards payable in cash. For all awards, the Company recognizes the expense associated with the awards over the vesting period. The liability for fair value of cash awards is reassessed at every balance sheet date, such that the vested portion of the liability is adjusted to reflect revised fair value through compensation expense.

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. SFAS No. 157,Fair Value Measurements, was adopted on January 1, 2008 and applied to fair value measurements of the Company’s financial instruments, including its financial derivative instruments. Additional information regarding the Company’s implementation of the accounting standard is found under “Recently Issued Accounting Standards” in this Note.

Noncontrolling Interest in Consolidated Subsidiaries

Noncontrolling interest reflects the fractional outside ownership of the Company’s majority-owned and consolidated subsidiaries. Noncontrolling interest does not necessarily reflect the fair value of that outside ownership.

Foreign Currency Translation

The Company’s Canadian subsidiary uses the Canadian dollar as its functional currency. All balance sheet accounts of the Canadian operations are translated into U.S. dollars at the period-end rate of exchange and statement of income items are translated at the weighted average exchange rates for the period. The resulting translation adjustments are made directly to a 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 earnings per common share is computed by dividing the net income 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, unvested restricted stock and convertible debt.

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. For the year ended December 31, 2008, all dilutive securities were excluded from the diluted net loss per share calculation as they were antidilutive. No outstanding options were excluded from the diluted net income per share calculation for the years ended December 31, 2007 and 2006.


	Years Ended December 31,
	2008			2007		2006
	(In thousands, except per share data)
Net income (loss) attributable to Quicksilver	$	(378,276	)	$	475,390	$	90,006
Impact of assumed conversions — interest on convertible debentures, net of income taxes⁽¹⁾		—			6,056		5,781

Income (loss) available to stockholders assuming conversion of convertible debentures	$	(378,276	)	$	481,446	$	95,787

Weighted average common shares — basic		162,004			156,517		153,988
Effect of dilutive securities:
Employee stock options		—			1,326		2,220
Employee stock awards		—			370		242
Contingently convertible debentures		—			9,816		9,816

Weighted average common shares — diluted⁽¹⁾		162,004			168,029		166,266

Earnings (loss) per common share — basic	$	(2.33	)	$	3.04	$	0.58
Earnings (loss) per common share — diluted	$	(2.33	)	$	2.87	$	0.58


⁽¹⁾		For 2008, the effects of convertible debt, stock options and unvested restricted stock were antidilutive and, therefore, excluded from the diluted share calculations

Recently Issued Accounting Standards


•		Pronouncements Implemented During 2008

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.

Level 3 inputs are unobservable inputs that reflect the Company’s assumptions about the assumptions that market participants would use in pricing an asset or liability.

executed with the same counterparty under the same master netting arrangement. The Company adopted FSP No. 39-1 on January 1, 2008 without significant impact.

On January 1, 2009, the Company also adopted FSP APB 14-1, SFAS No. 160 and FSP EITF 03-6-1 as more fully discussed previously.


•		Pronouncements Not Yet Implemented

3. ALLIANCE ACQUISITION

In August 2008, Quicksilver completed the Alliance Acquisition, under which the Company acquired leasehold, royalty and midstream assets in the Barnett Shale in northern Tarrant and southern Denton Counties of Texas. The purchase price which was funded, in part, using $318 million of borrowings under its existing Senior Secured Credit Facility and proceeds of $674.5 million from the Senior Secured Second Lien Facility more fully described in Note 14:


(In thousands)
Purchase Price:
Cash paid	$	1,000,000
Cash received from post-closing settlement		(8,109	)
Cash paid for acquisition-related expenses		1,321

Total cash		993,212
Issuance of 10,400,468 common shares		262,092

	$	1,255,304

Quicksilver’s preliminary purchase price allocation is presented below:


(In thousands)

Allocation of Purchase Price:
Oil and gas properties — proved	$	787,918
Oil and gas properties — unproved		441,303
Midstream assets		27,350
Liabilities assumed		(496	)
Asset retirement obligations		(771	)

	$	1,255,304

The preliminary purchase price allocation is based on preliminary estimates of oil and gas reserves and other valuations and estimates by management and is subject to final closing adjustments and determination of the valuation of tangible assets related to wells, pipelines and facilities. The Company expects to finalize the purchase price allocation during the quarter ending September 30, 2009.

Pro Forma Information

The following table reflects the Company’s unaudited consolidated pro forma statements of income as though the Alliance Acquisition, associated borrowings and issuance of Company common stock had occurred on January 1 for each year presented. The revenue and expenses for the acquisition are included in the Company’s 2008 consolidated results beginning from the date of closing. The pro forma information is not necessarily indicative of the results of operations that would have been achieved had the acquisition been effective at January 1 each year presented.


	For the Years Ended
	December 31,
	2008			2007
	(In thousands, except per share data)
Revenues	$	875,607		$	629,868

Net income (loss)	$	(384,645	)	$	428,314

Earnings (loss) per common share — basic	$	(2.29	)	$	2.57
Earnings (loss) per common share — diluted	$	(2.29	)	$	2.40

4. QUICKSILVER GAS SERVICES LP

On August 10, 2007, the Company’s majority-owned subsidiary, KGS, completed its underwritten IPO. KGS, a limited partnership engaged in the business of gathering and processing natural gas produced from the Barnett Shale formation, sold 5,000,000 common units for $95.0 million, net of underwriters’ discount and other offering costs. On September 7, 2007, the underwriters of the KGS IPO exercised their option to purchase an additional 750,000 common units for approximately $14.6 million, net of underwriters’ discount.

Upon completion of the IPO, KGS paid Quicksilver approximately $112.1 million in cash and issued Quicksilver a subordinated note with a principal amount of $50 million as a return of investment capital contributed and reimbursement for capital expenditures advanced which eliminated the Company’s investment in the KGS-predecessor. Due to a portion of the Company’s common interests in KGS being subordinated, Quicksilver initially deferred recognition of a gain of approximately $79.3 million related to its post-IPO ownership in KGS. The gain was originally expected to be recognized in earnings when the subordination period terminated, however the adoption of SFAS No. 160, as more fully described in Note 2, caused this amount to reclassified to stockholders’ equity on a retrospective basis for all periods subsequent to the KGS IPO.

As of December 31, 2008, KGS’ ownership is summarized in the following table:


	KGS Ownership
	Quicksilver			Third Parties			Total
General partner interests		1.9	%		—			1.9	%
Limited partner interests:
Common interests		23.5	%		27.1	%		50.6	%
Subordinated interests		47.5	%		—			47.5	%

Total interests		72.9	%		27.1	%		100.0	%

The subordinated units will convert into an equal number of common units upon termination of the subordination period. The subordination period is expected to end in February 2011, assuming KGS has earned and paid at least $0.30 per quarter on each outstanding common unit through that time.

The Company includes the results of operations and financial position of KGS in the consolidated financial statements of Quicksilver, and recognizes the portion of KGS’ results of operations attributable to unaffiliated unitholders as net income attributable to noncontrolling interests.

5. DIVESTITURE OF NORTHEAST OPERATIONS

In November 2007, Quicksilver closed on an agreement (the “BreitBurn Transaction”) to contribute all of its oil and gas properties and facilities in Michigan, Indiana and Kentucky (collectively the “Northeast Operations”) to BBEP. Total consideration for the BreitBurn Transaction was $750 million of cash and 21.348 million common units of BBEP, equaling total consideration of $1.47 billion based on closing market prices on that date. Upon closing, the Company used $654 million of proceeds from the BreitBurn Transaction to repay all U.S. borrowings then outstanding under its Senior Secured Credit Facility. Under the terms of the transaction, the Company must retain 50% of the acquired units until May 1, 2009, but may now freely trade the other acquired units.

Concurrent with closing the BreitBurn Transaction, the Company agreed to provide certain one-time benefits to 141 terminated employees, including settling unvested stock-based compensation in cash and providing cash severance and retention benefits payable in multiple installments over two years. The Company anticipates the total expense associated with the termination-related employees benefits to be approximately $10.2 million which was recognized approximately 60% in 2007 and 20% in 2008 plus an expected 20% in 2009. The $6.3 million recognized in oil and gas production costs in the latter half of 2007 was comprised of expenses to settle unvested stock-based compensation of $4.9 million and severance payments of $1.4 million associated with services rendered through the end of 2007 by affected employees. The $2.1 million recognized in 2008 and amounts to be recognized in 2009 are attributable to the services rendered or expected to be rendered by the affected employees over these periods and are payable only in the event of their continued employment by BBEP.

A portion of the Company’s hedging program that was designated to the Northeast Operations for the period subsequent to the closing of the BreitBurn Transaction no longer qualifies for hedge accounting treatment. Accordingly, concurrent with the completion of the BreitBurn Transaction, the Company reclassified the amounts included in accumulated other comprehensive income for the affected Northeast Operations hedges and recognized the changes in fair value for such contracts. This aggregate recognition totaled approximately $0.8 million, which increased other revenue in the 2007 consolidated statements of income. In the fourth quarter of 2007, the Company re-designated the hedges for the Northeast Operations as hedges of other U.S. production and applied hedge accounting treatment for prospective changes in value.

The Company was considered to have a “continuing interest” in the assets and subsidiaries sold in the BreitBurn Transaction as the Company owned approximately 32% of BBEP’s outstanding common units at the time of the BreitBurn Transaction. Thus, the Company deferred $294 million, or 32%, of the $923 million calculated book gain and recorded its investment in BBEP units, with an aggregate value of $724 million, net of the $294 million deferred gain for a net carrying value of $430 million at December 31, 2007. The Company accounts for its investment in the BBEP common units using the equity method, utilizing a one quarter lag from BBEP’s publicly available information. See Note 10 for recent developments regarding the Company’s investment in BBEP.

In completing the BreitBurn Transaction, the Company utilized investment banking services. Approximately $2 million of expense related to such services was included in general and administrative expense during the third quarter of 2007, with an additional approximately $8.2 million recognized in the fourth quarter of 2007 as a reduction of proceeds generated by the BreitBurn Transaction.

Under the full cost method of accounting, the Company’s U.S. exploration and production assets are considered a single asset. The divestiture of the Northeast Operations, therefore, represents a fractional divestiture of a single asset which precludes reporting the Northeast Operations’ financial position and results of operations as discontinued operations within the consolidated financial statements.

6. DERIVATIVES AND FAIR VALUE MEASUREMENTS

In accordance with the fair value hierarchy described in SFAS No. 157, the following table shows the fair value of the Company’s financial assets and liabilities that are required to be measured at fair value as of December 31, 2008.


	Fair Value Measurements as of December 31, 2008
										Balance Sheet
	Level 1		Level 2		Level 3		Other⁽¹⁾			Total
	(In thousands)
Derivative assets	$	—	$	295,085	$	—	$	(7,339	)	$	287,746

Derivative liabilities	$	—	$	17,267	$	—	$	(7,339	)	$	9,928


⁽¹⁾		Represents amounts netted under master netting arrangements

The Company’s derivative instruments at December 31, 2008 and 2007 include the Michigan Sales Contract that requires delivery of 25 MMcfd of natural gas for $2.49 per Mcf through March 2009. In December 2007 and in connection with the divestiture of the Northeast Operations, the Company decided to cease delivering a portion of its natural gas production to supply the contract. As the contract no longer qualified for the normal sales exclusion under GAAP, the Company recognized a $63.5 million loss at that time. In January 2008, the Company entered into two fixed-price natural gas swaps covering all volumes for the remaining contract period, which served to largely eliminate future earnings exposure for the Company’s remaining obligation under the Michigan Sales Contract. During 2008, the Company paid $48.2 million, net of derivative settlements, to meet its obligations under the Michigan Sales Contract.

The change in carrying value of the Company’s derivatives and the contractual fixed-price sale commitments in the Company’s balance sheet since December 31, 2007 principally resulted from the decrease in market prices for natural gas, NGL and oil relative to the prices in our derivative instruments and, to a lesser degree, from settlements made during 2008. The change in fair value of the effective portion of all cash flow hedges was reflected in accumulated other comprehensive income, net of deferred tax effects. The Company recorded $1.6 million and $1.0 million of net gains and a $0.1 million net loss in other revenue as the result of derivative hedge ineffectiveness for the years ended December 31, 2008, 2007 and 2006, respectively.

The estimated fair values of all derivatives and fixed-price firm sale commitments of the Company as of December 31, 2008 and 2007 are provided below. The associated carrying values of these derivatives 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 where rights of offset exists.


	As of December 31,
	2008		2007
	(In thousands)
Derivative assets:
Natural gas collars	$	260,901	$	10,491
Natural gas fixed-price swaps		34,184		4,666

	$	295,085	$	15,157

Derivative liabilities:
Natural gas basis swaps	$	4,365	$	1,224
Natural gas fixed-price swaps⁽¹⁾		4,839		—
Natural gas financial collars		—		1,625
Crude oil financial collars		—		6,517
NGL fixed—price swaps		—		11,294
Fixed-price natural gas sales contracts⁽¹⁾		8,063		63,777

	$	17,267	$	84,437


⁽¹⁾		Includes $8.1 million and $63.5 million for the Michigan Sales Contract at December 31, 2008 and 2007, respectively, and fixed price natural gas swaps with a liability value of $4.8 million at December 31, 2008 that eliminated earnings exposure for the required natural gas purchases

Hedge derivative assets and liabilities of $176.6 million and $1.9 million, respectively have been classified as current at December 31, 2008 based on the maturity of the derivative instruments, resulting in $115.1 million of after-tax gains expected to be reclassified from accumulated other comprehensive income in 2009.

7. FINANCIAL INSTRUMENTS

Commodity Price Risk

The Company enters into financial derivative contracts to mitigate its exposure to commodity price risk associated with anticipated future natural gas production and to increase the predictability of our revenue. As of December 31, 2008, approximately 150 MMcfd and 40 MMcfd of natural gas price collars and swaps, respectively, have been put in place to hedge 2009 anticipated natural gas production. Also, approximately 160 Mmcfd of natural gas collars have been executed to hedge anticipated 2010 natural gas production.

The following tables summarize our open derivative positions as of December 31, 2008 related to the Company’s natural gas production:

Weighted Avg Price

Product

Type

Contract Period

Volume

Per Mcf

Fair Value

(In thousands)

Gas

Swap

Jan 2009-Dec 2009

10,000 Mcfd

8.45

8,537

Gas

Swap

Jan 2009-Dec 2009

10,000 Mcfd

8.45

8,537

Gas

Swap

Jan 2009-Dec 2009

20,000 Mcfd

8.46

17,110

Gas

Collar

Jan 2009-Mar 2009

20,000 Mcfd

7.50- 9.35

3,259

Gas

Collar

Jan 2009-Mar 2009

20,000 Mcfd

8.00-10.20

4,132

Gas

Collar

Jan 2009-Dec 2009

20,000 Mcfd

7.50- 9.34

11,373

Gas

Collar

Jan 2009-Dec 2009

20,000 Mcfd

7.75-10.20

13,242

Gas

Collar

Jan 2009-Dec 2009

10,000 Mcfd

7.75-10.26

6,651

Gas

Collar

Jan 2009-Dec 2009

20,000 Mcfd

8.25- 9.60

16,083

Gas

Collar

Jan 2009-Dec 2009

10,000 Mcfd

8.25-10.45

8,290

Gas

Collar

Jan 2009-Dec 2009

10,000 Mcfd

8.25-10.45

8,290

Gas

Collar

Jan 2009-Dec 2009

10,000 Mcfd

8.25-10.45

8,290

Gas

Collar

Jan 2009-Dec 2009

10,000 Mcfd

11.50-14.48

19,520

Gas

Collar

Apr 2009-Dec 2009

10,000 Mcfd

8.50-13.15

6,796

Gas

Collar

Apr 2009-Dec 2009

30,000 Mcfd

11.00-13.50

38,970

Gas

Collar

Jan 2010-Dec 2010

20,000 Mcfd

8.00-11.00

10,423

Gas

Collar

Jan 2010-Dec 2010

20,000 Mcfd

8.00-11.00

10,423

Gas

Collar

Jan 2010-Dec 2010

20,000 Mcfd

8.00-12.20

11,077

Gas

Collar

Jan 2010-Dec 2010

20,000 Mcfd

8.00-12.20

11,077

Gas

Collar

Jan 2010-Dec 2010

10,000 Mcfd

8.50-12.05

6,778

Gas

Collar

Jan 2010-Dec 2010

20,000 Mcfd

8.50-12.05

13,555

Gas

Collar

Jan 2010-Dec 2010

10,000 Mcfd

8.50-12.08

6,795

Gas

Collar

Jan 2010-Dec 2010

40,000 Mcfd

10.00-13.50

45,877

Gas

Basis

Jan 2009-Dec 2009

20,000 Mcfd

(1,865

)

Gas

Basis

Jan 2009-Dec 2009

10,000 Mcfd

(932

)

Gas

Basis

Jan 2009-Dec 2009

15,000 Mcfd

(798

)

Gas

Basis

Jan 2009-Dec 2009

15,000 Mcfd

(770

)

Total

290,720

As discussed in Note 6, the Company also has an obligation through March 2009 to deliver 25 MMcfd of natural gas under the Michigan Sales Contract, which has a floor price of $2.49 per Mcf. In January 2008, the Company entered into two fixed-price natural gas swaps covering all remaining volumes for the remaining contract period that have served to effectively eliminate any significant net earnings exposure for the Company’s remaining obligations. During 2008, the Company paid $48.2 million of net cash in settlement of its obligations under the Michigan Sales Contract.


				Weighted Avg Price
Product	Type	Contract Period	Volume	Per Mcf		Fair Value
						(In thousands)
Gas	Sale	Jan 2009-Mar 2009	25,000 Mcfd	$	2.49	$	(8,063	)
Gas	Swap	Jan 2009-Mar 2009	10,000 Mcfd		8.20		(1,935	)
Gas	Swap	Jan 2009-Mar 2009	15,000 Mcfd		8.20		(2,904	)

				Total		$	(12,902	)

Utilization of our financial hedging program will most often result in the Company’s realized prices from the sale of its natural gas, NGL and crude oil to vary from market prices. As a result of settlements of derivative contracts, the Company’s revenue from natural gas, NGL and crude oil production was $18.4 million lower for 2008 and $51.1 million and $15.5 million higher for 2007 and 2006, respectively.

Interest Rate Risk

There were no interest rate swaps utilized during 2008 or 2007. However, interest expense for 2006 was $0.1 million lower as a result of interest rate swaps.

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 at spot or short-term contract prices. All its production is sold to large trading companies and energy marketing companies, refineries and other users of petroleum products. The Company also enters into hedge derivatives with financial counterparties. The Company monitors exposure to counterparties by reviewing credit ratings, financial statements and credit service reports. Exposure levels are limited and parental guarantees and collateral are used to manage our exposure to counterparties according to the Company’s established policy. Each customer and counterparty is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. The Company has not experienced any significant credit losses during any of the three years ended December 31, 2008.

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 its management of credit risk. Each customer and counterparty 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. For 2008, 2007 and 2006, non-functional currency transactions resulted in losses of $3.3 million, $0.8 million and $0.1 million, respectively, included in net earnings. Furthermore, the Senior Secured Credit Facility permits Canadian borrowings to be made in either U.S. or Canadian-denominated amounts. However, the aggregate borrowing capacity of the entire facility is calculated using the U.S. dollar equivalent. Accordingly, there is a risk that exchange rate movements could impact the available borrowing capacity.

Although cross-currency transactions are minimized, the result of a 10% change in the Canadian-U.S. exchange rate would increase or decrease stockholders’ equity by approximately $28 million at December 31, 2008.

8. ACCOUNTS RECEIVABLE

Accounts receivable consisted of the following:


		As of December 31,
		2008			2007
		(In thousands)
Accrued production receivables		$	47,552		$	51,429
Income tax receivable			47,928			—
Joint interest receivables			29,420			26,026
Accrued taxes receivable			12,877			9,804
Other receivables			5,624			3,089
Allowance for doubtful accounts	��		(86	)		(104	)

		$	143,315		$	90,244

9. OTHER CURRENT ASSETS

Other current assets consisted of the following:


	As of December 31,
	2008		2007
	(In thousands)
Spare parts and supplies	$	64,185	$	31,980
Prepaid production taxes		7,239		—
Prepaid drilling rentals		384		4,457
Deposits		109		2,134
Other prepaid expenses		3,516		3,617

	$	75,433	$	42,188

10. INVESTMENT IN BREITBURN ENERGY PARTNERS L.P.

In 2007, the Company received common units of BBEP, a publicly traded limited partnership, as part of the BreitBurn Transaction, which is more fully described in Note 5. On June 17, 2008, BBEP announced that it had repurchased and retired 14.4 million units, which represented approximately 22% of the units previously outstanding. The resulting reduction in the number of BBEP common units outstanding increased the Company’s ownership from approximately 32% to approximately 41%.

During the fourth quarter of 2008, the Company evaluated its investment in BBEP for impairment in response to decreases in both prevailing commodity prices and BBEP’s unit price. The Company considered numerous factors in evaluating whether this decline was other-than-temporary. In final reflection, the length of time at which BBEP traded below the Company’s net carrying value per unit, prevailing petroleum prices and broad limitations on available capital resulted in the determination that the decline in value was other-than-temporary. While the Company believes that the market forces that influence commodity and equity prices are under duress, the accounting rules that govern fair value assessments are rigid in their requirement to utilize the quoted market prices for determination of fair value. Accordingly, the impairment analysis utilized the December 31, 2008 price of $7.05 per BBEP unit. This resulted in an aggregate fair value of $150.5 million for the portion of BBEP units owned by the Company, which was then compared to the carrying value of $470.9 million. The difference of $320.4 million was recognized as an impairment charge during 2008.

Summarized estimated financial information for BBEP is as follows:



	As of
	September 30, 2008
	(In thousands)
Current assets	$	90,284
Property, plant and equipment		1,914,432

Other assets		66,583
Current liabilities		129,084
Long-term debt		708,000
Other non-current liabilities		121,005

Partners’ equity		1,127,679


	For the Eleven Months
	Ended
	September 30, 2008
	(In thousands)
Revenues	$	420,321
Operating expenses		251,618

Operating income		168,703
Interest and other		27,795
Income tax expense		593
Minority interests		206

Net income	$	140,109

Net income available to common unitholders	$	141,660

11. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:


	As of December 31,
	2008			2007
	(In thousands)
Oil and gas properties
Subject to depletion	$	3,621,831		$	1,811,295
Unevaluated costs		543,533			215,228
Accumulated depletion		(1,022,756	)		(262,123	)

Net oil and gas properties		3,142,608			1,764,400
Other plant and equipment
Pipelines and processing facilities		664,112			379,869
General properties		57,941			32,966
Accumulated depreciation		(66,946	)		(34,889	)

Net other property and equipment		655,107			377,946

Property, plant and equipment, net of accumulated depletion and depreciation	$	3,797,715		$	2,142,346

Ceiling Test Analysis

As described in Note 2, the Company is required to perform a quarterly ceiling test for each of its cost centers. The ceiling test incorporates assumptions regarding pricing and discount rates over which management has no influence in the determination of present value. Additionally, the Company’s ceiling test for its U.S. cost center ignores any effects of the benefits attendant to the ownership and consolidation of KGS. In arriving at the ceiling amount for the fourth quarter of 2008, the Company used $5.71 per Mcf of natural gas, $44.60 per Bbl of oil and $21.65 per Bbl of NGL for its U.S. properties’ production horizon. When the present value of the U.S. reserves was calculated, the carrying value exceeded the ceiling limit by $624.3 million and resulted in the impairment charge recognized during the fourth quarter of 2008. The Company has the ability to examine price recoveries subsequent to December 31, 2008 for incorporation into a revised ceiling calculation; however, such changes were insufficient to eliminate the impairment charge. The Company’s Canadian ceiling test required no impairment of its Canadian oil and gas properties.

During the fourth quarter of 2008,the Company determined that the exploration costs for the Delaware Basin of West Texas would become part of the U.S. full-cost pool and no longer remain excluded from depletion. The Company also evaluated its midstream assets in West Texas for impairment, recording an impairment charge of $9.2 million to reduce those midstream assets to their estimated fair values.

Unevaluated Natural Gas and Crude Oil Properties Not Subject to Depletion

Under full cost accounting, the Company may exclude certain unevaluated property costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties not subject to depletion at December 31, 2008 and 2007 and the year in which they were incurred follows:


	December 31, 2008 Costs Incurred During										December 31, 2007 Costs Incurred During
	2008		2007		2006		Prior		Total		2007		2006		2005		Prior		Total
	(In thousands)										(In thousands)
Acquisition costs	$	381,203	$	54,094	$	31,328	$	53,998	$	520,623	$	71,835	$	25,357	$	39,810	$	37,834	$	174,836
Exploration costs		19,632		—		—		—		19,632		20,334		20,058		—		—		40,392
Capitalized interest		3,278		—		—		—		3,278		—		—		—		—		—

Total	$	404,113	$	54,094	$	31,328	$	53,998	$	543,533	$	92,169	$	45,415	$	39,810	$	37,834	$	215,228

The following table summarizes the unevaluated property costs not subject to depletion.


	As of December 31,
	2008		2007
	(In thousands)
Fort Worth Basin	$	440,092	$	107,163
Canadian Horn River Basin		80,590		30,784
Canadian CBM		—		21,170
West Texas		—		50,908
Other		22,851		5,203

Total	$	543,533	$	215,228

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. Unevaluated acquisition costs will require an estimated eight to ten years of exploration and development activity before evaluation is complete.

Other Matters

Capitalized overhead costs that directly relate to exploration and development activities were $16.8 million, $7.0 million and $3.2 million for the years ended December 31, 2008, 2007 and 2006, respectively. Depletion per Mcfe was $1.68, $1.28 and $1.07 for the years ended December 31, 2008, 2007 and 2006, respectively.

12. OTHER ASSETS

Other assets consisted of the following:


	As of December 31,
	2008			2007
	(In thousands)
Deferred financing costs	$	44,917		$	19,701
Less accumulated amortization		(8,049	)		(3,680	)

Net deferred financing costs		36,868			16,021
Deferred compensation costs		—			1,003
Deposits		3,008			2,312
Other		772			1,143

	$	40,648		$	20,479

Costs related to the acquisition of debt are deferred and amortized over the term of the debt.

13. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:


	As of December 31,
	2008		2007
	(In thousands)
Accrued operating expenses	$	20,296	$	14,745
Interest payable		30,713		7,402
Accrued capital expenditures		1,695		11,417
Accrued product purchases		1,382		9,784
Revenue payable		7,181		6,692
Accrued production and property taxes		4,137		3,301
Prepayments from partners		974		732
Environmental liabilities		50		262
Other		495		646

	$	66,923	$	54,981

14. LONG-TERM DEBT (Restated)

Except for issues arising from the failure to provide certain financial information about the Company and its restricted subsidiaries required to be disclosed under its supplemental indentures and as described in Note 21, as of December 31, 2008, the Company was in compliance with all covenants associated with its long-term debt, other notes and loans. On June 15, 2009, the Company completed receipt of acknowledgements from its lenders for the senior secured credit facility wherein they agreed to waive any defaults associated with the provision of financial information about the Company and its restricted subsidiaries. The Company believes that the provision of the financial information about the Company and its restricted subsidiaries herein satisfies the reporting requirements for all previous periods and requires no further waivers from lenders, and accordingly has made no change to the anticipated maturities of the outstanding debt, as previously reported. Notes 21 and 27 have also been restated to reflect inclusion of this financial information.

Long-term debt consisted of the following:


	As of December 31,
	2008			2007
	(In thousands)
Senior secured credit facility	$	827,868		$	310,710
Senior secured second lien facility, net of unamortized discount of $13,050		641,555			—
Senior notes due 2015, net of unamortized discount of $5,938		469,062			—
Senior subordinated notes due 2016		350,000			350,000
Convertible debentures, net of unamortized discount of $20,760 and $27,192		129,240			122,808
KGS Credit Agreement		174,900			5,000
Other loans		—			34

Total debt		2,592,625			788,552
Less current maturities		(6,579	)		(34	)

Long-term debt	$	2,586,046		$	788,518

Maturities are as follows


					Senior Secured				Senior
	Total		Senior Secured		Second Lien		Senior Notes		Subordinated		Convertible		KGS
	Indebtedness		Credit Facility		Facility		due in 2015		Notes		Debentures		Credit Facility
	(In thousands)
2009	$	6,579	$	—	$	6,579	$	—	$	—	$	—	$	—
2010		6,579		—		6,579		—		—		—		—
2011		6,579		—		6,579		—		—		—		—
2012		1,009,347		827,868		6,579		—		—		—		174,900
2013		628,289		—		628,289		—		—		—		—
Thereafter		975,000		—		—		475,000		350,000		150,000		—

	$	2,632,373	$	827,868	$	654,605	$	475,000	$	350,000	$	150,000	$	174,900

Senior Secured Credit Facility

The Company’s Senior Secured Credit Facility matures February 9, 2012. The facility provides for revolving loans, swingline loans and letters of credit from time to time in an aggregate amount not to exceed the borrowing base, which is calculated based on several factors. The borrowing base is subject to at least annual redeterminations. In September 2008, the lenders agreed to a borrowing base of $1.2 billion. The lenders also agreed to $1.2 billion of revolving credit commitments and, with lender approval, the Company has an option to increase the facility to $1.45 billion. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. currency available for borrowing by U.S. subsidiaries and either U.S. or Canadian currency available for borrowing in Canada. The facility has the option to extend the maturity up to two additional years. 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 its domestic subsidiaries’ oil and gas properties and quantities of proved reserves of natural gas, NGLs and crude oil attributable to them. Canadian borrowings under the facility are guaranteed by Quicksilver and most of Quicksilver’s domestic subsidiaries and are secured by, among other things, the Company’s Canadian, Quicksilver’s and certain of Quicksilver’s domestic subsidiaries’ oil and gas properties and quantities of proved reserves of natural gas, NGLs and crude oil attributable to them. In 2007, the Company agreed to pledge the equity interests in BBEP it received as part of the BreitBurn Transaction to secure its obligations under the credit facility. At December 31, 2008, the Company had approximately $369 million available borrowing capacity under this facility.

Senior Secured Second Lien Facility

On August 8, 2008, the Company entered into a $700 million five-year senior secured second lien facility (“Senior Secured Second Lien Facility”) pursuant to the Alliance Acquisition. Net proceeds were $674.5 million after discount and issuance costs. The Senior Secured Second Lien Facility features LIBOR or ABR rate options with minimum floors plus a spread. On the last day of each quarter, the Company must make a principal payments of $1.6 million which will be adjusted should the Company make unscheduled loan repayments. In connection with the Senior Secured Second Lien Facility, Quicksilver entered into collateral agreements pursuant to which Quicksilver’s obligations under the Senior Secured Second Lien Facility, its Senior Notes due 2015 and its domestic subsidiaries’ guaranty obligations with respect to the Senior Secured Second Lien Facility and the Senior Notes have been secured equally and ratably by a second lien on substantially all of the assets of Quicksilver and such domestic subsidiaries and the equity of certain domestic subsidiaries.

Senior Notes

On June 27, 2008, the Company issued $475 million of Senior Notes due 2015 (“Senior Notes”), which are secured, senior obligations of the Company. Interest of 8.25% is payable semiannually on February 1 and August 1. Net proceeds of $457 million after discount and issuance costs were used to pay down balances then outstanding under the senior secured credit facility.

Senior Subordinated Notes

On March 16, 2006, the Company issued the senior subordinated notes due 2016 (“Senior Subordinated Notes”), which 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.

Convertible Debentures

The convertible debentures due November 1, 2024 are contingently convertible into shares of Quicksilver’s common stock. The debentures bear interest at an annual rate of 1.875% payable semi-annually on May 1 and November 1. The Company recognizes interest expense at a rate of 6.75%, which represents the rate at the time that the convertible debentures were issued. The Company recognized an aggregate discount of $42.7 million upon issuance of the convertible debentures, which will be amortized through October 2011. Additionally, 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 65.4418 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 at least $18.34 (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 any combination of Quicksilver common stock and cash. Should all debentures be converted to Quicksilver common stock, an additional 9,816,270 shares would become outstanding; however, as of January 1, 2009, the debentures were not convertible.

The following summarizes information related to the convertible debentures after giving effect to the adoption of FSP APB 14-1:


	As of December 31,
	2008			2007
	(In thousands)
Carrying value of equity component	$	42,675		$	42,675

Principal amount of liability component	$	150,000		$	150,000
Unamortized discount		(20,760	)		(27,192	)
Net carrying value	$	129,240		$	122,808


	For the years ended December 31,
	2008		2007		2006
	(In thousands)
Interest cost on contractual coupon rate	$	2,813	$	2,813	$	2,813
Interest cost on amortization of discount⁽¹⁾		6,432		6,013		5,622



⁽¹⁾		Interest rate on the liability component is 6.75% for each of the three years in the period ended December 31, 2008.

KGS Credit Agreement

Concurrent with its IPO, KGS entered into a five-year $150 million senior secured revolving credit facility (“KGS Credit Agreement”), with an option exercisable by KGS to extend the facility for up to two additional years. In October of 2008, the lenders increased the facility to $235 million and approved an accordion option of $115 million to allow for future expansion of the facility to $350 million upon lender approval. The KGS Credit Agreement provides for revolving credit loans, swingline loans and letters of credit. Borrowings under the facility are guaranteed by KGS’ subsidiaries and are secured by substantially all of the assets of KGS and each of its subsidiaries. The facility features LIBOR and U.S. prime rate interest options for revolving loans and a specified rate for swingline loans. Each interest rate option includes a margin which flexes based upon KGS’ leverage ratio.

Summary of All Outstanding Debt

The following table summarizes significant aspects of our long-term debt.

Priority of Right to Collateralized Assets⁽⁶⁾

Recourse only to

Highest priority

Lowest priority

KGS assets

Equal priority

Senior Secured

Senior

Convertible

KGS Credit

Credit Facility

Second Lien Facility

Senior Notes

Subordinated Notes

Debentures

Agreement

Maturity date

February 9, 2012

August 8, 2013

June 27, 2015

March 16, 2016

November 1, 2024

August 10, 2012

Interest rate at December 31, 2008⁽¹⁾

3.44%

7.75%

8.25%

7.125%

1.875%

2.90%

Base interest rate
options⁽⁵⁾

LIBOR, ABR or
specified

LIBOR or ABR

N/A

LIBOR, ABR or
specified

Financial covenants
for 2009⁽³⁾

- Minimum current ratio of 1.0

- - Minimum EBITDA to interest expense ratio of 2.5

- - Minimum reserve PV 10 plus 50% of BBEP investment fair value to total debt of 1.5

- - Minimum reserve PV 10 plus 50% of BBEP investment fair value to secured debt of 2.0

- Minimum current ratio of 1.0

- - Minimum EBITDA to interest expense ratio of 2.25

- - Minimum reserve PV 10 plus 50% of BBEP investment fair value to total debt of 1.5

- - Minimum reserve PV 10 plus 50% of BBEP investment fair value to secured debt of 2.0

N/A

- Maximum debt to EBITDA ratio of 4.5

- - Minimum EBITDA to interest expense ratio of 2.5

Financial covenants
beyond 2009^{(3) (4)}

- Minimum current ratio of 1.0

- - Minimum EBITDA to interest expense ratio of 2.5

- - Minimum reserve PV 10 plus 50% of BBEP investment fair value to total debt of 1.5

- - Reserve PV 10 plus 50% of BBEP investment fair value to secured debt of 2.25 beginning December 31, 2010

- Minimum current ratio of 1.0

- - Minimum EBITDA to interest expense ratio of 2.25

- - Minimum reserve PV 10 plus 50% of BBEP investment fair value to total debt of 1.5

- - Reserve PV 10 plus 50% of BBEP investment fair value to secured debt of 2.25 beginning December 31, 2010

N/A

- Maximum debt to EBITDA ratio of 4.5

- - Minimum EBITDA to interest expense ratio of 2.5

Significant
restrictive
covenants⁽³⁾

- Incurrence of debt

- - Incurrence of liens

- - Payment of dividends

- - Equity purchases

- - Asset sales

- - Affiliate transactions

- - Limitations on derivatives

- Incurrence of debt

- - Incurrence of
liens

- - Payment of dividends

- - Equity purchases

- - Asset sales

- - Affiliate transactions

- - Limitations on derivatives

- Incurrence of debt

- - Incurrence of liens

- - Payment of dividends

- - Equity purchases

- - Asset sales

- - Affiliate transactions

N/A

- Incurrence of debt

- - Incurrence of
liens

- - Equity
purchases

- - Asset sales

- - Limitations on derivatives

Estimated fair
value⁽²⁾

$827.9 million

$455.0 million

$349.1 million

$187.2 million

$93.8 million

$174.9 million


⁽¹⁾		Represents the weighted average borrowing rate payable to lenders

⁽²⁾		The estimated fair value is determined based on market quotations on balance sheet date for fixed rate obligations. The Company considers debt with market-based interest rates to have a fair value equal to its carrying value

⁽³⁾		The covenant information presented in this table is qualified in all respects by reference to the full text of the covenants and related definitions contained in the documents governing the various components of the Company’s debt


⁽⁴⁾		Represents the most restrictive that each covenant becomes during its period outstanding

⁽⁵⁾		Interest rate options include a base rate plus a spread. For the Senior Secured Second Lien Facility the LIBOR rate has a floor of 3.25% and the ABR has a floor of 4.25%

⁽⁶⁾		Priority of right to assets is not necessarily the same as priority to receive payments

15. ASSET RETIREMENT OBLIGATIONS

The Company records the fair value of the liability for asset retirement obligations in the period in which it is legally or contractually incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is recognized as expense through depletion or depreciation 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 estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted fair value to its estimated settlement value.

The following table provides a reconciliation of the changes in the estimated asset retirement obligation from January 1, 2007 through December 31, 2008.


	As of December 31,
	2008			2007
	(In thousands)
Beginning asset retirement obligations	$	24,510		$	25,206
Additional liability incurred		8,231			5,239
Change in estimates		4,288			2,385
Accretion expense		1,483			1,509
Sale of properties		—			(11,564	)
Asset retirement costs incurred		(359	)		(180	)
Loss on settlement of liability		119			4
Currency translation adjustment		(3,079	)		1,911

Ending asset retirement obligations		35,193			24,510
Less current portion		(440	)		(646	)

Long—term asset retirement obligation	$	34,753		$	23,864

16. INCOME TAXES

In 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 recognizes this tax as an income tax. The Company has recorded a deferred tax provision of $1.9 million and $2.5 million for the Texas margin tax in 2008 and 2007, and a current state income tax provision for the Texas margin tax in 2007 of $1.0 million.

Tax rate reductions were enacted during 2007 by the Canadian federal government and by Alberta Province. The Company’s Canadian deferred income tax balances were revalued to reflect the changes in these tax rates. The Company recorded $4.9 million of income tax benefits in 2007 as a result of the enactment of Canadian rate reductions. No further rate changes occurred in 2008.

The Company’s current and deferred tax positions have been significantly impacted by the November 2007 divestiture of the Northeast Operations and the resulting gain, the impairment of U.S. oil and gas properties in 2008 and the impairment of its investment in BBEP in 2008. Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2008 and 2007 are as follows:


	As of December 31,
	2008		2007
	(In thousands)
Current
Deferred tax asset
Deferred tax benefit on derivative contract loss	$	—	$	17,258
Deferred tax benefit on cash flow hedge losses		—		1,688

Total current deferred tax assets	$	—	$	18,946

Deferred tax liabilities
Deferred tax liability on cash flow hedge gains	$	52,393	$	—

Non—current
Deferred tax assets
Deferred tax benefit on BBEP impairment	$	112,135	$	—
Deferred tax benefit on derivative contract loss		—		4,973
Deferred tax benefit on deferred compensation expense		4,236		1,506
Deferred tax benefit on cash flow hedge losses		—		617
Net operating loss carry forwards		176,957		—
Other		969		2,336

Total deferred tax assets		294,297		9,432

Deferred tax liabilities
Property, plant and equipment		470,925		375,427
Deferred tax liability on cash flow hedge gains		40,461		—
Deferred tax liability on convertible debenture interest		17,296		16,814
Other		—		581

Total deferred tax liabilities		528,682		392,822

Net deferred tax liabilities	$	234,385	$	383,390

The components of income tax expense for 2008, 2007 and 2006 are as follows:


	2008			2007		2006
	(In thousands)
Current state income tax expense (benefit)	$	(4	)	$	1,143	$	11
Current U.S. federal income tax expense		(45,210	)		45,394		—
Current Canadian income tax expense		199			28		262

Total current income tax expense (benefit)		(45,015	)		46,565		273

Deferred state income tax expense		1,939			2,538		1,600
Deferred U.S. federal income tax expense (benefit)		(190,938	)		194,129		25,502
Deferred Canadian income tax expense		22,559			11,129		8,776

Total deferred income tax expense (benefit)		(166,440	)		207,796		35,878

Total income tax expense (benefit)	$	(211,455	)	$	254,361	$	36,151

The following table reconciles the statutory federal income tax rate to the effective tax rate for 2008, 2007 and 2006:


	2008			2007			2006
U.S. federal statutory tax rate		35.00	%		35.00	%		35.00	%
Permanent differences		(0.33	%)		0.01	%		0.16	%
State income taxes net of federal deduction		(0.22	%)		0.33	%		0.83	%
FIN 48 recognition		(0.09	%)		1.18	%		0.00	%
Foreign income taxes		1.38	%		(1.71	)%		(6.57	%)
Other		0.40	%		0.00	%		(0.79	%)

Effective income tax rate		36.14	%		34.81	%		28.63	%

The Company incurred a $641 million net operating tax loss in 2008. Approximately $137 million of this loss will be carried back to 2007. The remaining $504 million is included in deferred tax assets at December 31, 2008. The net operating loss will expire in 2028. The net operating loss was not reduced by a valuation allowance, because management believed that future taxable income would more likely than not be sufficient to utilize substantially all of its operating loss tax carry forwards prior to their expiration.

During 2007, the Company recognized $2.8 million in income tax benefits associated with the exercise of employee stock options as an increase to additional paid in capital. No such income tax benefits were recognized in 2008 because of the availability of net operating loss tax carry forwards to the Company.

The Company adopted FIN 48 on January 1, 2007. In connection with the adoption the Company recorded an adjustment to retained earnings of approximately $0.3 million for unrecognized tax benefits, all of which would affect our effective tax rate if recognized. The Company also reported unrecognized tax benefits for research and experimental development credits for Canadian taxes in the first quarter of 2007 of $1.1 million. The following schedule reconciles the total amounts of unrecognized tax benefits for 2008 and 2007.


	As of December 31,
	2008			2007
	(In thousands)
Beginning unrecognized tax benefits	$	9,997		$	345
Gross amounts of increases in unrecognized tax benefits as a result of tax positions taken during a prior period		834			1,396
Amount of decreases in unrecognized tax benefits related to settlements with taxing authorities		(1,301	)		(1,100	)
Gross amounts of increases in unrecognized tax benefits as a result of tax positions taken during the current year		—			9,356
Reductions resulting from the lapse of applicable statutes of limitations		(275	)		—

Unrecognized tax benefits	$	9,255		$	9,997

Approximately $8.9 million of these unrecognized tax benefits at December 31, 2008, if recognized, would impact the effective tax rate. Interest and penalties of $0.6 million related to unrecognized tax benefits were recognized as interest expense for 2007 and subsequently reversed in 2008. The Company remains subject to examination by the Internal Revenue Service (“IRS”) for the years 2001 through 2007 except for 2004. An audit was completed by the IRS for 2004 and the statute of limitations has now expired for this year. The Company does not expect that the total amounts of unrecognized tax benefits will significantly increase or decrease.

17. COMMITMENTS AND CONTINGENCIES

Contractual Obligations.

Information regarding our contractual and scheduled interest obligations, at December 31, 2008, is set forth in the following table.


	Transportation		Drilling Rig		Operating		Purchase
	Contracts⁽¹⁾		Contracts⁽²⁾		Leases⁽³⁾		Obligations⁽⁴⁾
	(In thousands)
2009	$	8,768	$	45,620	$	3,612	$	13,800
2010		21,087		19,689		2,122		—
2011		33,406		6,241		1,263		—
2012		45,747		—		478		—
2013		47,473		—		9		—
Thereafter		242,535		—		—		—

Total	$	399,016	$	71,550	$	7,484	$	13,800


⁽¹⁾		Under contracts with various pipeline companies, the Company is obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. The production committed to the pipelines is expected to meet, or exceed, the daily volumes required under the contracts.

⁽²⁾		The Company leases drilling rigs from third parties for use in our development and exploration programs. The outstanding drilling rig contracts require payment of a specified day rate ranging from $20,000 to $23,200 for the entire lease term regardless of our utilization of the drilling rigs.


⁽³⁾		The Company leases office buildings and other property under operating leases. Our operating lease obligations include $0.6 million of future lease payments to a company that is owned by members of the Darden family. Rent expense for operating leases with terms exceeding one month was $5.0 million in 2008, $5.2 million in 2007 and $3.5 million in 2006.

⁽⁴⁾		At December 31, 2008, KGS was under contract to purchase goods and services for completion of the Corvette Plant and for compressors. Total remaining cash obligations for these goods and services were $13.8 million, including $1.2 million recognized during 2008. KGS placed the Corvette Plant into service during the first quarter of 2009.

Commitments

The Company had commitments outstanding of approximately $3.4 million to purchase components for our drilling program as of December 31, 2008. In addition, the Company had approximately $3.0 million in letters of credit outstanding against the credit facility and approximately $41.3 million in surety bonds issued to fulfill contractual, legal or regulatory requirements. All surety bonds and letters of credit have an annual renewal option.

Contingencies

On November 7, 2001, the Company filed a lawsuit against CMS Marketing Services and Trading Company (“CMS”) in Texas. The suit alleged that CMS committed fraud when it entered into a 10-year contract with the Company on March 1, 1999 for the purchase and sale of 10,000 MMBtud of natural gas at a minimum price of $2.47 per MMBtu and breached the contract afterward by failing to comply with a provision of the contract requiring that, if the gas could be scheduled or delivered to derive additional value, the parties would share equally in the additional revenue. On May 15, 2007, the district court entered a final judgment in favor of the Company against CMS (“CMS”), declaring the Company’s contract with CMS to be void and rescinded as of that date. CMS appealed this judgment. The Company also appealed seeking to have the contract voided from its inception and seeking to recover jury-awarded punitive damages of $10 million. Pending final judgment by the appellate court, CMS and the Company agreed to a settlement based upon the decision to be rendered by the appellate court. The settlement agreement specifies that CMS will pay the Company all costs paid by it for all bonds posted on appeal and the Company shall have no obligation under its contract with CMS if the appellate decision affirms the original district court decision. If the appellate court voids the contract from its inception, CMS shall pay the Company $5 million plus all costs paid by the Company for all bonds posted on appeal. If the appellate court reverses the district court judgment, the Company will pay $5 million to CMS. If the appellate court finds that the Company is entitled to punitive damages, CMS will pay the Company $5 million. If the appellate court remands the matter back to the lower courts for any action other than for punitive damages, the parties agreed to forego further adjudication of the matter without payment.

On October 13, 2006, the Company filed suit in district court in Texas against Eagle Drilling, LLC and Eagle Domestic Drilling Operations, LLC (together “Eagle”) regarding three contracts for drilling rigs in which the Company alleged that the first rig furnished by Eagle exhibited operating deficiencies and safety defects and that the other rigs failed to conform to specifications set forth in the drilling contracts. On January 19, 2007, Eagle Domestic Drilling Operations, LLC and its parent, Blast Energy Services, Inc. filed for Chapter 11 bankruptcy. The Company’s suit against Eagle in Tarrant County was ultimately transferred to the bankruptcy court in Houston and has been consolidated with the Eagle/Blast bankruptcy, described more fully below. On September 17, 2007, Eagle Drilling, LLC, and Rod and Richard Thornton, sued the Company and its Executive Vice President Operations, in district court in Oklahoma for approximately $29 million in damages and an unspecified amount of punitive damages resulting from the Company’s repudiation of the rig contracts.

In September 2008, the Company entered into a settlement agreement with Eagle Domestic Drilling Operations, LLC and its parent, Blast Energy Services, Inc. (“Eagle/Blast”) that was approved in October by the district court in Texas. Under the settlement agreement, the Company agreed to pay Eagle/Blast $10 million over a three-year period, including $5 million on the settlement date. The Company recorded a $9.6 million charge to general and administrative expense during the quarter ended September 30, 2008 for the net present value of these payments. The other cases involving Eagle and its affiliates were not directly affected by this settlement. Based upon information currently available, the Company believes that the final resolution of this matter will not have a material effect on its financial condition, results of operations, or cash flows.

On October 31, 2008, the Company filed a lawsuit in district court in Texas against BBEP, BreitBurn GP, LLC, BreitBurn Operating L.P., Provident Energy Trust and certain individuals who serve as, or have previously served as, directors and/or officers of these entities (collectively, the “Defendants”). The Company alleges that, among other things, one or more of the Defendants breached the agreement pursuant to which the Company acquired its ownership interest in BBEP, and violated the Texas Securities Act and the Texas Business & Commerce Code, committed common law fraud, fraudulent inducement, negligent misrepresentation and civil conspiracy. The Company has requested, among other things, relief for actual and exemplary damages, and for injunctive and declaratory relief.

18. NONCONTROLLING INTERESTS

As a result of the KGS IPO, the outside ownership of KGS increased, however the Company continues to own 100% of KGS’ general partner and, therefore, continues to consolidate KGS into the Company’s financial statements. However, by virtue of the elevated outside ownership, the carrying value of the Company’s noncontrolling interests is much larger than years prior to KGS’ IPO.

19. EMPLOYEE BENEFITS

Quicksilver has a 401(k) retirement plan available to all U.S. full time employees who are at least 21 years of age. The Company makes matching contributions and a fixed annual contribution and has the ability to make discretionary contributions to the plan. Expenses associated with company contributions were $2.4 million, $1.6 million and $1.4 million for 2008, 2007 and 2006, respectively.

The Company has a retirement plan available to all Canadian employees. The plan provides for a match of employees’ contributions by the Company and a fixed annual contribution. Expenses associated with company contributions were $0.8 million, $0.7 million and $0.5 million for the 2008, 2007 and 2006, respectively.

The Company maintains a self-funded health benefit plan that covers all eligible U.S. employees. The plan has been reinsured on an individual claim and total group claim basis. Quicksilver is responsible for payment of the first $75,000 for each individual claim and also purchased aggregate level reinsurance for payment of claims up to $1 million over the estimated maximum claim liability. For 2008, 2007 and 2006 the Company recognized expenses of $4.4 million, $3.2 million and $2.5 million, respectively, for this plan.

20. STOCKHOLDERS’ EQUITY

Common Stock, Preferred Stock and Treasury Stock

The Company is authorized to issue 400 million shares of common stock with a par value per share of one cent and 10 million shares of preferred stock with a par value per share of one cent. At December 31, 2008, the Company had 167,169,904 shares of common stock outstanding.

The following table shows common share and treasury share activity since January 1, 2006:


	Common		Treasury
	Shares Issued		Shares Held
Opening balance at January 1, 2006		154,729,151		2,571,069
Stock options exercised		2,212,190		—
Restricted stock activity		842,174		8,602

Balance at December 31, 2006		157,783,515		2,579,671
Stock options exercised		2,257,840		—
Restricted stock activity		591,915		37,055

Balance at December 31, 2007		160,633,270		2,616,726
Stock issuance		10,400,468		—
Stock repurchase		—		1,885,600
Stock options exercised		249,732		—
Restricted stock activity		459,229		70,469

Balance at December 31, 2008		171,742,699		4,572,795

Stockholder Rights Plan

In 2003, the Company’s Board of Directors declared a dividend distribution of one preferred share purchase right for each outstanding share of common stock then outstanding. 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 $90, after adjustments to reflect the two-for-one stock split in January 2008.

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 30% of the Company’s common stock at December 31, 2008.

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

In 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. Under the 1999 Plan, 7.8 million shares of common stock could be issued via 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 7.2 million shares were reserved for issuance pursuant to the 1999 Plan. As of December 31, 2008, a total of 219,321 shares and 193,842 options to purchase shares granted under the 1999 plan remain unvested.

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 1.5 million shares reserved under the 2004 Plan, which permits issuance of non-qualified options and restricted stock awards to Quicksilver’s non-employee directors.

Under terms of the 1999 Plan and 2004 Plan, equity awards to officers, employees and non-employee directors reflect an exercise price of not less than the fair market value on the date of grant. Incentive stock options and non-qualified options’ lives may not exceed ten years from date of grant. Although shares were still available for issuance under the 1999 and 2004 Plans, in approving the 2006 Equity Plan, the Company agreed to make no further issuances under these plans.

2006 Equity Plan

In 2006, the Board of Directors and the shareholders approved the Company’s 2006 Equity Plan. Upon approval of the 2006 Equity Plan, 14 million shares of common stock were reserved for issuance as grants of stock options, appreciation rights, restricted shares, restricted stock units, performances shares, performance units and senior executive plan bonuses. Executive officers, other employees, consultants and non-employee directors of the Company are eligible to participate in the 2006 Equity Plan. Under the 2006 Equity Plan, options reflect an exercise price of not less than the fair market value on the date of grant and have a life of 10 years. At December 31, 2008, 12,176,203 shares (including 107,482 shares surrendered to the Company to satisfy participants’ tax withholding obligations which then became available for future issuance under the 2006 Equity Plan) of common stock were available for issuance under the 2006 Equity Plan.

Stock Options Under All Plans

The following summarizes the values from and assumptions for the Black-Scholes option pricing model:


	2008			2007		2006
Wtd avg grant date fair value	$	13.67			N/A	$	12.50
Wtd avg grant date		Jan 2, 2008			N/A		Jan 3, 2006
Wtd avg risk-free interest rate		3.41	%		N/A		4.35	%
Expected life (in years)		6.0			N/A		10.0
Wtd avg volatility		40.2	%		N/A		37.3	%
Expected dividends		—			N/A		—

The following table summarizes the Company’s stock option activity for 2008:


				Wtd Avg		Wtd Avg
				Exercise		Remaining		Aggregate
	Shares			Price		Contractual Life		Intrinsic Value
								(In thousands)
Outstanding at January 1, 2008		1,021,912		$	7.48
Granted		373,382			30.95
Exercised		(249,732	)		4.98
Cancelled		(42,226	)		28.20

Outstanding at December 31, 2008		1,103,336		$	14.20		3.7	$	39

Exercisable at December 31, 2008		572,710		$	7.29		1.6	$	26

The Company estimates that a total of 1,086,497 stock options will become vested including those options already exercisable. These options have a weighted average exercise price of $13.94 and a weighted average remaining contractual life of 3.7 years.

Compensation expense related to stock options of $1.6 million and $0.1 million was recognized for 2008 and 2007, respectively. Cash received from the exercise of stock options totaled $1.2 million, $21.4 million and $19.7 million for the years 2008, 2007 and 2006, respectively. The total intrinsic value of options exercised during 2008, 2007 and 2006, was $6.7 million, $30.5 million and $26.9 million, respectively.

Restricted Stock Under All Plans

The following table summarizes the Company’s restricted stock and stock unit activity for 2008:


				Wtd Avg
				Grant Date
	Shares			Fair Value
Outstanding at January 1, 2008		1,340,122		$	18.76
Granted		628,196			30.67
Vested		(484,428	)		30.94
Cancelled		(147,779	)		22.82

Outstanding at December 31, 2008		1,336,111		$	24.01

At December 31, 2007, the Company had unvested compensation cost of $15.2 million. During 2008, $13.5 million of compensation expense was recognized for restricted stock and stock units. As of December 31, 2008, the unrecognized compensation cost related to outstanding unvested restricted stock was $17.6 million, which is expected to be recognized in expense over the next twelve months. For 2007 and 2006, compensation expense of $11.0 million and $5.8 million, respectively, was recognized.

The total fair value of shares vested during 2008, 2007 and 2006 was $15.1 million, $6.4 million and $2.1 million, respectively.

KGS Restricted Phantom Units

Awards of phantom units have been granted under KGS’ 2007 Equity Plan, which permits the issuance of up to 750,000 units. The following table summarizes information regarding the phantom unit activity:


	Payable in cash					Payable in units
	Units			Wtd average grant date fair value		Units			Wtd average grant date fair value
Outstanding at January 1, 2008		84,961		$	21.36		9,833		$	21.36
Granted		6,605			24.12		137,148			25.25
Vested		(28,247	)		21.43		(6,089	)		21.36
Cancelled		(3,000	)		21.36		(974	)		25.25

Outstanding at December 31, 2008		60,319		$	21.63		139,918		$	25.15

At January 1, 2008, KGS had total unvested compensation cost of $1.9 million related to unvested phantom units. KGS recognized compensation expense of approximately $1.4 million during 2008, including $0.4 million for remeasuring awards to be settled in cash to their revised fair value. Grants of phantom units during the year ended December 31, 2008 had an estimated grant date fair value of $3.6 million. KGS has unearned compensation of $2.3 million which will be recognized in expense over the next 1.9 years. Phantom units that vested during the year ended December 31, 2008 had a fair value of $0.7 million.

21. ANNUAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Restated)

The following information reflects corrections to amounts previously reported. The previously reported information contained errors, most notably that certain combining adjustments for non-guarantor subsidiaries were reported as consolidating adjustments and certain earnings of consolidated non-guarantors were not appropriately reflected in their guarantor owners’ consolidated financial information. The following table illustrates the effects of the errors and the adoption of new accounting pronouncements as discussed in Note 2, on previously reported annual condensed consolidating financial information. These errors had no effect on the consolidated amounts previously reported.


	December 31, 2008
	Quicksilver Resources Inc.						Guarantor Subsidiaries						Non-Guarantor Subsidiaries						Eliminations
	As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously			As			As Revised for
	Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported			Restated			New GAAP
ASSETS																						(In			thousands)
Current assets	$	423,487	$	424,862	$	424,862	$	163	$	163	$	163	$	426,297	$	104,997	$	104,997	$	(456,611	)	$	(136,686	)	$	(136,686	)
Property and equipment		2,756,915		2,756,915		2,756,915		1,774		1,774		1,774		1,039,026		1,039,026		1,039,026		—			—			—
Investment in subsidiaries (equity method)		596,149		434,390		513,706		170,150		—		79,316		—		—		—		(615,796	)		(283,887	)		(442,519	)
Other assets		209,837		208,462		206,099		123,298		123,298		123,298		2,826		2,826		2,826		(176,944	)		(175,569	)		(175,569	)

Total assets	$	3,986,388	$	3,824,629	$	3,901,582	$	295,385	$	125,235	$	204,551	$	1,468,149	$	1,146,849	$	1,146,849	$	(1,249,351	)	$	(596,142	)	$	(754,774	)


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	518,836	$	357,077	$	357,077	$	122,677	$	122,677	$	122,677	$	233,597	$	75,431	$	75,431	$	(456,611	)	$	(136,686	)	$	(136,686	)
Long-term liabilities		2,372,843		2,372,843		2,359,679		—		—		—		682,281		680,906		684,036		(176,944	)		(175,569	)		(175,569	)
Deferred gain		—		—		—		—		—		—		29,867		79,316		—		—			—			—
Minority interest		—		—		—		—		—		—		79,316		29,867		—		—			—			—
Stockholders’ equity – Quicksilver		1,094,709		1,094,709		1,184,826		172,708		2,558		81,874		443,088		281,329		360,645		(615,796	)		(283,887	)		(442,519	)
Noncontrolling interests		—		—		—		—		—		—		—		—		26,737		—			—			—

Total liabilities and stockholders’ equity	$	3,986,388	$	3,824,629	$	3,901,582	$	295,385	$	125,235	$	204,551	$	1,468,149	$	1,146,849	$	1,146,849	$	(1,249,351	)	$	(596,142	)	$	(754,774	)


	December 31, 2007
	Quicksilver Resources Inc.						Guarantor Subsidiaries						Non-Guarantor Subsidiaries						Eliminations
	As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously			As			As Revised for
	Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported			Restated			New GAAP
	(In thousands)
ASSETS
Current assets	$	213,288	$	214,388	$	214,388	$	596	$	596	$	596	$	243,086	$	59,854	$	59,854	$	(266,569	)	$	(84,437	)	$	(84,437	)
Property and equipment		1,294,573		1,294,573		1,294,573		1,858		1,858		1,858		845,915		845,915		845,915		—			—			—
Investment in subsidiaries (equity method)		819,119		657,007		736,323		160,825		1,171		80,487		—		—		—		(559,773	)		(238,007	)		(396,639	)
Other assets		72,426		71,326		69,231		82,251		82,251		82,251		2,171		2,171		2,171		(133,920	)		(132,820	)		(132,820	)

Total assets	$	2,399,406	$	2,237,294	$	2,314,515	$	245,530	$	85,876	$	165,192	$	1,091,172	$	907,940	$	907,940	$	(960,262	)	$	(455,264	)	$	(613,896	)


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	470,690	$	308,578	$	308,578	$	77,529	$	77,529	$	77,529	$	76,925	$	56,905	$	56,905	$	(266,569	)	$	(84,437	)	$	(84,437	)
Long-term liabilities		860,361		860,361		843,183		—		—		—		512,821		511,721		512,345		(133,920	)		(132,820	)		(132,820	)
Deferred gain		—		—		—		—		—		—		79,316		79,316		—		—			—			—
Minority interest		—		—		—		—		—		—		30,338		30,338		—		—			—			—
Stockholders’ equity – Quicksilver		1,068,355		1,068,355		1,162,754		168,001		8,347		87,663		391,772		229,660		308,976		(559,773	)		(238,007	)		(396,639	)
Noncontrolling interests		—		—		—		—		—		—		—		—		29,714		—			—			—

Total liabilities and stockholders’ equity	$	2,399,406	$	2,237,294	$	2,314,515	$	245,530	$	85,876	$	165,192	$	1,091,172	$	907,940	$	907,940	$	(960,262	)	$	(455,264	)	$	(613,896	)


	For the Year Ended December 31, 2008
	Quicksilver Resources Inc.									Guarantor Subsidiaries								Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously		As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported		Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
	(In thousands)
Revenues	$	600,906		$	600,906		$	600,906		$	514	$	514		$	514		$	261,616		$	265,184		$	265,184		$	(62,395	)	$	(65,963	)	$	(65,963	)
Operating expenses		976,984			976,984			976,984			11,157		11,157			11,157			124,592			128,160			128,160			(62,395	)		(65,963	)		(65,963	)
Equity in net earnings of subsidiaries		81,948			74,331			74,331			21,762		21,762			21,762			—			—			—			(103,710	)		(96,093	)		(96,093	)

Operating income (loss)		(294,130	)		(301,747	)		(301,747	)		11,119		11,119			11,119			137,024			137,024			137,024			(103,710	)		(96,093	)		(96,093	)
Income from earnings of BBEP		93,298			93,298			93,298			—		—			—			—			—			—			—			—			—
Impairment of investment in BBEP		(320,387	)		(320,387	)		(320,387	)		—		—			—			—			—			—			—			—			—
Interest expense and other		(83,069	)		(83,069	)		(89,657	)		6,023		6,023			6,023			(29,311	)		(29,311	)		(24,657	)		—			—			—
Income tax (expense) benefit		230,294			237,911			240,217			1,617		(6,000	)		(6,000	)		(22,762	)		(22,762	)		(22,762	)		—			—			—

Net income (loss)		(373,994	)		(373,994	)		(378,276	)		18,759		11,142			11,142			84,951			84,951			89,605			(103,710	)		(96,093	)		(96,093	)
Net income attributable to noncontrolling interests		—			—			—			—		—			—			—			—			(4,654	)		—			—			—

Net income (loss) attributable to Quicksilver	$	(373,994	)	$	(373,994	)	$	(378,276	)	$	18,759	$	11,142		$	11,142		$	84,951		$	84,951		$	84,951		$	(103,710	)	$	(96,093	)	$	(96,093	)


	For the Year Ended December 31, 2007
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
	(In thousands)

Revenues	$	367,894		$	367,894		$	367,894		$	—		$	—		$	—		$	223,281		$	223,095		$	223,095		$	(29,917	)	$	(29,731	)	$	(29,731	)
Operating expenses		241,174			241,174			241,174			601			601			601			111,664			111,478			111,478			(29,917	)		(29,731	)		(29,731	)
Income from equity affiliates		14			14			14			—			—			—			647			647			647			—			—			—
Gain on sale of properties		628,709			628,709			628,709			—			—			—			—			—			—			—			—			—
Loss on natural gas supply contracts		(63,525	)		(63,525	)		(63,525	)		—			—			—			—			—			—			—			—			—
Equity in net earnings of subsidiaries		76,060			73,468			73,468			7,407			7,407			7,407			—			—			—			(83,467	)		(80,875	)		(80,875	)

Operating income		767,978			765,386			765,386			6,806			6,806			6,806			112,264			112,264			112,264			(83,467	)		(80,875	)		(80,875	)
Interest expense and other		(50,077	)		(50,077	)		(56,212	)		2,418			2,418			2,609			(20,036	)		(20,036	)		(19,172	)		—			—			—
Income tax expense		(238,523	)		(235,931	)		(233,784	)		(636	)		(3,228	)		(3,228	)		(17,349	)		(17,349	)		(17,349	)		—			—			—

Net income		479,378			479,378			475,390			8,588			5,996			6,187			74,879			74,879			75,743			(83,467	)		(80,875	)		(80,875	)
Net income attributable to noncontrolling interests		—			—			—			—			—			(191	)		—			—			(864	)	��	—			—			—

Net income attributable to Quicksilver	$	479,378		$	479,378		$	475,390		$	8,588		$	5,996		$	5,996		$	74,879		$	74,879		$	74,879		$	(83,467	)	$	(80,875	)	$	(80,875	)


	For the Year Ended December 31, 2006
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
	(In thousands)
Revenues	$	233,757		$	233,757		$	233,757		$	3,046		$	3,046		$	3,046		$	157,491		$	167,244		$	167,244		$	(3,932	)	$	(13,685	)	$	(13,685	)
Operating expenses		148,613			148,613			148,613			2,635			2,635			2,635			69,376			79,129			79,129			(3,932	)		(13,685	)		(13,685	)
Income from equity affiliates		17			17			17			—			—			—			509			509			509			—			—			—
Equity in net earnings of subsidiaries		58,543			57,992			57,992			—			1,574			1,574			—			—			—			(58,543	)		(59,566	)		(59,566	)

Operating income		143,704			143,153			143,153			411			1,985			1,985			88,624			88,624			88,624			(58,543	)		(59,566	)		(59,566	)
Interest expense and other		(29,766	)		(29,766	)		(35,478	)		—			—			91			(12,561	)		(12,561	)		(12,561	)		—			—			—
Income tax expense		(20,219	)		(19,668	)		(17,669	)		(144	)		(695	)		(695	)		(17,787	)		(17,787	)		(17,787	)		—			—			—

Net income		93,719			93,719			90,006			267			1,290			1,381			58,276			58,276			58,276			(58,543	)		(59,566	)		(59,566	)
Net income attributable to noncontrolling interests		—			—			—			—			—			(91	)		—			—			—			—			—			—

Net income attributable to Quicksilver	$	93,719		$	93,719		$	90,006		$	267		$	1,290		$	1,290		$	58,276		$	58,276		$	58,276		$	(58,543	)	$	(59,566	)	$	(59,566	)


	For the Year Ended December 31, 2008
	Quicksilver Resources Inc.									Guarantor Subsidiaries							Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As		As Revised for		As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated		New GAAP		Reported			Restated			New GAAP			Reported			Restated			New GAAP
	(In thousands)
Cash flow provided by operations	$	211,519		$	290,160		$	290,160		$	9,684		$	—	$	—	$	235,363		$	189,688		$	189,688		$	—		$	(23,282	)	$	(23,282	)
Cash flow provided by (used for) investing activities		(1,875,307	)		(1,952,156	)		(1,952,156	)		50,596			—		—		(370,311	)		(283,518	)		(283,518	)		(83,566	)		(42,914	)		(42,914	)
Cash flow provided by financing activities		1,638,387			1,637,556			1,637,556			(60,280	)		—		—		135,080			93,001			93,001			83,566			66,196			66,196
Effect of exchange rates on cash		68			(893	)		(893	)		—			—		—		(177	)		784			784			—			—			—

Net decrease in cash & equivalents		(25,333	)		(25,333	)		(25,333	)		—			—		—		(45	)		(45	)		(45	)		—			—			—
Cash and equivalents at beginning of period		27,010			27,012			27,012			—			—		—		1,216			1,214			1,214			—			—			—

Cash and equivalents at end of period	$	1,677		$	1,679		$	1,679		$	—		$	—	$	—	$	1,171		$	1,169		$	1,169		$	—		$	—		$	—


	For the Year Ended December 31, 2007
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
	(In thousands)
Cash flow provided by (used for) operations	$	146,348		$	190,777		$	190,777		$	(354	)	$	(596	)	$	(596	)	$	173,110		$	131,884		$	131,884		$	—		$	(2,961	)	$	(2,961	)
Cash flow used for investing activities		(18,471	)		(355	)		(355	)		47,047			(267	)		(267	)		(283,940	)		(225,433	)		(225,433	)		(14,388	)		(43,697	)		(43,697	)
Cash flow provided by (used for) financing activities		(101,541	)		(163,939	)		(163,939	)		(46,693	)		863			863			101,570			84,142			84,142			14,388			46,658			46,658
Effect of exchange rates on cash		591			446			446			—			—			—			5,278			5,423			5,423			—			—			—

Net increase (decrease) in cash & equivalents		26,927			26,929			26,929			—			—			—			(3,982	)		(3,984	)		(3,984	)		—			—			—
Cash and equivalents at beginning of period		83			83			83			—			—			—			5,198			5,198			5,198			—			—			—

Cash and equivalents at end of period	$	27,010		$	27,012		$	27,012		$	—		$	—		$	—		$	1,216		$	1,214		$	1,214		$	—		$	—		$	—


	For the Year Ended December 31, 2006
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
	(In thousands)
Cash flow provided by (used for) operations	$	207,097		$	152,793		$	152,793		$	(45,073	)	$	(434	)	$	(434	)	$	80,162		$	89,827		$	89,827		$	—		$	—		$	—
Cash flow used for investing activities		(523,750	)		(469,451	)		(469,451	)		(81,534	)		—			—			(257,016	)		(210,429	)		(210,429	)		250,275			67,855			67,855
Cash flow provided by financing activities		307,746			307,746			307,746			126,607			434			434			177,233			120,986			120,986			(250,275	)		(67,855	)		(67,855	)
Effect of exchange rates on cash		—			5			5			—			—			—			(509	)		(514	)		(514	)		—			—			—

Net decrease in cash & equivalents		(8,907	)		(8,907	)		(8,907	)		—			—			—			(130	)		(130	)		(130	)		—			—			—
Cash and equivalents at beginning of period		8,990			8,990			8,990			—			—			—			5,328			5,328			5,328			—			—			—

Cash and equivalents at end of period	$	83		$	83		$	83		$	—		$	—		$	—		$	5,198		$	5,198		$	5,198		$	—		$	—		$	—

The following tables provide information about the entities that guarantee Quicksilver’s Senior Notes and Quicksilver’s Senior Subordinated Notes. The guarantees are full and unconditional and joint and several. Under SEC rules, the Company is required to present financial information segregated between its guarantor and non-guarantor subsidiaries. The indentures under both the Company’s Senior Notes and the Company’s Senior Subordinated Notes distinguish between “restricted” subsidiaries and “unrestricted” subsidiaries and further specify supplemental information that is not required under GAAP. Prior to August 2007, there was no unrestricted subsidiary that required provision of supplemental information in that none had both $10 million or more of net assets and assets that exceeded its liabilities by more than 5% of the amount by which the consolidated assets of the Company and its subsidiaries exceeded consolidated liabilities of the Company and its subsidiaries. The following table illustrates the Company’s subsidiaries and their status pursuant to the Senior Notes and the Senior Subordinated Notes:


Guarantor Subsidiaries -	Non-Guarantor Subsidiaries
Restricted	Restricted	Unrestricted
Cowtown Pipeline Funding, Inc.	Quicksilver Resources Canada, Inc.	Quicksilver Gas Services Holdings LLC
Cowtown Pipeline Management, Inc.	Mercury Michigan, Inc.⁽¹⁾	Quicksilver Gas Services GP LLC
Cowtown Pipeline L.P.	Terra Energy Ltd.⁽¹⁾	Quicksilver Gas Services LP
Cowtown Gas Processing L.P.	GTG Pipeline Corporation⁽¹⁾	Quicksilver Gas Services Operating LLC ⁽²⁾
	Terra Pipeline Company⁽¹⁾	Quicksilver Gas Services Operating GP LLC ⁽²⁾
	Beaver Creek Pipeline, LLC⁽¹⁾	Cowtown Pipeline Partners L.P. ⁽²⁾
	Quicksilver Resources Horn River Inc.	Cowtown Gas Processing Partners L.P. ⁽²⁾
	Cowtown Drilling Inc.


⁽¹⁾		Prior to the sale of the Northeast Operations in November 2007, these entities were restricted guarantor subsidiaries. After the sale, they have been reclassified to restricted non-guarantor subsidiaries for all periods presented.

⁽²⁾		Each entity is a wholly owned subsidiary of and consolidated into Quicksilver Gas Services LP.

Quicksilver owns 100% of each of the restricted subsidiaries. Quicksilver and the restricted subsidiaries conduct all of the Company’s exploration and production activities, and the unrestricted subsidiaries only conduct midstream operations. Neither the restricted non-guarantor subsidiaries nor the unrestricted non-guarantor subsidiaries guarantee the obligations under the Senior Notes and the Senior Subordinated Notes. However, the restricted non-guarantor subsidiaries, like the restricted guarantor subsidiaries, are limited in their activity by the covenants in the indenture for such matters as:

	•		incurring additional indebtedness;
	•		paying dividends;
	•		making investments; and
	•		making restricted payments.

Subject to restrictions set forth in the indentures, the Company may in the future designate one or more additional subsidiaries as unrestricted.

The following tables present financial information about the Company and its restricted subsidiaries for the annual periods covered by the consolidated financial statements, and Note 27, as supplemented, contains comparable information on an interim basis.


	December 31, 2008
			Restricted		Restricted		Restricted			Quicksilver		Unrestricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			and Restricted		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	424,862	$	163	$	102,384	$	(123,071	)	$	404,338	$	2,613	$	(13,615	)	$	393,336
Property and equipment		2,756,915		1,774		550,906		—			3,309,595		488,120		—			3,797,715
Investment in subsidiaries (equity method)		513,706		79,316		—		(363,203	)		229,819		—		(79,316	)		150,503
Other assets		206,099		123,298		910		—			330,307		1,916		(175,569	)		156,654

Total assets	$	3,901,582	$	204,551	$	654,200	$	(486,274	)	$	4,274,059	$	492,649	$	(268,500	)	$	4,498,208


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	357,077	$	122,677	$	44,907	$	(123,071	)	$	401,590	$	30,524	$	(13,615	)	$	418,499
Long-term liabilities		2,359,679		—		327,964		—			2,687,643		356,072		(175,569	)		2,868,146
Stockholders’ equity-Quicksilver		1,184,826		81,874		281,329		(363,203	)		1,184,826		79,316		(79,316	)		1,184,826
Noncontrolling interests		—		—		—		—			—		26,737		—			26,737

Total liabilities and stockholders’ equity	$	3,901,582	$	204,551	$	654,200	$	(486,274	)	$	4,274,059	$	492,649	$	(268,500	)	$	4,498,208


	December 31, 2007
			Restricted		Restricted		Restricted			Quicksilver		Unrestricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			and Restricted		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	214,388	$	596	$	57,952	$	(77,923	)	$	195,013	$	1,902	$	(6,514	)	$	190,401
Property and equipment		1,294,573		1,858		571,967		—			1,868,398		273,948		—			2,142,346
Investment in subsidiaries (equity method)		736,323		80,487		—		(316,152	)		500,658		—		(80,487	)		420,171
Other assets		69,231		82,251		1,205		—			152,687		966		(132,820	)		20,833

Total assets	$	2,314,515	$	165,192	$	631,124	$	(394,075	)	$	2,716,756	$	276,816	$	(219,821	)	$	2,773,751


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	308,578	$	77,529	$	31,075	$	(77,923	)	$	339,259	$	25,830	$	(6,514	)	$	358,575
Long-term liabilities		843,183		—		371,560		—			1,214,743		140,785		(132,820	)		1,222,708
Stockholders’ equity-Quicksilver		1,162,754		87,663		228,489		(316,152	)		1,162,754		80,487		(80,487	)		1,162,754
Noncontrolling interests		—		—		—		—			—		29,714		—			29,714

Total liabilities and stockholders’ equity	$	2,314,515	$	165,192	$	631,124	$	(394,075	)	$	2,716,756	$	276,816	$	(219,821	)	$	2,773,751


	For the Year Ended December 31, 2008
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	600,906		$	514		$	187,126		$	(426	)	$	788,120		$	78,058		$	(65,537	)	$	800,641
Operating expenses		976,984			11,157			86,937			(426	)		1,074,652			41,223			(65,537	)		1,050,338
Equity in net earnings of subsidiaries		74,331			21,762			—			(74,331	)		21,762			—			(21,762	)		—

Operating income (loss)		(301,747	)		11,119			100,189			(74,331	)		(264,770	)		36,835			(21,762	)		(249,697	)
Income from earnings of BBEP		93,298			—			—			—			93,298			—			—			93,298
Impairment of investment in BBEP		(320,387	)		—			—			—			(320,387	)		—			—			(320,387	)
Interest expense and other		(89,657	)		6,023			(14,491	)		—			(98,125	)		(10,166	)		—			(108,291	)
Income tax (expense) benefit		240,217			(6,000	)		(22,509	)		—			211,708			(253	)		—			211,455

Net income (loss)		(378,276	)		11,142			63,189			(74,331	)		(378,276	)		26,416			(21,762	)		(373,622	)
Net income attributable to noncontrolling interests		—			—			—			—			—			(4,654	)		—			(4,654	)

Net income (loss) attributable to Quicksilver	$	(378,276	)	$	11,142		$	63,189		$	(74,331	)	$	(378,276	)	$	21,762		$	(21,762	)	$	(378,276	)


	For the Year Ended December 31, 2007
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	367,894		$	—		$	187,154		$	(160	)	$	554,888		$	35,941		$	(29,571	)	$	561,258
Operating expenses		241,174			601			88,517			(160	)		330,132			22,961			(29,571	)		323,522
Income from equity affiliates		14			—			647			—			661			—			—			661
Gain on sale of properties		628,709			—			—			—			628,709			—			—			628,709
Loss on natural gas supply contracts		(63,525	)		—			—			—			(63,525	)		—			—			(63,525	)
Equity in net earnings of subsidiaries		73,468			7,407			—			(73,468	)		7,407			—			(7,407	)		—

Operating income		765,386			6,806			99,284			(73,468	)		798,008			12,980			(7,407	)		803,581
Interest expense and other		(56,212	)		2,609			(14,776	)		—			(68,379	)		(4,396	)		—			(72,775	)
Income tax expense		(233,784	)		(3,228	)		(17,036	)		—			(254,048	)		(313	)		—			(254,361	)

Net income		475,390			6,187			67,472			(73,468	)		475,581			8,271			(7,407	)		476,445
Net income attributable to noncontrolling interests		—			(191	)		—			—			(191	)		(864	)		—			(1,055	)

Net income attributable to Quicksilver	$	475,390		$	5,996		$	67,472		$	(73,468	)	$	475,390		$	7,407		$	(7,407	)	$	475,390


	For the Year Ended December 31, 2006
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	233,757		$	3,046		$	156,372		$	(3,932	)	$	389,243		$	10,872		$	(9,753	)	$	390,362
Operating expenses		148,613			2,635			69,921			(3,932	)		217,237			9,208			(9,753	)		216,692
Income from equity affiliates		17			—			509			—			526			—			—			526
Equity in net earnings of subsidiaries		57,992			1,574			—			(57,992	)		1,574			—			(1,574	)		—

Operating income		143,153			1,985			86,960			(57,992	)		174,106			1,664			(1,574	)		174,196
Interest expense and other		(35,478	)		91			(12,574	)		—			(47,961	)		13			—			(47,948	)
Income tax expense		(17,669	)		(695	)		(17,684	)		—			(36,048	)		(103	)		—			(36,151	)

Net income		90,006			1,381			56,702			(57,992	)		90,097			1,574			(1,574	)		90,097
Net income attributable to noncontrolling interests		—			(91	)		—			—			(91	)		—			—			(91	)

Net income attributable to Quicksilver	$	90,006		$	1,290		$	56,702		$	(57,992	)	$	90,006		$	1,574		$	(1,574	)	$	90,006


	For the Year Ended December 31, 2008
				Restricted		Restricted			Restricted		Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor		Non-Guarantor			Subsidiary		and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries		Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by operations	$	290,160		$	—	$	137,005		$	—	$	427,165		$	52,683		$	(23,282	)	$	456,566
Purchases of property, plant and equipment		(1,995,791	)		—		(136,057	)		—		(2,131,848	)		(148,079	)		—			(2,279,927	)
Proceeds from sale of equipment to subsidiaries		42,914			—		—			—		42,914			—			(42,914	)		—
Proceeds from sales of properties and equipment		721			—		618			—		1,339			—			—			1,339

Cash flow provided by (used for) investing activities		(1,952,156	)		—		(135,439	)		—		(2,087,595	)		(148,079	)		(42,914	)		(2,278,588	)

Issuance of debt		2,570,611			—		208,161			—		2,778,772			169,900			—			2,948,672
Repayments of debt		(886,429	)		—		(209,734	)		—		(1,096,163	)		—			—			(1,096,163	)
Debt issuance costs		(24,733	)		—		—			—		(24,733	)		(486	)		—			(25,219	)
Repayments to parent		—			—		—			—		—			(42,914	)		42,914			—
Distributions to parent		—			—		—			—		—			(23,282	)		23,282			—
Distributions to noncontrolling interests		—			—		—			—		—			(8,644	)		—			(8,644	)
Proceeds from exercise of stock options		1,244			—		—			—		1,244			—			—			1,244
Purchase of treasury stock		(23,137	)		—		—			—		(23,137	)		—			—			(23,137	)

Cash flow provided by (used for) financing activities		1,637,556			—		(1,573	)		—		1,635,983			94,574			66,196			1,796,753
Effect of exchange rates on cash		(893	)		—		784			—		(109	)		—			—			(109	)

Net increase (decrease) in cash & equivalents		(25,333	)		—		777			—		(24,556	)		(822	)		—			(25,378	)
Cash and equivalents at beginning of period		27,012			—		89			—		27,101			1,125			—			28,226

Cash and equivalents at end of period	$	1,679		$	—	$	866		$	—	$	2,545		$	303		$	—		$	2,848


	For the Year Ended December 31, 2007
				Restricted			Restricted			Restricted		Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by (used for) operations	$	190,777		$	(596	)	$	116,935		$	—	$	307,116		$	14,949		$	(2,961	)	$	319,104
Purchases of property, plant and equipment		(824,321	)		(267	)		(151,807	)		—		(976,395	)		(73,797	)		29,508			(1,020,684	)
Investment in subsidiaries and affiliates		(38,908	)		—			—			—		(38,908	)		—			38,908			—
Return of investment from subsidiaries and affiliates		121,577			—			171			—		121,748			—			(112,113	)		9,635
Proceeds from sales of properties and equipment		741,297			—			—			—		741,297			—			—			741,297

Cash flow provided by (used for) investing activities		(355	)		(267	)		(151,636	)		—		(152,258	)		(73,797	)		(43,697	)		(269,752	)

Issuance of debt		594,500			—			218,321			—		812,821			5,000			—			817,821
Repayments of debt		(777,866	)		—			(190,691	)		—		(968,557	)		��			—			(968,557	)
Debt issuance costs		(3,148	)		—			(664	)		—		(3,812	)		(1,318	)		—			(5,130	)
Proceeds from sale of KGS units, net		—			—			—			—		—			109,642			—			109,642
Contributions from parent		—			863			—			—		863			67,553			(68,416	)		—
Contributions from noncontrolling interests		—			—			—			—		—			167			—			167
Distributions to parent		—			—			—			—		—			(115,074	)		115,074			—
Distributions to noncontrolling interests		—			—			—			—		—			(8,794	)		—			(8,794	)
Proceeds from exercise of stock options		21,387			—			—			—		21,387			—			—			21,387
Excess tax benefits on exercise of stock operations		2,755			—			—			—		2,755			—			—			2,755
Purchase of treasury stock		(1,567	)		—			—			—		(1,567	)		—			—			(1,567	)

Cash flow provided by (used for) financing activities		(163,939	)		863			26,966			—		(136,110	)		57,176			46,658			(32,276	)
Effect of exchange rates on cash		446			—			5,423			—		5,869			—			—			5,869

Net increase (decrease) in cash & equivalents		26,929			—			(2,312	)		—		24,617			(1,672	)		—			22,945
Cash and equivalents at beginning of period		83			—			2,401			—		2,484			2,797			—			5,281

Cash and equivalents at end of period	$	27,012		$	—		$	89		$	—	$	27,101		$	1,125		$	—		$	28,226


	For the Year Ended December 31, 2006
				Restricted			Restricted			Restricted		Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by (used for) operations	$	152,793		$	(434	)	$	83,382		$	—	$	235,741		$	6,445		$	—		$	242,186
Purchases of property, plant and equipment		(403,074	)		—			(137,627	)		—		(540,701	)		(78,360	)		—			(619,061	)
Investment in subsidiaries and affiliates		(67,855	)		—			—			—		(67,855	)		—			67,855			—
Return of investment from subsidiaries and affiliates		143			—			1,780			—		1,923			—			—			1,923
Proceeds from sales of properties and equipment		1,335			—			3,778			—		5,113			—			—			5,113

Cash flow used for investing activities		(469,451	)		—			(132,069	)		—		(601,520	)		(78,360	)		67,855			(612,025	)

Issuance of debt		638,500			—			56,182			—		694,682			—			—			694,682
Repayments of debt		(340,846	)		—			(9,908	)		—		(350,754	)		—			—			(350,754	)
Debt issuance costs		(9,213	)		—			—			—		(9,213	)		—			—			(9,213	)
Contributions from parent		—			434			—			—		434			67,421			(67,855	)		—
Contributions from noncontrolling interests		—			—			—			—		—			7,291			—			7,291
Proceeds from exercise of stock options		19,689			—			—			—		19,689			—			—			19,689
Purchase of treasury stock		(384	)		—			—			—		(384	)		—			—			(384	)

Cash flow provided by financing activities		307,746			434			46,274			—		354,454			74,712			(67,855	)		361,311
Effect of exchange rates on cash		5			—			(514	)		—		(509	)		—			—			(509	)

Net increase (decrease) in cash & equivalents		(8,907	)		—			(2,927	)		—		(11,834	)		2,797			—			(9,037	)
Cash and equivalents at beginning of period		8,990			—			5,328			—		14,318			—			—			14,318

Cash and equivalents at end of period	$	83		$	—		$	2,401		$	—	$	2,484		$	2,797		$	—		$	5,281

22. SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for interest and income taxes is as follows:


	Years Ended December 31,
	2008		2007		2006
	(In thousands)
Interest	$	83,400	$	69,038	$	37,627
Income taxes		49,433		—		3

Other significant non-cash transactions are as follows:


	Years Ended December 31,
	2008		2007		2006
	(In thousands)
Working capital related to capital expenditures	$	230,624	$	159,819	$	118,359
Issuance of common stock as consideration for the Alliance Acquisition		262,092		—		—
Noncash interest in BBEP earnings		—		429,618		—
Tax benefit recognized on employee stock option exercises		—		2,755		—

23. RELATED PARTY TRANSACTIONS

As of December 31, 2008, members of the Darden family and entities controlled by them beneficially owned approximately 30% of the Company’s outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.

Quicksilver paid $1.9 million, $2.1 million and $1.8 million in 2008, 2007 and 2006, respectively, for rent on buildings owned by entities controlled by members of the Darden family. Rental rates were determined based on comparable rates charged by third parties. At December 31, 2008, the Company had future lease obligations of $0.6 million through 2010 to these entities.

During 2008, 2007 and 2006, the Company paid $0.9 million, $0.2 million and $0.4 million for use of an airplane owned by an entity controlled by member of the Darden family. Usage rates were determined based upon comparable rates charged by third parties.

Payments received in 2008, 2007 and 2006 from Mercury for sublease rentals, employee insurance coverage and administrative services were $0.3 million, $0.2 million and $0.1 million, respectively.

In October 2008, the Company paid $19.9 million for the purchase of 1,885,600 share of its common stock from an entity controlled by members of the Darden family.

In October 2008, the Company completed the purchase of its headquarters building in Fort Worth, Texas for $6.4 million, the estimated fair value of the building, from an entity controlled by members of the Darden family. Subsequently, the Company entered into a property management agreement with an affiliate of the seller to which the Company paid $14,000 during the remainder of 2008. Annual lease payments on the purchased building prior to acquisition had been $1.1 million.

In May 2008, the Company signed a settlement agreement with Mercury in which Mercury agreed to make a payment of approximately $0.4 million in connection with issues related to the ownership and operation of certain oil and gas properties acquired from Mercury in 2001, including audit claims received with respect to certain of the acquired properties and the administration of employee benefits.

In 2006, Quicksilver leased over 5,000 acres from a related party entity, “KC7,” in exchange for $0.7 million. Under the terms of the leases, either a 3% overriding royalty interest or a 20% royalty interest was granted to KC7. The lease terms were determined based on comparable prices and terms granted to third parties with respect to similar leases in the area. Aggregate payments to KC7 in 2007 were $0.2 million, respectively. No payments were made to KC7 in 2008.

24. SEGMENT INFORMATION

The Company operates in two geographic segments, the United States and Canada, where it is engaged in the exploration and production segment of the oil and gas industry. Additionally, the Company operates in the U.S. midstream segment, where it provides natural gas processing and gathering services to the oil and gas industry, predominately through KGS. Revenue earned by KGS for the processing and gathering of Quicksilver gas are eliminated on a consolidated basis as are the costs of these services recognized by Quicksilver’s producing properties. The Company evaluates performance based on operating income and property and equipment costs incurred.


	Exploration & Production					Processing &								Quicksilver
	United States			Canada		Gathering		Corporate			Elimination			Consolidated
						(In thousands)
2008
Revenues	$	600,292		$	187,740	$	78,572	$	—		$	(65,963	)	$	800,641
Depletion, depreciation and accretion		127,010			44,948		15,134		1,104			—			188,196
Impairment related to oil and gas properties		624,315			—		9,200		—			—			633,515
Operating income (loss)		(321,756	)		104,131		34,879		(66,951	)		—			(249,697	)
Property, plant and equipment — net		2,723,103			550,413		519,447		4,752			—			3,797,715
Property and equipment costs incurred		2,179,815			138,360		265,222		1,638			—			2,585,035
2007
Revenues	$	396,768		$	158,121	$	35,941	$	—		$	(29,572	)	$	561,258
Depletion, depreciation and accretion		72,132			39,445		8,146		974			—			120,697
Operating income		750,703			85,155		12,380		(44,657	)		—			803,581
Property, plant and equipment — net		1,290,728			571,496		275,807		4,315			—			2,142,346
Property and equipment costs incurred		758,601			115,073		168,523		2,017			—			1,044,214
2006
Revenues	$	272,377		$	116,726	$	13,907	$	—		$	(12,648	)	$	390,362
Depletion, depreciation and accretion		45,810			29,225		2,998		767			—			78,800
Operating income		133,521			63,906		3,173		(26,404	)		—			174,196
Property, plant and equipment — net		1,126,351			417,199		132,457		3,273			—			1,679,280
Property and equipment costs incurred		439,986			118,028		85,848		1,865			—			645,727

25. 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 from Schlumberger Data and Consulting Services and LaRoche Petroleum Consultants, Ltd., respectively. The reserve reports were prepared in accordance with guidelines established by the SEC and utilized existing economic and operating conditions. Natural gas, NGL 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. 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.

As further discussed in Note 2, the Company records its equity earnings from its investment in BBEP in the period in which BBEP makes such information publicly available because the Company does not control BBEP and believes that BBEP is not an “affiliate” (as defined in the SEC rules) of the Company. As a result, the Company’s 2008 consolidated financial statements reflect BBEP’s results of operations from November 1, 2007, when the Company acquired the BBEP units, through September 30, 2008. The disclosures in this note relating to BBEP, however, reflect the Company’s pro rata portion of the supplemental oil and gas information disclosed by BBEP as of and for the period ended December 31, 2008 in their 2008 annual report.

The changes in proved reserves for the three years ended December 31, 2008 were as follows:


	Natural Gas (MMcf)									NGL (MBbl)									Crude Oil (MBbl)
										United									United
	United States			Canada			Total			States			Canada			Total			States			Canada		Total
December 31, 2005		716,043			304,910			1,020,953			9,623			—			9,623			5,915			—		5,915
Revisions		(80,484	)		(32,938	)		(113,422	)		4,593			7			4,600			667			—		667
Extensions and discoveries		332,811			55,006			387,817			34,510			14			34,524			320			—		320
Sales in place		—			(405	)		(405	)		—			—			—			—			—		—
Production		(35,028	)		(18,238	)		(53,266	)		(741	)		(5	)		(746	)		(587	)		—		(587	)

December 31, 2006⁽¹⁾		933,342			308,335			1,241,677			47,985			16			48,001			6,315			—		6,315
Revisions		(30,494	)		17,761			(12,733	)		1,112			(1	)		1,111			633			—		633
Extensions and discoveries		302,098			24,463			326,561			46,571			—			46,571			658			—		658
Sales in place⁽²⁾		(503,651	)		(1,446	)		(505,097	)		(3,147	)		—			(3,147	)		(3,947	)		—		(3,947	)
Production		(38,887	)		(20,732	)		(59,619	)		(2,466	)		(5	)		(2,471	)		(584	)		—		(584	)

December 31, 2007⁽¹⁾		662,408			328,381			990,789			90,055			10			90,065			3,075			—		3,075
Revisions		(171,009	)		4,923			(166,086	)		(25,596	)		—			(25,596	)		(106	)		—		(106	)
Extensions and discoveries		560,205			22,363			582,568			31,662			—			31,662			428			—		428
Purchases in place		299,952			—			299,952			—			—			—			—					—
Sales in place		—			(27	)		(27	)		—			—			—			—			—		—
Production		(45,059	)		(23,069	)		(68,128	)		(4,194	)		(2	)		(4,196	)		(483	)		—		(483	)

December 31, 2008⁽¹⁾		1,306,497			332,571			1,639,068			91,927			8			91,935			2,914			—		2,914

Proved developed reserves December 31, 2006		626,582			217,759			844,341			18,771			16			18,787			5,236			—		5,236
December 31, 2007		379,917			260,029			639,946			50,738			10			50,748			2,763			—		2,763
December 31, 2008		756,191			278,668			1,034,859			56,181			8			56,189			2,509			—		2,509

��


⁽¹⁾		Although the Company did not acquire its initial 32% limited partnership interest in BBEP until 2007, had the Company owned 32% of BBEP at December 31, 2006, proportionate ownership of BBEP would have included 1,341 MMcf of natural gas and 9,613 MBbl of crude oil, all within the United States but none of which is included in the above table. At December 31, 2007, the Company’s 32% ownership of BBEP represented proved oil and gas reserves of 160,880 MMcf of natural gas and 18,505 MBbl of crude oil, all within the United States but none of which is included in the above table. At December 31, 2008, the Company’s 41% ownership of BBEP represented proved oil and gas reserves of 189,176 MMcf of natural gas and 10,509 MBbl of crude oil, all within the United States but none of which is included in the above table.

⁽²⁾		Sales of reserves in place during 2007 relate principally to the BreitBurn Transaction, which is more fully described in Note 5

The carrying value of oil and gas assets as of December 31, 2008, 2007 and 2006 were as follows:


	United States			Canada			Consolidated
	(In thousands)
2008
Proved properties	$	3,068,326		$	553,505		$	3,621,831
Unevaluated properties		462,943			80,590			543,533
Accumulated DD&A		(902,281	)		(120,475	)		(1,022,756	)

Net capitalized costs⁽¹⁾	$	2,628,988		$	513,620		$	3,142,608

2007
Proved properties	$	1,231,109		$	580,186		$	1,811,295
Unevaluated properties		163,274			51,954			215,228
Accumulated DD&A		(157,122	)		(105,001	)		(262,123	)

Net capitalized costs⁽¹⁾	$	1,237,261		$	527,139		$	1,764,400

2006
Proved properties	$	1,163,353		$	397,106		$	1,560,459
Unevaluated properties		157,220			34,445			191,665
Accumulated DD&A		(250,547	)		(57,518	)		(308,065	)

Net capitalized costs⁽¹⁾	$	1,070,026		$	374,033		$	1,444,059


⁽¹⁾		Although the Company did not acquire its initial 32% limited partnership interest in BBEP until 2007, had the Company owned 32% of BBEP at December 31, 2006, proportionate ownership of BBEP would have included $59.3 million of capitalized oil and gas costs, all within the United States but none of which is included in the above table. At December 31, 2007, the Company’s 32% ownership of BBEP represented $593.8 million of capitalized oil and gas costs, all within the United States but none of which is included in the above table. At December 31, 2008, the Company’s 41% ownership of BBEP represented $743.8 million of capitalized oil and gas costs, all within the United States but none of which is included in the above table.

Capital expenditures for exploration and development activities during each of the three years ended December 31, 2008, were as follows:


	United States		Canada		Consolidated
	(In thousands)
2008
Proved acreage	$	787,172	$	—	$	787,172
Unproved acreage		484,770		54,048		538,818
Development costs		836,032		68,629		904,661
Exploration costs		30,161		10,280		40,441

Total⁽¹⁾	$	2,138,135	$	132,957	$	2,271,092

2007
Proved acreage	$	—	$	—	$	—
Unproved acreage		17,031		31,448		48,479
Development costs		648,632		67,608		716,240
Exploration costs		75,862		11,953		87,815

Total⁽¹⁾	$	741,525	$	111,009	$	852,534

2006
Proved acreage	$	—	$	—	$	—
Unproved acreage		32,048		1,574		33,622
Development costs		121,104		82,378		203,482
Exploration costs		280,438		27,197		307,635

Total⁽¹⁾	$	433,590	$	111,149	$	544,739


⁽¹⁾		Although the Company did not acquire its initial 32% limited partnership interest in BBEP until 2007, had the Company owned 32% of BBEP at December 31, 2006, proportionate ownership of BBEP would have included $12.2 million of capitalized expenditures for exploration and development, all within the United States but none of which is included in the above table. At December 31, 2007, the Company’s 32% ownership of BBEP represented $551.0 million of costs incurred for exploration and development, all within the United States but none of which is included in the above table. At December 31, 2008, the Company’s 41% ownership of BBEP represented $49.6 million of costs incurred for exploration and development, all within the United States but none of which is included in the above table.

Results of operations from producing activities for the three years ended December 31, 2008, are set forth below:


	United States			Canada		Consolidated
	(In thousands)
2008
Natural gas, NGL and crude oil sales	$	597,889		$	182,899	$	780,788
Oil & gas production expense		113,793			38,662		152,455
Depletion & amortization expense		120,845			40,337		161,182
Impairment related to oil and gas properties		624,315			—		624,315

		(261,064	)		103,900		(157,164	)
Income tax expense (benefit)		(91,372	)		30,131		(61,241	)

Results from producing activities⁽¹⁾	$	(169,692	)	$	73,769	$	(95,923	)

2007
Natural gas, NGL and crude oil sales	$	392,841		$	152,248	$	545,089
Oil & gas production expense		119,452			33,521		152,973
Depletion & amortization expense		65,701			35,330		101,031

		207,688			83,397		291,085
Income tax expense		72,691			24,185		96,876

Results from producing activities⁽¹⁾	$	134,997		$	59,212	$	194,209

2006
Natural gas, NGL and crude oil sales	$	270,535		$	116,005	$	386,540
Oil & gas production expense		87,199			23,596		110,795
Depletion & amortization expense		40,760			26,094		66,854

		142,576			66,315		208,891
Income tax expense		49,902			19,231		69,133

Results from producing activities⁽¹⁾	$	92,674		$	47,084	$	139,758


⁽¹⁾		Although the Company did not acquire its initial 32% limited partnership interest in BBEP until 2007, had the Company owned 32% of BBEP at December 31, 2006, proportionate ownership of BBEP would have included $25.0 million of producing activity results, all within the United States but none of which is included in the above table. For 2007, the Company’s 32% ownership of BBEP represented a loss of $7.8 million for producing activity results including realized and unrealized hedging gains and losses, all within the United States but none of which is included in the above table. At December 31, 2008, the Company’s 41% ownership of BBEP represented income of $214.1 million for producing activity results including realized and unrealized hedging gains and losses, all within the United States but none of which is included in the above table.

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) do 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 prices were used in the Standardized Measure and were adjusted by field for appropriate regional differentials:


	At December 31,
	2008		2007		2006
Natural gas — Henry Hub-Spot	$	5.71	$	6.80	$	5.64
Natural gas — AECO		5.44		6.35		5.39
NGL — Mont Belvieu, Texas		21.65		57.35		40.10
NGL — Kalkaska, Michigan⁽¹⁾		N/A		N/A		37.73
Crude oil — WTI Cushing		44.60		95.98		60.85


⁽¹⁾		All Michigan NGL reserves were sold in 2007 pursuant to the BreitBurn Transaction, which is more fully described in Note 5

Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pretax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pretax 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, 2008, 2007 and 2006 were as follows:


	United States			Canada			Total
	(In thousands)
December 31, 2008
Future revenues	$	8,783,936		$	1,764,268		$	10,548,204
Future production costs		(4,162,737	)		(551,395	)		(4,714,132	)
Future development costs		(1,140,466	)		(113,800	)		(1,254,266	)
Future income taxes		(504,753	)		(215,212	)		(719,965	)

Future net cash flows		2,975,980			883,861			3,859,841
10% discount		(1,623,862	)		(441,717	)		(2,065,579	)

Standardized measure of discounted future cash flows relating to proved reserves⁽¹⁾	$	1,352,118		$	442,144		$	1,794,262

December 31, 2007
Future revenues	$	9,566,791		$	2,037,478		$	11,604,269
Future production costs		(3,286,618	)		(675,890	)		(3,962,508	)
Future development costs		(651,802	)		(156,289	)		(808,091	)
Future income taxes		(1,772,021	)		(228,883	)		(2,000,904	)

Future net cash flows		3,856,350			976,416			4,832,766
10% discount		(2,168,150	)		(495,413	)		(2,663,563	)

Standardized measure of discounted future cash flows relating to proved reserves⁽¹⁾	$	1,688,200		$	481,003		$	2,169,203

December 31, 2006
Future revenues	$	7,388,886		$	1,629,456		$	9,018,342
Future production costs		(2,715,746	)		(550,148	)		(3,265,894	)
Future development costs		(464,997	)		(148,850	)		(613,847	)
Future income taxes		(1,268,907	)		(197,885	)		(1,466,792	)

Future net cash flows		2,939,236			732,573			3,671,809
10% discount		(1,813,746	)		(372,238	)		(2,185,984	)

Standardized measure of discounted future cash flows relating to proved reserves⁽¹⁾	$	1,125,490		$	360,335		$	1,485,825


⁽¹⁾		Although the Company did not acquire its initial 32% limited partnership interest in BBEP until 2007, had the Company owned 32% of BBEP at December 31, 2006, proportionate ownership of BBEP would have included $100.0 million of discounted future cash flows, all within the United States but none of which is included in the above table. For 2007, the Company’s 32% ownership of BBEP represented $609.2 million of discounted future cash flows, all within the United States, but none of which is included in the above table. At December 31, 2008, the Company’s 41% ownership of BBEP represented $240.2 million of discounted future cash flows related to its proved oil and gas reserves, all within the United States but none of which is included in the above table.

The primary changes in the standardized measure of discounted future net cash flows for the three years ended December 31, 2008, were as follows:


	Years Ended December 31,
	2008			2007			2006
	(In thousands)
Sales of oil and gas net of production costs	$	(628,333	)	$	(392,116	)	$	(275,745	)
Net changes in price and production cost		(2,368,940	)		1,048,432			(1,236,793	)
Extensions and discoveries		1,630,418			1,045,296			661,033
Development costs incurred		373,124			170,686			78,063
Changes in estimated future development costs		(413,097	)		(234,649	)		42,015
Purchase and sale of reserves, net		722,662			(1,008,566	)		(1,977	)
Revision of estimates		(618,527	)		(8,090	)		(94,080	)
Accretion of discount		324,064			196,275			260,340
Net change in income taxes		509,854			(293,374	)		302,342
Timing and other differences		93,834			159,484			(73,505	)

Net increase (decrease)	$	(374,941	)	$	683,378		$	(338,307	)

26. SELECTED QUARTERLY DATA (UNAUDITED)


	Quarter Ended
	March 31		June 30		September 30			December 31
	(In thousands, except per share data)
2008⁽¹⁾
Operating revenues	$	157,617	$	197,900	$	236,263		$	208,861
Operating income		70,723		107,103		119,990			(547,513	)
Net income (loss)		41,642		52,323		(2,629	)		(464,958	)
Net income (loss) attributable to Quicksilver		41,134		51,335		(3,754	)		(466,991	)
Basic net earnings (loss) per share	$	0.26	$	0.32	$	(0.02	)	$	(2.79	)
Diluted net earnings (loss) per share		0.25		0.31		(0.02	)		(2.79	)
2007⁽²⁾
Operating revenues	$	116,580	$	136,398	$	159,199		$	149,081
Operating income		48,560		62,078		63,574			629,472
Net income		21,944		30,871		28,170			395,460
Net income attributable to Quicksilver		21,881		30,743		27,713			395,053
Basic net earnings per share	$	0.14	$	0.20	$	0.18		$	2.51
Diluted net earnings per share		0.14		0.19		0.17			2.35


⁽¹⁾		Operating loss for the fourth quarter of 2008 includes a charge of $633.5 million for the impairment related to the Company’s U.S. oil and gas properties. Net loss for the fourth quarter of 2008 also includes $93.3 million for pretax income attributable to the Company’s proportionate ownership of BBEP and a pretax charge of $320.4 million for impairment of the related investment, respectively.

⁽²⁾		Operating income and net income for the fourth quarter of 2007 includes a gain of $628.6 million recognized from the divestiture of the Company’s Northeast Operations and a charge of $63.5 million for the remaining contract period of the Michigan Sales Contract.

27. INTERIM CONDENSED CONSOLIDATING FINANCIAL INFORMATION (UNAUDITED)

The following information reflects corrections to the interim information previously presented. The previously reported information contained errors, most notably that certain combining adjustments for non-guarantor subsidiaries were reported as consolidating adjustments and certain earnings of consolidated non-guarantors were not appropriately reflected in their guarantor owners’ financial condition and results of operation. These errors had no effect on the consolidated amounts previously reported.


	September 30, 2008
	Quicksilver Resources Inc.						Guarantor Subsidiaries						Non-Guarantor Subsidiaries						Eliminations
	As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously			As			As Revised for
	Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported			Restated			New GAAP
	(In thousands)
ASSETS
Current assets	$	312,186	$	313,286	$	313,286	$	—	$	—	$	—	$	336,875	$	86,853	$	86,853	$	(394,000	)	$	(145,078	)	$	(145,078	)
Property and equipment		3,177,418		3,177,418		3,177,418		10,977		10,977		10,977		1,041,897		1,041,897		1,041,897		—			—			—
Investment in subsidiaries (equity method)		741,170		582,708		662,024		166,853		—		79,316		—		—		—		(613,151	)		(287,836	)		(446,468	)
Other assets		152,040		150,940		148,648		151,864		151,864		151,864		5,080		5,080		5,080		(204,869	)		(203,769	)		(203,769	)

Total assets	$	4,382,814	$	4,224,352	$	4,301,376	$	329,694	$	162,841	$	242,157	$	1,383,852	$	1,133,830	$	1,133,830	$	(1,212,020	)	$	(636,683	)	$	(795,315	)


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	413,613	$	255,151	$	255,151	$	152,390	$	152,390	$	152,390	$	161,161	$	70,701	$	70,701	$	(394,000	)	$	(145,078	)	$	(145,078	)
Long-term liabilities		2,468,412		2,468,412		2,454,219		—		—		—		678,746		677,646		679,681		(204,869	)		(203,769	)		(203,769	)
Deferred gain		—		—		—		—		—		—		79,316		79,316		—		—			—			—
Minority interest		—		—		—		—		—		—		28,782		28,782		—		—			—			—
Stockholders’ equity-Quicksilver		1,500,789		1,500,789		1,592,006		177,304		10,451		89,767		435,847		277,385		356,701		(613,151	)		(287,836	)		(446,468	)
Noncontrolling interests		—		—		—		—		—		—		—		—		26,747		—			—			—

Total liabilities and stockholders’ equity	$	4,382,814	$	4,224,352	$	4,301,376	$	329,694	$	162,841	$	242,157	$	1,383,852	$	1,133,830	$	1,133,830	$	(1,212,020	)	$	(636,683	)	$	(795,315	)


	June 30, 2008
	Quicksilver Resources Inc.						Guarantor Subsidiaries						Non-Guarantor Subsidiaries						Eliminations
	As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously			As			As Revised for
	Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported			Restated			New GAAP
	(In thousands)
ASSETS
Current assets	$	416,922	$	418,022	$	418,022	$	—	$	—	$	—	$	301,450	$	79,661	$	79,661	$	(443,750	)	$	(223,061	)	$	(223,061	)
Property and equipment		1,699,550		1,699,550		1,699,550		10,981		10,981		10,981		992,115		992,115		992,115		—			—			—
Investment in subsidiaries (equity method)		744,722		585,309		664,625		167,796		—		79,316		—		—		—		(516,731	)		(189,522	)		(348,154	)
Other assets		90,642		89,542		87,317		131,911		131,911		131,911		2,198		2,198		2,198		(184,519	)		(183,419	)		(183,419	)

Total assets	$	2,951,836	$	2,792,423	$	2,869,514	$	310,688	$	142,892	$	222,208	$	1,295,763	$	1,073,974	$	1,073,974	$	(1,145,000	)	$	(596,002	)	$	(754,634	)


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	608,806	$	449,393	$	449,393	$	133,800	$	133,800	$	133,800	$	250,439	$	189,163	$	189,163	$	(443,750	)	$	(223,061	)	$	(223,061	)
Long-term liabilities		1,419,402		1,419,402		1,404,197		—		—		—		597,067		595,967		597,396		(184,519	)		(183,419	)		(183,419	)
Deferred gain		—		—		—		—		—		—		79,316		79,316		—		—			—			—
Minority interest		—		—		—		—		—		—		29,098		29,098		—		—			—			—
Stockholders’ equity-Quicksilver		923,628		923,628		1,015,924		176,888		9,092		88,408		339,843		180,430		259,746		(516,731	)		(189,522	)		(348,154	)
Noncontrolling interests		—		—		—		—		—		—		—		—		27,669		—			—			—

Total liabilities and stockholders’ equity	$	2,951,836	$	2,792,423	$	2,869,514	$	310,688	$	142,892	$	222,208	$	1,295,763	$	1,073,974	$	1,073,974	$	(1,145,000	)	$	(596,002	)	$	(754,634	)


	March 31, 2008
	Quicksilver Resources Inc.						Guarantor Subsidiaries						Non-Guarantor Subsidiaries						Eliminations
	As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously			As			As Revised for
	Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported			Restated			New GAAP
	(In thousands)
ASSETS
Current assets	$	311,609	$	312,709	$	312,709	$	—	$	—	$	—	$	270,544	$	62,152	$	62,152	$	(345,146	)	$	(137,854	)	$	(137,854	)
Property and equipment		1,481,585		1,481,585		1,481,585		10,953		10,953		10,953		938,226		938,226		938,226		—			—			—
Investment in subsidiaries (equity method)		790,711		630,357		709,673		168,747		—		79,316		—		—		—		(542,727	)		(213,626	)		(372,258	)
Other assets		75,301		74,201		72,042		110,743		110,743		110,743		2,329		2,329		2,329		(162,934	)		(161,834	)		(161,834	)

Total assets	$	2,659,206	$	2,498,852	$	2,576,009	$	290,443	$	121,696	$	201,012	$	1,211,099	$	1,002,707	$	1,002,707	$	(1,050,807	)	$	(513,314	)	$	(671,946	)


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	503,880	$	343,526	$	343,526	$	113,585	$	113,585	$	113,585	$	138,451	$	91,513	$	91,513	$	(345,146	)	$	(137,854	)	$	(137,854	)
Long-term liabilities		1,129,052		1,129,052		1,112,852		—		—		—		598,051		596,951		597,848		(162,934	)		(161,834	)		(161,834	)
Deferred gain		—		—		—		—		—		—		79,316		79,316		—		—			—			—
Minority interest		—		—		—		—		—		—		29,412		29,412		—		—			—			—
Stockholders’ equity-Quicksilver		1,026,274		1,026,274		1,119,631		176,858		8,111		87,427		365,869		205,515		284,831		(542,727	)		(213,626	)		(372,258	)
Noncontrolling interests		—		—		—		—		—		—		—		—		28,515		—			—			—

Total liabilities and stockholders’ equity	$	2,659,206	$	2,498,852	$	2,576,009	$	290,443	$	121,696	$	201,012	$	1,211,099	$	1,002,707	$	1,002,707	$	(1,050,807	)	$	(513,314	)	$	(671,946	)


	September 30, 2007
	Quicksilver Resources Inc.						Guarantor Subsidiaries						Non-Guarantor Subsidiaries						Eliminations
	As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously		As		As Revised for		As Previously			As			As Revised for
	Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported		Restated		New GAAP		Reported			Restated			New GAAP
	(In thousands)
ASSETS
Current assets	$	4,589	$	5,414	$	5,414	$	596	$	596	$	596	$	503,821	$	338,438	$	338,438	$	(354,251	)	$	(189,693	)	$	(189,693	)
Property and equipment		1,544,145		1,544,145		1,544,145		1,879		1,879		1,879		841,827		841,827		841,827		—			—			—
Investment in subsidiaries (equity method)		622,217		461,049		542,662		157,527		—		81,613		8,058		4,543		4,543		(780,641	)		(458,431	)		(621,657	)
Other assets		70,727		69,902		67,869		64,457		64,457		64,457		2,109		2,109		2,109		(115,084	)		(114,259	)		(114,259	)

Total assets	$	2,241,678	$	2,080,510	$	2,160,090	$	224,459	$	66,932	$	148,545	$	1,355,815	$	1,186,917	$	1,186,917	$	(1,249,976	)	$	(762,383	)	$	(925,609	)


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	366,089	$	204,921	$	204,921	$	60,909	$	60,909	$	60,909	$	160,684	$	157,294	$	157,294	$	(354,251	)	$	(189,693	)	$	(189,693	)
Long-term liabilities		1,200,193		1,200,193		1,182,054		—		—		—		549,245		466,807		466,974		(115,084	)		(114,259	)		(114,259	)
Deferred gain		—		—		—		—		—		—		—		81,613		—		—			—			—
Minority interest		—		—		—		—		—		—		28,795		28,795		—		—			—			—
Stockholders’ equity-Quicksilver		675,396		675,396		773,115		163,550		6,023		87,636		617,091		452,408		534,021		(780,641	)		(458,431	)		(621,657	)
Noncontrolling interests		—		—		—		—		—		—		—		—		28,628		—			—			—

Total liabilities and stockholders’ equity	$	2,241,678	$	2,080,510	$	2,160,090	$	224,459	$	66,932	$	148,545	$	1,355,815	$	1,186,917	$	1,186,917	$	(1,249,976	)	$	(762,383	)	$	(925,609	)


	June 30, 2007
	Quicksilver Resources Inc.						Guarantor Subsidiaries								Non-Guarantor Subsidiaries						Eliminations
	As Previously		As		As Revised for		As Previously			As			As Revised for		As Previously		As		As Revised for		As Previously			As			As Revised for
	Reported		Restated		New GAAP		Reported			Restated			New GAAP		Reported		Restated		New GAAP		Reported			Restated			New GAAP
	(In thousands)
ASSETS
Current assets	$	158,611	$	158,611	$	158,611	$	46		$	46		$	46	$	355,686	$	355,686	$	355,686	$	(385,950	)	$	(385,950	)	$	(385,950	)
Property and equipment		1,343,598		1,343,598		1,343,598		1,900			1,901			1,901		753,557		753,556		753,556		—			—			—
Investment in subsidiaries (equity method)		600,553		600,553		600,553		170,296			174,371			174,371		8,020		4,503		4,503		(771,536	)		(772,094	)		(772,094	)
Other assets		21,481		21,481		19,508		38,279			38,279			38,279		1,353		1,353		1,353		(38,279	)		(38,279	)		(38,279	)

Total assets	$	2,124,243	$	2,124,243	$	2,122,270	$	210,521		$	214,597		$	214,597	$	1,118,616	$	1,115,098	$	1,115,098	$	(1,195,765	)	$	(1,196,323	)	$	(1,196,323	)


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	394,332	$	394,332	$	394,332	$	35,969		$	35,969		$	35,969	$	143,450	$	143,450	$	143,450	$	(385,950	)	$	(385,950	)	$	(385,950	)
Long-term liabilities		1,100,455		1,100,455		1,081,369		(120	)		(120	)		32		370,410		370,410		370,410		(38,279	)		(38,279	)		(38,279	)
Minority interest		—		—		—		7,892			7,892			—		—		—		—		—			—			—
Stockholders’ equity-Quicksilver		629,456		629,456		646,569		166,780			170,856			170,856		604,756		601,238		601,238		(771,536	)		(772,094	)		(772,094	)
Noncontrolling interests		—		—		—		—			—			7,740		—		—		—		—			—			—

Total liabilities and stockholders’ equity	$	2,124,243	$	2,124,243	$	2,122,270	$	210,521		$	214,597		$	214,597	$	1,118,616	$	1,115,098	$	1,115,098	$	(1,195,765	)	$	(1,196,323	)	$	(1,196,323	)


	March 31, 2007
	Quicksilver Resources Inc.						Guarantor Subsidiaries								Non-Guarantor Subsidiaries						Eliminations
	As Previously		As		As Revised for		As Previously			As			As Revised for		As Previously		As		As Revised for		As Previously			As			As Revised for
	Reported		Restated		New GAAP		Reported			Restated			New GAAP		Reported		Restated		New GAAP		Reported			Restated			New GAAP
	(In thousands)
ASSETS
Current assets	$	134,809	$	134,809	$	134,809	$	2,297		$	2,297		$	2,297	$	319,115	$	319,115	$	319,115	$	(338,675	)	$	(338,675	)	$	(338,675	)
Property and equipment		1,163,917		1,163,917		1,163,917		950			950			950		678,778		678,778		678,778		—			—			—
Investment in subsidiaries (equity method)		537,680		537,680		537,680		149,248			150,529			150,529		7,955		4,438		4,438		(687,487	)		(685,251	)		(685,251	)
Other assets		21,598		21,598		19,683		—			—			—		2,248		2,248		2,248		—			—			—

Total assets	$	1,858,004	$	1,858,004	$	1,856,089	$	152,495		$	153,776		$	153,776	$	1,008,096	$	1,004,579	$	1,004,579	$	(1,026,162	)	$	(1,023,926	)	$	(1,023,926	)


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	368,360	$	368,360	$	368,360	$	17		$	17		$	17	$	139,032	$	139,032	$	139,032	$	(338,675	)	$	(338,675	)	$	(338,675	)
Long-term liabilities		929,656		929,656		909,640		(50	)		(50	)		1		326,411		326,411		326,411		—			—			—
Minority interest		—		—		—		7,694			7,694			—		—		—		—		—			—			—
Stockholders’ equity-Quicksilver		559,988		559,988		578,089		144,834			146,115			146,115		542,653		539,136		539,136		(687,487	)		(685,251	)		(685,251	)
Noncontrolling interests		—		—		—		—			—			7,643		—		—		—		—			—			—

Total liabilities and stockholders’ equity	$	1,858,004	$	1,858,004	$	1,856,089	$	152,495		$	153,776		$	153,776	$	1,008,096	$	1,004,579	$	1,004,579	$	(1,026,162	)	$	(1,023,926	)	$	(1,023,926	)


	For the Three Months Ended September 30, 2008
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
	(In thousands)
Revenues	$	171,634		$	171,639		$	171,639		$	—		$	—		$	—		$	81,037		$	80,571		$	80,571		$	(16,409	)	$	(15,947	)	$	(15,947	)
Operating expenses		100,636			100,488			100,488			376			376			376			31,669			31,356			31,356			(16,409	)		(15,947	)		(15,947	)
Equity in net earnings of subsidiaries		31,846			29,851			29,851			5,263			5,263			5,263			—			—			—			(37,109	)		(35,114	)		(35,114	)

Operating income		102,844			101,002			101,002			4,887			4,887			4,887			49,368			49,215			49,215			(37,109	)		(35,114	)		(35,114	)
Income from earnings of BBEP		(89,814	)		(89,814	)		(89,814	)		—			—			—			—			—			—			—			—			—
Interest expense and other		(30,287	)		(30,287	)		(31,948	)		1,736			1,736			1,736			(9,014	)		(9,014	)		(7,889	)		—			—			—
Income tax (expense) benefit		14,582			16,424			17,006			(476	)		(2,318	)		(2,318	)		(9,392	)		(9,392	)		(9,392	)		—			—			—

Net income (loss)		(2,675	)		(2,675	)		(3,754	)		6,147			4,305			4,305			30,962			30,809			31,934			(37,109	)		(35,114	)		(35,114	)
Net income attributable to noncontrolling interests		—			—			—			—			—			—			—			—			(1,125	)		—			—			—

Net income (loss) attributable to Quicksilver	$	(2,675	)	$	(2,675	)	$	(3,754	)	$	6,147		$	4,305		$	4,305		$	30,962		$	30,809		$	30,809		$	(37,109	)	$	(35,114	)	$	(35,114	)


	For the Three Months Ended June 30, 2008
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
	(In thousands)
Revenues	$	148,991		$	148,984		$	148,984		$	—		$	—		$	—		$	63,515		$	63,708		$	63,708		$	(14,491	)	$	(14,792	)	$	(14,792	)
Operating expenses		72,681			72,827			72,827			514			514			514			32,094			32,248			32,248			(14,491	)		(14,792	)		(14,792	)
Equity in net earnings of subsidiaries		20,018			18,555			18,555			4,619			4,618			4,618			—			—			—			(24,637	)		(23,173	)		(23,173	)

Operating income		96,328			94,712			94,712			4,105			4,104			4,104			31,421			31,460			31,460			(24,637	)		(23,173	)		(23,173	)
Income from earnings of BBEP		(10,269	)		(10,269	)		(10,269	)		—			—			—			—			—			—			—			—			—
Interest expense and other		(9,972	)		(9,972	)		(11,604	)		1,494			1,494			1,494			(7,518	)		(7,404	)		(6,416	)		—			—			—
Income tax expense		(23,691	)		(22,075	)		(21,504	)		(343	)		(1,959	)		(1,959	)		(4,522	)		(4,522	)		(4,522	)		—			—			—

Net income		52,396			52,396			51,335			5,256			3,639			3,639			19,381			19,534			20,522			(24,637	)		(23,173	)		(23,173	)
Net income attributable to noncontrolling interests		—			—			—			—			—			—			—			—			(988	)		—			—			—


Net income attributable to Quicksilver	$	52,396		$	52,396		$	51,335		$	5,256		$	3,639		$	3,639		$	19,381		$	19,534		$	19,534		$	(24,637	)	$	(23,173	)	$	(23,173	)


	For the Three Months Ended March 31, 2008
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
	(In thousands)
Revenues	$	116,887		$	116,889		$	116,889		$	—		$	—		$	—		$	53,261		$	53,653		$	53,653		$	(12,645	)	$	(12,925	)	$	(12,925	)
Operating expenses		66,957			66,959			66,959			499			499			499			32,083			32,361			32,361			(12,645	)		(12,925	)		(12,925	)
Equity in net earnings of subsidiaries		11,895			11,063			11,063			2,376			2,376			2,376			—			—			—			(14,271	)		(13,439	)		(13,439	)

Operating income		61,825			60,993			60,993			1,877			1,877			1,877			21,178			21,292			21,292			(14,271	)		(13,439	)		(13,439	)
Income from earnings of BBEP		6,219			6,219			6,219			—			—			—			—			—			—			—			—			—
Interest expense and other		(5,446	)		(5,446	)		(7,049	)		1,433			1,433			1,433			(6,727	)		(6,841	)		(6,333	)		—			—			—
Income tax expense		(20,422	)		(19,590	)		(19,029	)		(327	)		(1,159	)		(1,159	)		(3,163	)		(3,163	)		(3,163	)		—			—			—

Net income		42,176			42,176			41,134			2,983			2,151			2,151			11,288			11,288			11,796			(14,271	)		(13,439	)		(13,439	)
Net income attributable to noncontrolling interests		—			—			—			—			—			—			—			—			(508	)		—			—			—

Net income attributable to Quicksilver	$	42,176		$	42,176		$	41,134		$	2,983		$	2,151		$	2,151		$	11,288		$	11,288		$	11,288		$	(14,271	)	$	(13,439	)	$	(13,439	)


	For the Three Months Ended September 30, 2007
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries										Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As				As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated				New GAAP			Reported			Restated			New GAAP
																(In thousands)
Revenues	$	104,237		$	104,237		$	104,237		$	—		$	—		$	—		$	63,307		$	63,237			$	63,237		$	(8,345	)	$	(8,275	)	$	(8,275	)
Operating expenses		73,375			73,375			73,375			(784	)		(784	)		(784	)		31,664			31,594		��		31,594			(8,345	)		(8,275	)		(8,275	)
Equity in net earnings of subsidiaries		18,848			18,201			18,201			552			1,848			1,848			289			289				289			(19,404	)		(20,053	)		(20,053	)

Operating income		49,710			49,063			49,063			1,336			2,632			2,632			31,932			31,932				31,932			(19,404	)		(20,053	)		(20,053	)
Interest expense and other		(15,109	)		(15,109	)		(16,657	)		999			999			999			(6,652	)		(6,652	)			(6,195	)		—			—			—
Income tax expense		(5,882	)		(5,235	)		(4,693	)		(624	)		(1,271	)		(1,271	)		(7,587	)		(7,587	)			(7,587	)		—			—			—

Net income		28,719			28,719			27,713			1,711			2,360			2,360			17,693			17,693				18,150			(19,404	)		(20,053	)		(20,053	)
Net income attributable to noncontrolling interests		—			—			—			—			—			—			—			—				(457	)		—			—			—

Net income attributable to Quicksilver	$	28,719		$	28,719		$	27,713		$	1,711		$	2,360		$	2,360		$	17,693		$	17,693			$	17,693		$	(19,404	)	$	(20,053	)	$	(20,053	)


	For the Three Months Ended June 30, 2007
	Quicksilver Resources Inc.									Guarantor Subsidiaries								Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously		As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported		Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
															(In thousands)
Revenues	$	88,948		$	88,948		$	88,948		$	—	$	—		$	—		$	53,961		$	54,047		$	54,047		$	(6,408	)	$	(6,494	)	$	(6,494	)
Operating expenses		54,687			54,687			54,687			680		680			680			25,746			25,832			25,832			(6,408	)		(6,494	)		(6,494	)
Equity in net earnings of subsidiaries		19,453			18,743			18,743			2,794		2,031			2,031			266			266			266			(22,231	)		(20,758	)		(20,758	)

Operating income		53,714			53,004			53,004			2,114		1,351			1,351			28,481			28,481			28,481			(22,231	)		(20,758	)		(20,758	)
Interest expense and other		(13,706	)		(13,706	)		(15,226	)		84		84			212			(3,955	)		(3,955	)		(3,955	)		—			—			—
Income tax (expense) benefit		(8,277	)		(7,567	)		(7,035	)		208		(502	)		(502	)		(4,701	)		(4,701	)		(4,701	)		—			—			—

Net income		31,731			31,731			30,743			2,406		933			1,061			19,825			19,825			19,825			(22,231	)		(20,758	)		(20,758	)
Net income attributable to noncontrolling interests		—			—			—			—		—			(128	)		—			—			—			—			—			—

Net income attributable to Quicksilver	$	31,731		$	31,731		$	30,743		$	2,406	$	933		$	933		$	19,825		$	19,825		$	19,825		$	(22,231	)	$	(20,758	)	$	(20,758	)


	For the Three Months Ended March 31, 2007
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
																(In thousands)
Revenues	$	70,868		$	70,868		$	70,868		$	—		$	—		$	—		$	50,190		$	50,104		$	50,104		$	(4,478	)	$	(4,392	)	$	(4,392	)
Operating expenses		46,461			46,461			46,461			459			459			459			25,693			25,607			25,607			(4,478	)		(4,392	)		(4,392	)
Equity in net earnings of subsidiaries		14,742			14,480			14,480			1,281			748			748			109			109			109			(16,017	)		(15,222	)		(15,222	)

Operating income		39,149			38,887			38,887			822			289			289			24,606			24,606			24,606			(16,017	)		(15,222	)		(15,222	)
Interest expense and other		(11,120	)		(11,120	)		(12,613	)		(63	)		(63	)		—			(3,231	)		(3,231	)		(3,231	)		—			—			—
Income tax expense		(5,178	)		(4,916	)		(4,393	)		183			(79	)		(79	)		(6,300	)		(6,300	)		(6,300	)		—			—			—

Net income		22,851			22,851			21,881			942			147			210			15,075			15,075			15,075			(16,017	)		(15,222	)		(15,222	)
Net income attributable to noncontrolling interests		—			—			—			—			—			(63	)		—			—			—			—			—			—

Net income attributable to Quicksilver	$	22,851		$	22,851		$	21,881		$	942		$	147		$	147		$	15,075		$	15,075		$	15,075		$	(16,017	)	$	(15,222	)	$	(15,222	)


	For the Nine Months Ended September 30, 2008
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
	(In thousands)
Revenues	$	437,512		$	437,512		$	437,512		$	—		$	—		$	—		$	197,813		$	197,932		$	197,932		$	(43,545	)	$	(43,664	)	$	(43,664	)
Operating expenses		240,274			240,274			240,274			1,389			1,389			1,389			95,846			95,965			95,965			(43,545	)		(43,664	)		(43,664	)
Equity in net earnings of subsidiaries		63,759			59,469			59,469			12,258			12,258			12,258			—			—			—			(76,017	)		(71,727	)		(71,727	)

Operating income		260,997			256,707			256,707			10,869			10,869			10,869			101,967			101,967			101,967			(76,017	)		(71,727	)		(71,727	)
Income from earnings of BBEP		(93,864	)		(93,864	)		(93,864	)		—			—			—			—			—			—			—			—			—
Interest expense and other		(45,705	)		(45,705	)		(50,601	)		4,663			4,663			4,663			(23,259	)		(23,259	)		(20,638	)		—			—			—
Income tax expense		(29,531	)		(25,241	)		(23,527	)		(1,146	)		(5,436	)		(5,436	)		(17,077	)		(17,077	)		(17,077	)		—			—			—

Net income		91,897			91,897			88,715			14,386			10,096			10,096			61,631			61,631			64,252			(76,017	)		(71,727	)		(71,727	)
Net income attributable to noncontrolling interests		—			—			—			—			—			—			—			—			(2,621	)		—			—			—

Net income attributable to Quicksilver	$	91,897		$	91,897		$	88,715		$	14,386		$	10,096		$	10,096		$	61,631		$	61,631		$	61,631		$	(76,017	)	$	(71,727	)	$	(71,727	)


	For the Six Months Ended June 30, 2008
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
	(In thousands)
Revenues	$	265,878		$	265,873		$	265,873		$	—		$	—		$	—		$	116,776		$	117,361		$	117,361		$	(27,136	)	$	(27,717	)	$	(27,717	)
Operating expenses		139,638			139,786			139,786			1,013			1,013			1,013			64,177			64,609			64,609			(27,136	)		(27,717	)		(27,717	)
Equity in net earnings of subsidiaries		31,913			29,618			29,618			6,995			6,994			6,994			—			—			—			(38,908	)		(36,612	)		(36,612	)

Operating income		158,153			155,705			155,705			5,982			5,981			5,981			52,599			52,752			52,752			(38,908	)		(36,612	)		(36,612	)
Income from earnings of BBEP		(4,050	)		(4,050	)		(4,050	)		—			—			—			—			—			—			—			—			—
Interest expense and other		(15,418	)		(15,418	)		(18,653	)		2,927			2,927			2,927			(14,245	)		(14,245	)		(12,749	)		—			—			—
Income tax expense		(44,113	)		(41,665	)		(40,533	)		(670	)		(3,118	)		(3,118	)		(7,685	)		(7,685	)		(7,685	)		—			—			—

Net income		94,572			94,572			92,469			8,239			5,790			5,790			30,669			30,822			32,318			(38,908	)		(36,612	)		(36,612	)
Net income attributable to noncontrolling interests		—			—			—			—			—			—			—			—			(1,496	)		—			—			—

Net income attributable to Quicksilver	$	94,572		$	94,572		$	92,469		$	8,239		$	5,790		$	5,790		$	30,669		$	30,822		$	30,822		$	(38,908	)	$	(36,612	)	$	(36,612	)


	For the Nine Months Ended September 30, 2007
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
																(In thousands)
Revenues	$	264,053		$	264,053		$	264,053		$	—		$	—		$	—		$	167,355		$	167,285		$	167,285		$	(19,231	)	$	(19,161	)	$	(19,161	)
Operating expenses		174,523			174,523			174,523			355			355			355			83,103			83,033			83,033			(19,231	)		(19,161	)		(19,161	)
Equity in net earnings of subsidiaries		53,043			51,424			51,424			4,627			4,627			4,627			664			664			664			(57,652	)		(56,033	)		(56,033	)

Operating income		142,573			140,954			140,954			4,272			4,272			4,272			84,916			84,916			84,916			(57,652	)		(56,033	)		(56,033	)
Interest expense and other		(39,935	)		(39,935	)		(44,496	)		1,020			1,020			1,211			(13,735	)		(13,735	)		(13,278	)		—			—			—
Income tax expense		(19,337	)		(17,718	)		(16,121	)		(233	)		(1,852	)		(1,852	)		(18,588	)		(18,588	)		(18,588	)		—			—			—

Net income		83,301			83,301			80,337			5,059			3,440			3,631			52,593			52,593			53,050			(57,652	)		(56,033	)		(56,033	)
Net income attributable to noncontrolling interests		—			—			—			—			—			(191	)		—			—			(457	)		—			—			—

Net income attributable to Quicksilver	$	83,301		$	83,301		$	80,337		$	5,059		$	3,440		$	3,440		$	52,593		$	52,593		$	52,593		$	(57,652	)	$	(56,033	)	$	(56,033	)


	For the Six Months Ended June 30, 2007
	Quicksilver Resources Inc.									Guarantor Subsidiaries								Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously		As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported		Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
															(In thousands)
Revenues	$	159,816		$	159,816		$	159,816		$	—	$	—		$	—		$	104,151		$	104,151		$	104,151		$	(10,886	)	$	(10,886	)	$	(10,886	)
Operating expenses		101,148			101,148			101,148			1,139		1,139			1,139			51,439			51,439			51,439			(10,886	)		(10,886	)		(10,886	)
Equity in net earnings of subsidiaries		34,195			33,223			33,223			4,075		2,779			2,779			375			375			375			(38,248	)		(35,980	)		(35,980	)

Operating income		92,863			91,891			91,891			2,936		1,640			1,640			53,087			53,087			53,087			(38,248	)		(35,980	)		(35,980	)
Interest expense and other		(24,826	)		(24,826	)		(27,839	)		21		21			212			(7,186	)		(7,186	)		(7,186	)		—			—			—
Income tax expense		(13,455	)		(12,483	)		(11,428	)		391		(581	)		(581	)		(11,001	)		(11,001	)		(11,001	)		—			—			—

Net income		54,582			54,582			52,624			3,348		1,080			1,271			34,900			34,900			34,900			(38,248	)		(35,980	)		(35,980	)
Net income attributable to noncontrolling interests		—			—			—			—		—			(191	)		—			—			—			—			—			—

Net income attributable to Quicksilver	$	54,582		$	54,582		$	52,624		$	3,348	$	1,080		$	1,080		$	34,900		$	34,900		$	34,900		$	(38,248	)	$	(35,980	)	$	(35,980	)


	For the Nine Months Ended September 30, 2008
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
																(In thousands)
Cash flow provided by operations	$	53,455		$	138,736		$	138,736		$	9,688		$	2,483		$	2,483		$	210,977		$	149,981		$	149,981		$	—		$	(17,080	)	$	(17,080	)
Cash flow used for investing activities		(1,627,306	)		(1,711,759	)		(1,711,759	)		72,342			(2,483	)		(2,483	)		(289,446	)		(228,453	)		(228,453	)		(99,110	)		(825	)		(825	)
Cash flow provided by financing activities		1,560,117			1,559,289			1,559,289			(82,030	)		—			—			80,051			80,054			80,054			99,110			17,905			17,905
Effect of exchange rates on cash		(155	)		(155	)		(155	)		—			—			—			(2,454	)		(2,454	)		(2,454	)		—			—			—

Net decrease in cash & equivalents		(13,889	)		(13,889	)		(13,889	)		—			—			—			(872	)		(872	)		(872	)		—			—			—
Cash and equivalents at beginning of period		27,010			27,012			27,012			—			—			—			1,216			1,214			1,214			—			—			—

Cash and equivalents at end of period	$	13,121		$	13,123		$	13,123		$	—		$	—		$	—		$	344		$	342		$	342		$	—		$	—		$	—


	For the Six Months Ended June 30, 2008
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
																(In thousands)
Cash flow provided by (used for) operations	$	(79,043	)	$	(14,468	)	$	(14,468	)	$	9,443		$	2,282		$	2,282		$	206,211		$	159,669		$	159,669		$	—		$	(10,872	)	$	(10,872	)
Cash flow used for investing activities		(404,699	)		(468,721	)		(468,721	)		48,163			(2,282	)		(2,282	)		(204,511	)		(157,973	)		(157,973	)		(68,479	)		(550	)		(550	)
Cash flow provided by (used for) financing activities		457,023			456,470			456,470			(57,606	)		—			—			(1,325	)		(1,321	)		(1,321	)		68,479			11,422			11,422
Effect of exchange rates on cash		(70	)		(70	)		(70	)		—			—			—			517			517			517			—			—			—

Net increase (decrease) in cash & equivalents		(26,789	)		(26,789	)		(26,789	)		—			—			—			892			892			892			—			—			—
Cash and equivalents at beginning of period		27,010			27,012			27,012			—			—			—			1,216			1,214			1,214			—			—			—

Cash and equivalents at end of period	$	221		$	223		$	223		$	—		$	—		$	—		$	2,108		$	2,106		$	2,106		$	—		$	—		$	—


	For the Three Months Ended March 31, 2008
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
																(In thousands)
Cash flow provided by (used for) operations	$	(45,590	)	$	(10,412	)	$	(10,412	)	$	9,093		$	1,888		$	1,888		$	79,781		$	57,111		$	57,111		$	—		$	(5,303	)	$	(5,303	)
Cash flow used for investing activities		(231,747	)		(266,647	)		(266,647	)		23,270			(1,888	)		(1,888	)		(132,502	)		(109,833	)		(109,833	)		(37,667	)		(278	)		(278	)
Cash flow provided by financing activities		252,122			251,844			251,844			(32,363	)		—			—			52,160			52,161			52,161			37,667			5,581			5,581
Effect of exchange rates on cash		(58	)		(58	)		(58	)		—			—			—			(416	)		(416	)		(416	)		—			—			—

Net decrease in cash & equivalents		(25,273	)		(25,273	)		(25,273	)		—			—			—			(977	)		(977	)		(977	)		—			—			—
Cash and equivalents at beginning of period		27,010			27,012			27,012			—			—			—			1,216			1,214			1,214			—			—			—

Cash and equivalents at end of period	$	1,737		$	1,739		$	1,739		$	—		$	—		$	—		$	239		$	237		$	237		$	—		$	—		$	—


	For the Nine Months Ended September 30, 2007
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
																(In thousands)
Cash flow provided by operations	$	116,890		$	153,652		$	153,652		$	(496	)	$	280		$	280		$	145,305		$	107,767		$	107,767		$	—		$	—		$	—
Cash flow used for investing activities		(562,188	)		(537,828	)		(537,828	)		29,092			(280	)		(280	)		(191,881	)		(137,213	)		(137,213	)		5,097			(44,559	)		(44,559	)
Cash flow provided by financing activities		446,035			384,915			384,915			(28,596	)		—			—			56,978			39,846			39,846			(5,097	)		44,559			44,559
Effect of exchange rates on cash		588			588			588			—			—			—			2,582			2,582			2,582			—			—			—

Net increase in cash & equivalents		1,325			1,327			1,327			—			—			—			12,984			12,982			12,982			—			—			—
Cash and equivalents at beginning of period		83			83			83			—			—			—			5,198			5,198			5,198			—			—			—

Cash and equivalents at end of period	$	1,408		$	1,410		$	1,410		$	—		$	—		$	—		$	18,182		$	18,180		$	18,180		$	—		$	—		$	—


	For the Six Months Ended June 30, 2007
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
																(In thousands)
Cash flow provided by operations	$	77,788		$	80,928		$	80,928		$	(735	)	$	280		$	280		$	77,495		$	73,340		$	73,340		$	—		$	—		$	—
Cash flow used for investing activities		(370,426	)		(373,564	)		(373,564	)		(45,333	)		(280	)		(280	)		(117,535	)		(107,511	)		(107,511	)		90,956			39,017			39,017
Cash flow provided by financing activities		292,304			292,304			292,304			46,068			—			—			36,467			30,596			30,596			(90,956	)		(39,017	)		(39,017	)
Effect of exchange rates on cash		390			390			390			—			—			—			1,494			1,494			1,494			—			—			—

Net increase (decrease) in cash & equivalents		56			58			58			—			—			—			(2,079	)		(2,081	)		(2,081	)		—			—			—
Cash and equivalents at beginning of period		83			83			83			—			—			—			5,198			5,198			5,198			—			—			—

Cash and equivalents at end of period	$	139		$	141		$	141		$	—		$	—		$	—		$	3,119		$	3,117		$	3,117		$	—		$	—		$	—


	For the Three Months Ended March 31, 2007
	Quicksilver Resources Inc.									Guarantor Subsidiaries									Non-Guarantor Subsidiaries									Eliminations
	As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for			As Previously			As			As Revised for
	Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP			Reported			Restated			New GAAP
																(In thousands)
Cash flow provided by operations	$	42,754		$	40,820		$	40,820		$	(231	)	$	276		$	276		$	30,483		$	31,910		$	31,910		$	—		$	—		$	—
Cash flow used for investing activities		(166,157	)		(164,222	)		(164,222	)		(24,282	)		(276	)		(276	)		(67,639	)		(67,181	)		(67,181	)		48,354			21,955			21,955
Cash flow provided by financing activities		123,755			123,756			123,756			24,513			—			—			37,010			35,123			35,123			(48,354	)		(21,955	)		(21,955	)
Effect of exchange rates on cash		—			—			—			—			—			—			231			231			231			—			—			—

Net increase in cash & equivalents		352			354			354			—			—			—			85			83			83			—			—			—
Cash and equivalents at beginning of period		83			83			83			—			—			—			5,198			5,198			5,198			—			—			—

Cash and equivalents at end of period	$	435		$	437		$	437		$	—		$	—		$	—		$	5,283		$	5,281		$	5,281		$	—		$	—		$	—

See Note 21, as restated, for more information about the Company’s “restricted” and “unrestricted” subsidiaries. The following tables present restated information for the Company and include the financial information about the Company and its restricted subsidiaries for each of the interim periods covered by the consolidated financial statements.


	September 30, 2008
			Restricted		Restricted		Restricted			Quicksilver		Unrestricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			and Restricted		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
							(In thousands)
ASSETS
Current assets	$	313,286	$	—	$	74,908	$	(140,037	)	$	248,157	$	11,945	$	(5,041	)	$	255,061
Property and equipment		3,177,418		10,977		604,015		—			3,792,410		437,882		—			4,230,292
Investment in subsidiaries (equity method)		662,024		79,316		—		(367,152	)		374,188		—		(79,316	)		294,872
Other assets		148,648		151,864		3,996		—			304,508		1,084		(203,769	)		101,823

Total assets	$	4,301,376	$	242,157	$	682,919	$	(507,189	)	$	4,719,263	$	450,911	$	(288,126	)	$	4,882,048


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	255,151	$	152,390	$	37,648	$	(140,037	)	$	305,152	$	33,053	$	(5,041	)	$	333,164
Long-term liabilities		2,454,219		—		367,886		—			2,822,105		311,795		(203,769	)		2,930,131
Stockholders’ equity-Quicksilver		1,592,006		89,767		277,385		(367,152	)		1,592,006		79,316		(79,316	)		1,592,006
Noncontrolling interests		—		—		—		—			—		26,747		—			26,747

Total liabilities and stockholders’ equity	$	4,301,376	$	242,157	$	682,919	$	(507,189	)	$	4,719,263	$	450,911	$	(288,126	)	$	4,882,048


	June 30, 2008
			Restricted		Restricted		Restricted			Quicksilver		Unrestricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			and Restricted		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
							(In thousands)
ASSETS
Current assets	$	418,022	$	—	$	72,999	$	(214,816	)	$	276,205	$	6,662	$	(8,245	)	$	274,622
Property and equipment		1,699,550		10,981		619,482		—			2,330,013		372,633		—			2,702,646
Investment in subsidiaries (equity method)		664,625		79,316		—		(268,838	)		475,103		—		(79,316	)		395,787
Other assets		87,317		131,911		1,058		—			220,286		1,140		(183,419	)		38,007

Total assets	$	2,869,514	$	222,208	$	693,539	$	(483,654	)	$	3,301,607	$	380,435	$	(270,980	)	$	3,411,062


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	449,393	$	133,800	$	157,737	$	(214,816	)	$	526,114	$	31,426	$	(8,245	)	$	549,295
Long-term liabilities		1,404,197		—		355,372		—			1,759,569		242,024		(183,419	)		1,818,174
Stockholders’ equity-Quicksilver		1,015,924		88,408		180,430		(268,838	)		1,015,924		79,316		(79,316	)		1,015,924
Noncontrolling interests		—		—		—		—			—		27,669		—			27,669

Total liabilities and stockholders’ equity	$	2,869,514	$	222,208	$	693,539	$	(483,654	)	$	3,301,607	$	380,435	$	(270,980	)	$	3,411,062


	March 31, 2008
			Restricted		Restricted		Restricted			Quicksilver		Unrestricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			and Restricted		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
							(In thousands)
ASSETS
Current assets	$	312,709	$	—	$	58,394	$	(134,891	)	$	236,212	$	3,758	$	(2,963	)	$	237,007
Property and equipment		1,481,585		10,953		616,407		—			2,108,945		321,819		—			2,430,764
Investment in subsidiaries (equity method)		709,673		79,316		—		(292,942	)		496,047		—		(79,316	)		416,731
Other assets		72,042		110,743		1,131		—			183,916		1,198		(161,834	)		23,280

Total assets	$	2,576,009	$	201,012	$	675,932	$	(427,833	)	$	3,025,120	$	326,775	$	(244,113	)	$	3,107,782


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	343,526	$	113,585	$	68,899	$	(134,891	)	$	391,119	$	22,614	$	(2,963	)	$	410,770
Long-term liabilities		1,112,852		—		401,518		—			1,514,370		196,330		(161,834	)		1,548,866
Stockholders’ equity-Quicksilver		1,119,631		87,427		205,515		(292,942	)		1,119,631		79,316		(79,316	)		1,119,631
Noncontrolling interests		—		—		—		—			—		28,515		—			28,515

Total liabilities and stockholders’ equity	$	2,576,009	$	201,012	$	675,932	$	(427,833	)	$	3,025,120	$	326,775	$	(244,113	)	$	3,107,782


	September 30, 2007
			Restricted		Restricted		Restricted			Quicksilver		Unrestricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			and Restricted		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
							(In thousands)
ASSETS
Current assets	$	5,414	$	596	$	327,192	$	(177,745	)	$	155,457	$	11,246	$	(11,948	)	$	154,755
Property and equipment		1,544,145		1,879		614,002		—			2,160,026		227,825		—			2,387,851
Investment in subsidiaries (equity method)		542,662		81,613		4,543		(540,044	)		88,774		—		(81,613	)		7,161
Other assets		67,869		64,457		1,150		—			133,476		959		(114,259	)		20,176

Total assets	$	2,160,090	$	148,545	$	946,887	$	(717,789	)	$	2,537,733	$	240,030	$	(207,820	)	$	2,569,943


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	204,921	$	60,909	$	143,808	$	(177,745	)	$	231,893	$	13,486	$	(11,948	)	$	233,431
Long-term liabilities		1,182,054		—		350,671		—			1,532,725		116,303		(114,259	)		1,534,769
Stockholders’ equity-Quicksilver		773,115		87,636		452,408		(540,044	)		773,115		81,613		(81,613	)		773,115
Noncontrolling interests		—		—		—		—			—		28,628		—			28,628

Total liabilities and stockholders’ equity	$	2,160,090	$	148,545	$	946,887	$	(717,789	)	$	2,537,733	$	240,030	$	(207,820	)	$	2,569,943


	June 30, 2007
			Restricted		Restricted		Restricted			Quicksilver		Unrestricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			and Restricted		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
							(In thousands)
ASSETS
Current assets	$	158,611	$	46	$	312,428	$	(356,263	)	$	114,822	$	43,258	$	(29,687	)	$	128,393
Property and equipment		1,343,598		1,901		560,268		—			1,905,767		193,288		—			2,099,055
Investment in subsidiaries (equity method)		600,553		174,371		4,503		(591,074	)		188,353		—		(181,020	)		7,333
Other assets		19,508		38,279		1,353		—			59,140		—		(38,279	)		20,861

Total assets	$	2,122,270	$	214,597	$	878,552	$	(947,337	)	$	2,268,082	$	236,546	$	(248,986	)	$	2,255,642


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	394,332	$	35,969	$	127,846	$	(356,263	)	$	201,884	$	15,604	$	(29,687	)	$	187,801
Long-term liabilities		1,081,369		32		330,488		—			1,411,889		39,922		(38,279	)		1,413,532
Stockholders’ equity-Quicksilver		646,569		170,856		420,218		(591,074	)		646,569		181,020		(181,020	)		646,569
Noncontrolling interests		—		7,740		—		—			7,740		—		—			7,740

Total liabilities and stockholders’ equity	$	2,122,270	$	214,597	$	878,552	$	(947,337	)	$	2,268,082	$	236,546	$	(248,986	)	$	2,255,642


	March 31, 2007
			Restricted		Restricted		Restricted			Quicksilver		Unrestricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			and Restricted		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
							(In thousands)
ASSETS
Current assets	$	134,809	$	2,297	$	308,677	$	(333,205	)	$	112,578	$	10,438	$	(5,470	)	$	117,546
Property and equipment		1,163,917		950		520,561		—			1,685,428		158,217		—			1,843,645
Investment in subsidiaries (equity method)		537,680		150,529		4,438		(527,264	)		165,383		—		(157,987	)		7,396
Other assets		19,683		—		1,427		—			21,110		821		—			21,931

Total assets	$	1,856,089	$	153,776	$	835,103	$	(860,469	)	$	1,984,499	$	169,476	$	(163,457	)	$	1,990,518


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	368,360	$	17	$	129,203	$	(333,205	)	$	164,375	$	9,829	$	(5,470	)	$	168,734
Long-term liabilities		909,640		1		324,751		—			1,234,392		1,660		—			1,236,052
Stockholders’ equity-Quicksilver		578,089		146,115		381,149		(527,264	)		578,089		157,987		(157,987	)		578,089
Noncontrolling interests		—		7,643		—		—			7,643		—		—			7,643

Total liabilities and stockholders’ equity	$	1,856,089	$	153,776	$	835,103	$	(860,469	)	$	1,984,499	$	169,476	$	(163,457	)	$	1,990,518


	For the Three Months Ended September 30, 2008
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Revenues	$	171,639		$	—		$	61,267		$	—		$	232,906		$	19,304		$	(15,947	)	$	236,263
Operating expenses		100,488			376			21,245			—			122,109			10,111			(15,947	)		116,273
Equity in net earnings of subsidiaries		29,851			5,263			—			(29,851	)		5,263			—			(5,263	)		—

Operating income		101,002			4,887			40,022			(29,851	)		116,060			9,193			(5,263	)		119,990
Income from earnings of BBEP		(89,814	)		—			—			—			(89,814	)		—			—			(89,814	)
Interest expense and other		(31,948	)		1,736			(5,190	)		—			(35,402	)		(2,699	)		—			(38,101	)
Income tax (expense) benefit		17,006			(2,318	)		(9,286	)		—			5,402			(106	)		—			5,296

Net income (loss)		(3,754	)		4,305			25,546			(29,851	)		(3,754	)		6,388			(5,263	)		(2,629	)
Net income attributable to noncontrolling interests		—			—			—			—			—			(1,125	)		—			(1,125	)

Net income (loss) attributable to Quicksilver	$	(3,754	)	$	4,305		$	25,546		$	(29,851	)	$	(3,754	)	$	5,263		$	(5,263	)	$	(3,754	)


	For the Three Months Ended June 30, 2008
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Revenues	$	148,984		$	—		$	45,503		$	—		$	194,487		$	18,205		$	(14,792	)	$	197,900
Operating expenses		72,827			514			22,107			—			95,448			10,141			(14,792	)		90,797
Equity in net earnings of subsidiaries		18,555			4,618			—			(18,555	)		4,618			—			(4,618	)		—

Operating income		94,712			4,104			23,396			(18,555	)		103,657			8,064			(4,618	)		107,103
Income from earnings of BBEP		(10,269	)		—			—			—			(10,269	)		—			—			(10,269	)
Interest expense and other		(11,604	)		1,494			(3,996	)		—			(14,106	)		(2,420	)		—			(16,526	)
Income tax expense		(21,504	)		(1,959	)		(4,484	)		—			(27,947	)		(38	)		—			(27,985	)

Net income		51,335			3,639			14,916			(18,555	)		51,335			5,606			(4,618	)		52,323
Net income attributable to noncontrolling interests		—			—			—			—			—			(988	)		—			(988	)

Net income attributable to Quicksilver	$	51,335		$	3,639		$	14,916		$	(18,555	)	$	51,335		$	4,618		$	(4,618	)	$	51,335


	For the Three Months Ended March 31, 2008
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Revenues	$	116,889		$	—		$	38,468		$	—		$	155,357		$	15,185		$	(12,925	)	$	157,617
Operating expenses		66,959			499			22,438			—			89,896			9,923			(12,925	)		86,894
Equity in net earnings of subsidiaries		11,063			2,376			—			(11,063	)		2,376			—			(2,376	)		—

Operating income		60,993			1,877			16,030			(11,063	)		67,837			5,262			(2,376	)		70,723
Income from earnings of BBEP		6,219			—			—			—			6,219			—			—			6,219
Interest expense and other		(7,049	)		1,433			(3,920	)		—			(9,536	)		(2,413	)		—			(11,949	)
Income tax expense		(19,029	)		(1,159	)		(3,198	)		—			(23,386	)		35			—			(23,351	)

Net income		41,134			2,151			8,912			(11,063	)		41,134			2,884			(2,376	)		41,642
Net income attributable to noncontrolling interests		—			—			—			—			—			(508	)		—			(508	)

Net income attributable to Quicksilver	$	41,134		$	2,151		$	8,912		$	(11,063	)	$	41,134		$	2,376		$	(2,376	)	$	41,134


	For the Three Months Ended September 30, 2007
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Revenues	$	104,237		$	—		$	52,955		$	(239	)	$	156,953		$	10,282		$	(8,036	)	$	159,199
Operating expenses		73,375			(784	)		25,117			(239	)		97,469			6,477			(8,036	)		95,910
Equity in net earnings of subsidiaries		18,201			1,848			289			(18,205	)		2,133			—			(1,848	)		285

Operating income (loss)		49,063			2,632			28,127			(18,205	)		61,617			3,805			(1,848	)		63,574
Interest expense and other		(16,657	)		999			(4,787	)		—			(20,445	)		(1,408	)		—			(21,853	)
Income tax expense		(4,693	)		(1,271	)		(7,495	)		—			(13,459	)		(92	)		—			(13,551	)

Net income		27,713			2,360			15,845			(18,205	)		27,713			2,305			(1,848	)		28,170
Net income attributable to noncontrolling interests		—			—			—			—			—			(457	)		—			(457	)

Net income attributable to Quicksilver	$	27,713		$	2,360		$	15,845		$	(18,205	)	$	27,713		$	1,848		$	(1,848	)	$	27,713


	For the Three Months Ended June 30, 2007
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Revenues	$	88,948		$	—		$	46,930		$	(209	)	$	135,669		$	7,117		$	(6,285	)	$	136,501
Operating expenses		54,687			680			21,094			(209	)		76,252			4,738			(6,285	)		74,705
Equity in net earnings of subsidiaries		18,743			2,031			266			(18,727	)		2,313			—			(2,031	)		282

Operating income		53,004			1,351			26,102			(18,727	)		61,730			2,379			(2,031	)		62,078
Interest expense and other		(15,226	)		212			(3,663	)		—			(18,677	)		(292	)		—			(18,969	)
Income tax expense		(7,035	)		(502	)		(4,645	)		—			(12,182	)		(56	)		—			(12,238	)

Net income		30,743			1,061			17,794			(18,727	)		30,871			2,031			(2,031	)		30,871
Net income attributable to noncontrolling interests		—			(128	)		—			—			(128	)		—			—			(128	)

Net income attributable to Quicksilver	$	30,743		$	933		$	17,794		$	(18,727	)	$	30,743		$	2,031		$	(2,031	)	$	30,743


	For the Three Months Ended March 31, 2007
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Revenues	$	70,868		$	—		$	44,732		$	(228	)	$	115,372		$	5,372		$	(4,164	)	$	116,580
Operating expenses		46,461			459			21,099			(228	)		67,791			4,508			(4,164	)		68,135
Equity in net earnings of subsidiaries		14,480			748			109			(14,474	)		863			—			(748	)		115

Operating income		38,887			289			23,742			(14,474	)		48,444			864			(748	)		48,560
Interest expense and other		(12,613	)		—			(3,156	)		—			(15,769	)		(75	)		—			(15,844	)
Income tax (expense) benefit		(4,393	)		(79	)		(6,259	)		—			(10,731	)		(41	)		—			(10,772	)

Net income		21,881			210			14,327			(14,474	)		21,944			748			(748	)		21,944
Net income attributable to noncontrolling interests		—			(63	)		—			—			(63	)		—			—			(63	)

Net income attributable to Quicksilver	$	21,881		$	147		$	14,327		$	(14,474	)	$	21,881		$	748		$	(748	)	$	21,881


	For the Nine Months Ended September 30, 2008
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Revenues	$	437,512		$	—		$	145,238		$	—		$	582,750		$	52,694		$	(43,664	)	$	591,780
Operating expenses		240,274			1,389			65,790			—			307,453			30,175			(43,664	)		293,964
Equity in net earnings of subsidiaries		59,469			12,258			—			(59,469	)		12,258			—			(12,258	)		—

Operating income		256,707			10,869			79,448			(59,469	)		287,555			22,519			(12,258	)		297,816
Income from earnings of BBEP		(93,864	)		—			—			—			(93,864	)		—			—			(93,864	)
Interest expense and other		(50,601	)		4,663			(13,107	)		—			(59,045	)		(7,531	)		—			(66,576	)
Income tax expense		(23,527	)		(5,436	)		(16,968	)		—			(45,931	)		(109	)		—			(46,040	)

Net income		88,715			10,096			49,373			(59,469	)		88,715			14,879			(12,258	)		91,336
Net income attributable to noncontrolling interests		—			—			—			—			—			(2,621	)		—			(2,621	)


Net income attributable to Quicksilver	$	88,715		$	10,096		$	49,373		$	(59,469	)	$	88,715		$	12,258		$	(12,258	)	$	88,715


	For the Six Months Ended June 30, 2008
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	265,873		$	—		$	83,971		$	—		$	349,844		$	33,390		$	(27,717	)	$	355,517
Operating expenses		139,786			1,013			44,545			—			185,344			20,064			(27,717	)		177,691
Equity in net earnings of subsidiaries		29,618			6,994			—			(29,618	)		6,994			—			(6,994	)		—

Operating income		155,705			5,981			39,426			(29,618	)		171,494			13,326			(6,994	)		177,826
Income from earnings of BBEP		(4,050	)		—			—			—			(4,050	)		—			—			(4,050	)
Interest expense and other		(18,653	)		2,927			(7,916	)		—			(23,642	)		(4,833	)		—			(28,475	)
Income tax expense		(40,533	)		(3,118	)		(7,682	)		—			(51,333	)		(3	)		—			(51,336	)

Net income		92,469			5,790			23,828			(29,618	)		92,469			8,490			(6,994	)		93,965
Net income attributable to noncontrolling interests		—			—			—			—			—			(1,496	)		—			(1,496	)


Net income attributable to Quicksilver	$	92,469		$	5,790		$	23,828		$	(29,618	)	$	92,469		$	6,994		$	(6,994	)	$	92,469


	For the Nine Months Ended September 30, 2007
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	264,053		$	—		$	144,514		$	(676	)	$	407,891		$	22,771		$	(18,485	)	$	412,177
Operating expenses		174,523			355			67,310			(676	)		241,512			15,723			(18,485	)		238,750
Equity in net earnings of subsidiaries		51,424			4,627			664			(51,406	)		5,309			—			(4,627	)		682

Operating income		140,954			4,272			77,868			(51,406	)		171,688			7,048			(4,627	)		174,109
Interest expense and other		(44,496	)		1,211			(11,503	)		—			(54,788	)		(1,775	)		—			(56,563	)
Income tax expense		(16,121	)		(1,852	)		(18,399	)		—			(36,372	)		(189	)		—			(36,561	)

Net income		80,337			3,631			47,966			(51,406	)		80,528			5,084			(4,627	)		80,985
Net income attributable to noncontrolling interests		—			(191	)		—			—			(191	)		(457	)		—			(648	)


Net income attributable to Quicksilver	$	80,337		$	3,440		$	47,966		$	(51,406	)	$	80,337		$	4,627		$	(4,627	)	$	80,337


	For the Six Months Ended June 30, 2007
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	159,816		$	—		$	91,662		$	(437	)	$	251,041		$	12,489		$	(10,449	)	$	253,081
Operating expenses		101,148			1,139			42,193			(437	)		144,043			9,246			(10,449	)		142,840
Equity in net earnings of subsidiaries		33,223			2,779			375			(33,201	)		3,176			—			(2,779	)		397

Operating income		91,891			1,640			49,844			(33,201	)		110,174			3,243			(2,779	)		110,638
Interest expense and other		(27,839	)		212			(6,819	)		—			(34,446	)		(367	)		—			(34,813	)
Income tax (expense) benefit		(11,428	)		(581	)		(10,904	)		—			(22,913	)		(97	)		—			(23,010	)

Net income		52,624			1,271			32,121			(33,201	)		52,815			2,779			(2,779	)		52,815
Net income attributable to noncontrolling interests		—			(191	)		—			—			(191	)		—			—			(191	)


Net income attributable to Quicksilver	$	52,624		$	1,080		$	32,121		$	(33,201	)	$	52,624		$	2,779		$	(2,779	)	$	52,624


	For the Nine Months Ended September 30, 2008
				Restricted			Restricted			Restricted		Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by operations	$	138,736		$	2,483		$	113,616		$	—	$	254,835		$	36,365		$	(17,080	)	$	274,120
Purchases of property, plant and equipment		(1,744,219	)		(2,483	)		(116,871	)		—		(1,863,573	)		(112,200	)		—			(1,975,773	)
Return of investment from BBEP and equity affiliates		31,435			—			—			—		31,435			—			—			31,435
Proceeds from sale of equipment to subsidiaries		825			—			—			—		825			—			(825	)		—
Proceeds from sales of properties and equipment		200			—			618			—		818			—			—			818

Cash flow provided by (used for) investing activities		(1,711,759	)		(2,483	)		(116,253	)		—		(1,830,495	)		(112,200	)		(825	)		(1,943,520	)
Issuance of debt		2,169,611			—			203,208			—		2,372,819			99,300			—			2,472,119
Repayments of debt		(583,782	)		—			(198,206	)		—		(781,988	)		—			—			(781,988	)
Debt issuance costs		(24,545	)		—			—			—		(24,545	)		—			—			(24,545	)
Repayments to parent		—			—			—			—		—			(825	)		825			—
Distributions to parent		—			—			—			—		—			(17,080	)		17,080			—
Distributions to noncontrolling interests		—			—			—			—		—			(6,343	)		—			(6,343	)
Proceeds from exercise of stock options		1,240			—			—			—		1,240			—			—			1,240
Purchase of treasury stock		(3,235	)		—			—			—		(3,235	)		—			—			(3,235	)

Cash flow provided by (used for) financing activities		1,559,289			—			5,002			—		1,564,291			75,052			17,905			1,657,248
Effect of exchange rates on cash		(155	)		—			(2,454	)		—		(2,609	)		—			—			(2,609	)

Net increase (decrease) in cash & equivalents		(13,889	)		—			(89	)		—		(13,978	)		(783	)		—			(14,761	)
Cash and equivalents at beginning of period		27,012			—			89			—		27,101			1,125			—			28,226

Cash and equivalents at end of period	$	13,123		$	—		$	—		$	—	$	13,123		$	342		$	—		$	13,465


	For the Six Months Ended June 30, 2008
				Restricted			Restricted			Restricted		Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by operations	$	(14,468	)	$	2,282		$	135,589		$	—	$	123,403		$	24,080		$	(10,872	)	$	136,611
Purchases of property, plant and equipment		(489,605	)		(2,282	)		(99,137	)		—		(591,024	)		(59,434	)		—			(650,458	)
Return of investment from BBEP and equity affiliates		20,334			—			—			—		20,334			—			—			20,334
Proceeds from sale of equipment to subsidiaries		550			—			—			—		550			—			(550	)		—
Proceeds from sales of properties and equipment		—			—			598			—		598			—			—			598

Cash flow provided by (used for) investing activities		(468,721	)		(2,282	)		(98,539	)		—		(569,542	)		(59,434	)		(550	)		(629,526	)
Issuance of debt		876,611			—			103,377			—		979,988			50,300			—			1,030,288
Repayments of debt		(408,032	)		—			(139,534	)		—		(547,566	)		—			—			(547,566	)
Debt issuance costs		(10,837	)		—			—			—		(10,837	)		—			—			(10,837	)
Repayments to parent		—			—			—			—		—			(550	)		550			—
Distributions to parent		—			—			—			—		—			(10,872	)		10,872			—
Distributions to noncontrolling interests		—			—			—			—		—			(4,042	)		—			(4,042	)
Proceeds from exercise of stock options		1,082			—			—			—		1,082			—			—			1,082
Purchase of treasury stock		(2,354	)		—			—			—		(2,354	)		—			—			(2,354	)

Cash flow provided by (used for) financing activities		456,470			—			(36,157	)		—		420,313			34,836			11,422			466,571
Effect of exchange rates on cash		(70	)		—			517			—		447			—			—			447

Net increase (decrease) in cash & equivalents		(26,789	)		—			1,410			—		(25,379	)		(518	)		—			(25,897	)
Cash and equivalents at beginning of period		27,012			—			89			—		27,101			1,125			—			28,226

Cash and equivalents at end of period	$	223		$	—		$	1,499		$	—	$	1,722		$	607		$	—		$	2,329


	For the Three Months Ended March 31, 2008
				Restricted			Restricted			Restricted		Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by operations	$	(10,412	)	$	1,888		$	44,265		$	—	$	35,741		$	12,846		$	(5,303	)	$	43,284
Purchases of property, plant and equipment		(220,215	)		(1,888	)		(77,152	)		—		(299,255	)		(32,681	)		—			(331,936	)
Advances to BBEP		(50,150	)		—			—			—		(50,150	)		—			—			(50,150	)
Return of investment from BBEP and equity affiliates		3,440			—			—			—		3,440			—			—			3,440
Proceeds from sale of equipment to subsidiaries		278			—			—			—		278			—			(278	)		—
Proceeds from sales of properties and equipment		—			—			—			—		—			—			—			—

Cash flow provided by (used for) investing activities		(266,647	)		(1,888	)		(77,152	)		—		(345,687	)		(32,681	)		(278	)		(378,646	)
Issuance of debt		253,000			—			51,241			—		304,241			26,500			—			330,741
Repayments of debt		(34	)		—			(18,027	)		—		(18,061	)		—			—			(18,061	)
Repayments to parent		—			—			—			—		—			(278	)		278			—
Distributions to parent		—			—			—			—		—			(5,303	)		5,303			—
Distributions to noncontrolling interests		—			—			—			—		—			(1,972	)		—			(1,972	)
Proceeds from exercise of stock options		858			—			—			—		858			—			—			858
Purchase of treasury stock		(1,980	)		—			—			—		(1,980	)		—			—			(1,980	)

Cash flow provided by (used for) financing activities		251,844			—			33,214			—		285,058			18,947			5,581			309,586
Effect of exchange rates on cash		(58	)		—			(416	)		—		(474	)		—			—			(474	)

Net increase (decrease) in cash & equivalents		(25,273	)		—			(89	)		—		(25,362	)		(888	)		—			(26,250	)
Cash and equivalents at beginning of period		27,012			—			89			—		27,101			1,125			—			28,226

Cash and equivalents at end of period	$	1,739		$	—		$	—		$	—	$	1,739		$	237		$	—		$	1,976


	For the Nine Months Ended September 30, 2007
				Restricted			Restricted			Restricted		Quicksilver				Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		and Restricted				Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			��	Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by (used for) operations	$	153,652		$	280		$	93,846		$	—	$	247,778			$	13,921		$	—		$	261,699
Purchases of property, plant and equipment		(612,074	)		(280	)		(82,178	)		—		(694,532	)			(55,184	)		29,508			(720,208	)
Investment in subsidiaries and affiliates		(38,045	)		—			—			—		(38,045	)			—			38,045			—
Return of investment from subsidiaries and affiliates		112,125			—			149			—		112,274				—			(112,112	)		162
Proceeds from sales of properties and equipment		166			—			—			—		166				—			—			166

Cash flow provided by (used for) investing activities		(537,828	)		(280	)		(82,029	)		—		(620,137	)			(55,184	)		(44,559	)		(719,880	)
Issuance of debt		497,500			—			42,530			—		540,030				—			—			540,030
Repayments of debt		(123,773	)		—			(58,584	)		—		(182,357	)			—			—			(182,357	)
Debt issuance costs		(2,857	)		—			(664	)		—		(3,521	)			(992	)		—			(4,513	)
Proceeds from sale of KGS units, net		—			—			—			—		—				109,642			—			109,642
Contributions from parent		—			—			—			—		—				67,553			(67,553	)		—
Contributions from noncontrolling interests		—			—			—			—		—				167			—			167
Distributions to parent		—			—			—			—		—				(112,112	)		112,112			—
Distributions to noncontrolling interests		—			—			—			—		—				(7,694	)		—			(7,694	)
Proceeds from exercise of stock options		15,570			—			—			—		15,570				—			—			15,570
Purchase of treasury stock		(1,525	)		—			—			—		(1,525	)			—			—			(1,525	)

Cash flow provided by (used for) financing activities		384,915			—			(16,718	)		—		368,197				56,564			44,559			469,320
Effect of exchange rates on cash		588			—			2,582			—		3,170				—			—			3,170

Net increase (decrease) in cash & equivalents		1,327			—			(2,319	)		—		(992	)			15,301			—			14,309
Cash and equivalents at beginning of period		83			—			2,401			—		2,484				2,797			—			5,281

Cash and equivalents at end of period	$	1,410		$	—		$	82		$	—	$	1,492			$	18,098		$	—		$	19,590


	For the Six Months Ended June 30, 2007
				Restricted			Restricted			Restricted		Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by (used for) operations	$	80,928		$	280		$	67,282		$	—	$	148,490		$	6,058		$	—		$	154,548
Purchases of property, plant and equipment		(334,712	)		(280	)		(62,635	)		—		(397,627	)		(45,040	)		—			(442,667	)
Investment in subsidiaries and affiliates		(39,017	)		—			—			—		(39,017	)		—			39,017			—
Return of investment from subsidiaries and affiliates		3			—			164			—		167			—			—			167
Proceeds from sales of properties and equipment		162			—			—			—		162			—			—			162

Cash flow provided by (used for) investing activities		(373,564	)		(280	)		(62,471	)		—		(436,315	)		(45,040	)		39,017			(442,338	)
Issuance of debt		283,000			—			29,157			—		312,157			—			—			312,157
Repayments of debt		(180	)		—			(37,081	)		—		(37,261	)		—			—			(37,261	)
Debt issuance costs		(1,882	)		—			(664	)		—		(2,546	)		—			—			(2,546	)
Contributions from parent		—			—			—			—		—			39,017			(39,017	)		—
Contributions from noncontrolling interests		—			—			—			—		—			167			—			167
Proceeds from exercise of stock options		12,187			—			—			—		12,187			—			—			12,187
Purchase of treasury stock		(821	)		—			—			—		(821	)		—			—			(821	)

Cash flow provided by (used for) financing activities		292,304			—			(8,588	)		—		283,716			39,184			(39,017	)		283,883
Effect of exchange rates on cash		390			—			1,494			—		1,884			—			—			1,884

Net increase (decrease) in cash & equivalents		58			—			(2,283	)		—		(2,225	)		202			—			(2,023	)
Cash and equivalents at beginning of period		83			—			2,401			—		2,484			2,797			—			5,281

Cash and equivalents at end of period	$	141		$	—		$	118		$	—	$	259		$	2,999		$	—		$	3,258


	For the Three Months Ended March 31, 2007
				Restricted			Restricted			Restricted		Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by (used for) operations	$	40,820		$	276		$	30,151		$	—	$	71,247		$	1,759		$	—		$	73,006
Purchases of property, plant and equipment		(142,252	)		(276	)		(43,696	)		—		(186,224	)		(23,702	)		—			(209,926	)
Investment in subsidiaries and affiliates		(21,955	)		—			—			—		(21,955	)		—			21,955			—
Return of investment from subsidiaries and affiliates		(15	)		—			217			—		202			—			—			202

Cash flow provided by (used for) investing activities		(164,222	)		(276	)		(43,479	)		—		(207,977	)		(23,702	)		21,955			(209,724	)
Issuance of debt		123,000			—			20,446			—		143,446			—			—			143,446
Repayments of debt		(87	)		—			(6,781	)		—		(6,868	)		—			—			(6,868	)
Debt issuance costs		(1,639	)		—			(664	)		—		(2,303	)		—			—			(2,303	)
Contributions from parent		—			—			—			—		—			21,955			(21,955	)		—
Contributions from noncontrolling interests		—			—			—			—		—			167			—			167
Proceeds from exercise of stock options		2,976			—			—			—		2,976			—			—			2,976
Purchase of treasury stock		(494	)		—			—			—		(494	)		—			—			(494	)

Cash flow provided by (used for) financing activities		123,756			—			13,001			—		136,757			22,122			(21,955	)		136,924
Effect of exchange rates on cash		—			—			231			—		231			—			—			231

Net increase (decrease) in cash & equivalents		354			—			(96	)		—		258			179			—			437
Cash and equivalents at beginning of period		83			—			2,401			—		2,484			2,797			—			5,281

Cash and equivalents at end of period	$	437		$	—		$	2,305		$	—	$	2,742		$	2,976		$	—		$	5,718

ITEM 9A. Controls and Procedures

Disclosure Controls and Procedures

Disclosure controls and procedures, as defined in SEC literature, are controls and other procedures that are designed to ensure that the information that we are required to disclose in the reports that we file or submit to the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

In connection with the preparation of this Annual Report on Form 10-K, as amended, our management, under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2008. In making this evaluation, our management considered the matters relating to the restatement of our financial statements and the material weaknesses discussed below.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2008. In light of the material weaknesses described below, we revised our review of the preparation of condensed consolidating financial information and expanded our review of our financial reporting requirements and have concluded that the financial statements in this Annual Report on Form 10-K, as amended, present fairly, in all material respects, our consolidated financial position, results of operation and cash flows in conformity with generally accepted accounting principles.

Management’s Report on Internal Control Over Financial Reporting

Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with existing policies or procedures may deteriorate.

Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management conducted an assessment of our internal control over financial reporting as of December 31, 2008, based on the criteria established inInternal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, our management has concluded that, as of December 31, 2008, we did not maintain an effective control environment over financial reporting due to material weaknesses relating to:

•

preparation and review of combined financial information within our condensed consolidating financial information. The condensed consolidating information previously reported contained errors that resulted from inadequate review of the combined financial information. These errors did not affect the amounts previously reported in our consolidated financial statements.

•

monitoring the Company’s financial reporting requirements. The review associated with the completeness of the required information failed to highlight omitted information related to the Company and its restricted subsidiaries.

Changes in Internal Control Over Financial Reporting

In response to the identification of these material weaknesses, management has revised its process to better structure the preparation and allow for further review of its consolidating financial information. Further, management has enhanced its process for documenting and satisfying the full extent of the Company’s financial reporting requirements. Management believes that these enhancements and improvements, when repeated in future periods, remediate the material weaknesses described above.

Other than the identification and remediation of the material weaknesses described above, there has been no change in our internal control over financial reporting during 2008, including the quarter ended December 31, 2008, that has materially affected, or is reasonably likely to 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 the internal control over financial reporting of Quicksilver Resources Inc. and subsidiaries (the “Company”) as of December 31, 2008, based on criteria established inInternal Control — Integrated Frameworkissued 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, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified and included in management’s assessment: 1) preparation and review of combined financial information within the condensed consolidating financial information, and 2) monitoring the Company’s financial reporting requirements.

In our opinion, because of the effect of the material weaknesses identified above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2008, based on the criteria established inInternal Control — Integrated Frameworkissued 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, 2008 of the Company. We considered the material weaknesses identified above in determining the nature, timing, and extent of audit tests applied in our audit of the 2008 consolidated financial statements, and this report does not affect our report dated March 2, 2009 (June 16, 2009 as to the effects of the restatement as discussed in Notes 14 and 21, and as to the effects of the adoption of Statement of Financial Accounting Standards No. 160,Noncontrolling Interests in Consolidated Financial Statements – an Amendment to ARB 51(“SFAS 160”), FASB Staff Position APB 14-1:Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)(“FSP APB 14-1”), and FASB Staff Position EITF 03-6-1:Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities(“FSP EITF 03-6-1”), and the related disclosures in Notes 2, 4, 12, 14, 16, 18, and 21) which expressed an unqualified opinion on those financial statements and included explanatory paragraphs regarding the restatement of the 2008 consolidated financial statements, and the adoption of SFAS 160, FSP APB 14-1, and FSP EITF 03-6-1.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas
March 2, 2009 (June 16, 2009 as to the effects of the material weaknesses discussed in Management’s Report on Internal Control Over Financial Reporting)

PART IV

ITEM 15. Exhibits and Financial Statement Schedules

Financial Statement Schedules

The following Consolidated Financial Statements and related footnotes are filed as part of this report:


		i.)		Audited financial statements and related footnotes of Quicksilver Resources Canada Inc. (“QRCI”) for the years ended December 31, 2008, 2007 and 2006.⁽¹⁾

		ii.)		Consolidated audited financial statements and related footnotes of Cowtown Pipeline Funding, Inc. for the years ended December 31, 2008, 2007 and 2006.⁽¹⁾

		iii.)		Consolidated audited financial statements and related footnotes of Quicksilver Gas Services Holdings LLC for the years ended December 31, 2008, 2007 and 2006.⁽¹⁾

		iv.)		Consolidated audited financial statements and related footnotes of Quicksilver’s equity method investment in BreitBurn Energy Partners L.P. (“BBEP”).⁽²⁾


⁽¹⁾		The audited financial statements of QRCI, Cowtown Pipeline Funding, Inc. and Quicksilver Gas Services Holdings LLC are being filed in accordance with SEC Rule 3-16 of Regulation S-X.

⁽²⁾		The audited financial statements and related footnotes of Quicksilver’s equity method investment in BreitBurn Energy Partners L.P. are being filed in accordance with SEC Rule 3-09 of Regulation S-X.

QUICKSILVER RESOURCES CANADA INC.
CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ending December 31, 2008, 2007 and 2006



Independent Auditors’ Report

Consolidated Balance Sheets as of December 31, 2008 and 2007

Consolidated Statements of Income and Comprehensive Income for the Years Ended December 31, 2008, 2007 and 2006

Consolidated Statements of Stockholder’s Equity for the Years Ended December 31, 2008, 2007 and 2006

Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006

Notes to Consolidated Financial Statements for the Years Ended December 31, 2008, 2007 and 2006

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Stockholder of
Quicksilver Resources Canada Inc.
Fort Worth, Texas

We have audited the accompanying consolidated balance sheets of Quicksilver Resources Canada Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income and comprehensive income, stockholder’s equity and of cash flows for each of the three years in the period ended December 31, 2008. 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 auditing standards generally accepted in the United States of America. 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Quicksilver Resources Canada Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared from the separate records maintained by Quicksilver Resources Inc. and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to, Quicksilver Resources Inc. as a whole.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas
May 29, 2009

QUICKSILVER RESOURCES CANADA INC.

CONSOLIDATED BALANCE SHEETS

As of December 31, 2008 and 2007

In thousands


	2008		2007
ASSETS
Current assets
Cash and cash equivalents	$	866	$	89
Accounts receivable — net of allowance for doubtful accounts		29,169		38,648
Advances to Quicksilver		30		118
Derivative assets at fair value		59,245		419
Other current assets		13,063		18,739

Total current assets		102,373		58,013
Investment in equity affiliate at cost		68,604		—
Property, plant and equipment
Oil and gas properties, full cost method (including unevaluated costs of $9,832 and $21,170, respectively)		437,563		533,401
Other property and equipment		42,585		38,566

Property, plant and equipment — net		480,148		571,967
Other assets		910		1,205

	$	652,035	$	631,185

LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable	$	19,587	$	9,396
Accrued liabilities		7,612		21,679
Derivative liabilities at fair value		1,865		—
Deferred income taxes		15,843		62

Total current liabilities		44,907		31,137

Long-term debt		252,868		310,710
Asset retirement obligations		17,608		14,278
Deferred income taxes		56,948		46,572
Stockholder’s equity
Common stock		1,817		1,817
Paid in capital in excess of par value		28,118		28,118
Accumulated other comprehensive income		33,809		43,870
Retained earnings		215,960		154,683

Total stockholder’s equity		279,704		228,488

	$	652,035	$	631,185

The accompanying notes are an integral part of these consolidated financial statements.

QUICKSILVER RESOURCES CANADA INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2008, 2007 and 2006
In thousands


	2008			2007			2006
Revenue
Natural gas, NGL and crude oil	$	181,994		$	154,372		$	117,831
Other		4,840			6,174			721

Total revenue		186,834			160,546			118,552


Operating expenses
Oil and gas production expense		38,153			35,931			26,237
Depletion, depreciation and accretion		44,821			39,287			29,012
General and administrative		3,673			2,499			1,790

Total expenses		86,647			77,717			57,039

Operating income		100,187			82,829			61,513
Other income (expense) — net		(2,994	)		(427	)		108
Interest expense		(13,978	)		(14,773	)		(12,593	)

Income before income taxes		83,215			67,629			49,028
Income tax expense		(21,938	)		(11,129	)		(8,777	)

Net income	$	61,277		$	56,500		$	40,251

Other comprehensive income
Reclassification adjustments related to settlements of derivative contracts — net of income tax		160			(18,043	)		(6,030	)
Net change in derivative fair value — net of income tax		38,478			5,012			33,747
Foreign currency translation adjustment		(48,699	)		29,018			(1,236	)

Comprehensive income	$	51,216		$	72,487		$	66,732

The accompanying notes are an integral part of these consolidated financial statements.

QUICKSILVER RESOURCES CANADA INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2008, 2007 and 2006
In thousands


					Accumulated
			Additional		Other
	Common		Paid-in		Comprehensive			Retained
	Stock		Capital		Income			Earnings		Total
Balances at December 31, 2005	$	1,817	$	28,118	$	1,402		$	57,932	$	89,269
Net income		—		—		—			40,251		40,251
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $3,636		—		—		(6,030	)		—		(6,030	)
Net change in derivative fair value, net of income tax benefit of $17,884		—		—		33,747			—		33,747
Foreign currency translation adjustment		—		—		(1,236	)		—		(1,236	)

Balances at December 31, 2006	$	1,817	$	28,118	$	27,883		$	98,183	$	156,001
Net income		—		—		—			56,500		56,500
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $7,550		—		—		(18,043	)		—		(18,043	)
Net change in derivative fair value, net of income tax benefit of $2,229		—		—		5,012			—		5,012
Foreign currency translation adjustment		—		—		29,018			—		29,018

Balances at December 31, 2007	$	1,817	$	28,118	$	43,870		$	154,683	$	228,488
Net income		—		—		—			61,277		61,277
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax benefit of $65		—		—		160			—		160
Net change in derivative fair value, net of income tax of $15,715		—		—		38,478			—		38,478
Foreign currency translation adjustment		—		—		(48,699	)		—		(48,699	)

Balances at December 31, 2008	$	1,817	$	28,118	$	33,809		$	215,960	$	279,704

The accompanying notes are an integral part of these consolidated financial statements.

QUICKSILVER RESOURCES CANADA INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2008, 2007 and 2006
In thousands


	2008			2007			2006
Operating activities:
Net income	$	61,277		$	56,500		$	40,251
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion		44,821			39,287			29,012
Deferred income tax expense		21,938			11,129			8,777
Non-cash loss from hedging and derivative activities		(2,544	)		(193	)		—
Loss from the sale of equipment		—			—			936
Non-cash interest expense		295			297			316
Changes in assets and liabilities
Accounts receivable		9,479			9,763			2,503
Advances to/from Quicksilver		88			(446	)		(8,326	)
Other assets		2,324			(3,318	)		487
Accounts payable		1,977			(78	)		(2,928	)
Accrued liabilities		(2,650	)		(447	)		3,567

Net cash provided by operating activities		137,005			112,494			74,595


Investing activities:
Purchases of property, plant and equipment		(136,057	)		(147,195	)		(131,470	)
Proceeds from sales of property, plant and equipment		618			—			3,778

Net cash used for investing activities		(135,439	)		(147,195	)		(127,692	)


Financing activities:
Issuance of debt		208,161			218,321			56,182
Repayment of debt		(209,734	)		(190,691	)		(9,908	)
Debt issuance costs		—			(664	)		—

Net cash (used for) provided by financing activities		(1,573	)		26,966			46,274


Effect of exchange rate changes in cash		784			5,423			(514	)


Net increase (decrease) in cash		777			(2,312	)		(7,337	)

Cash and cash equivalents at beginning of period		89			2,401			9,738


Cash and cash equivalents at end of period	$	866		$	89		$	2,401

The accompanying notes are an integral part of these consolidated financial statements.

QUICKSILVER RESOURCES CANADA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 2008, 2007 and 2006

1. SIGNIFICANT ACCOUNTING POLICIES

Nature of Business and Basis of Presentation

Quicksilver Resources Canada Inc. (“QRCI “or the “Company”) was previously called MGV Energy Inc., which was formed upon the amalgamation of MGV Energy Inc., Gatens Holdings Inc. and Voneiff Holdings Inc. on August 19, 1999 under the Alberta Business Corporations Act. The name was changed to Quicksilver Resources Canada Inc. on April 10, 2006. QRCI is a wholly-owned subsidiary of Quicksilver Resources Inc. (“Quicksilver” or the “parent company”). QRCI is engaged in the exploration, development and production of petroleum and natural gas reserves.

Basis of Presentation

A wholly-owned subsidiary of QRCI was dissolved December 15, 2006. The subsidiary did not hold any assets at the time of dissolution. Prior to this date, the financial statements of QRCI were consolidated and included the accounts of the Company and its subsidiary. We eliminate all inter-company balances and transactions in preparing consolidated financial statements. QRCI accounts for its ownership in unincorporated partnerships and companies under the cost method as it has significant influence over those entities, but because of terms of the ownership agreements, it does not meet the criteria for control which would trigger consolidation of the entities. QRCI also consolidates its share of oil and gas joint ventures.

The QRCI financial statements presented herein have been translated from Canadian dollars to U.S. dollars as QRCI uses the Canadian dollar as its functional currency. Unless otherwise noted, all financial information presented herein is reported in U.S. dollars.

Use of Estimates

The preparation of financial statements in conformity with GAAP in the U.S. requires QRCI’s management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses, including stock compensation expense, during each reporting period. QRCI’s 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 QRCI’s estimates. Significant estimates underlying these financial statements include the estimated quantities of proved natural gas, NGL and crude oil reserves used to compute depletion expense and future net cash flows from reserve production, estimates of current revenue 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

Hedging and Derivatives

Quicksilver enters into financial derivative instruments on behalf of QRCI to mitigate risk associated with the prices received from its natural gas, NGL and crude oil production. All derivatives are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates. For derivatives instruments that qualify as cash flow hedges, the effective portions of gains and losses are deferred in other comprehensive income and recognized in revenue 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 earnings during the period in which the hedged transaction is recognized. If the hedged transaction becomes probable of not occurring, the deferred gain or loss would be immediately recorded to earnings. Changes in value of ineffective portions of hedges, if any, are recognized currently as a component of other revenue.

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

QRCI accounts for its preferred interests in 1373159 Alberta Ltd. using the cost method. QRCI carries the investment at historical cost and reviews the investment for impairment whenever circumstances or events indicate that the investment’s carrying value will not be recoverable.

Property, Plant, and Equipment

QRCI follows the full cost method in accounting for its oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. 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. Excluded from amounts subject to depletion are costs associated with unevaluated properties.

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge QRCI’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. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required.

All other properties and equipment are stated at original cost and depreciated using the straight-line method based on estimated useful lives ranging from five to forty years.

Revenue Recognition

Revenue is recognized when title to the products transfer to the purchaser. QRCI uses the “sales method” to account for its production revenue, whereby QRCI recognizes revenue on all natural gas, NGL 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, 2008 and 2007, QRCI’s aggregate production imbalances were not material.

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

Stock-based Compensation

The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors based on their estimated fair value. At the discretion of Quicksilver’s board of directors, QRCI may issue awards payable in cash. For all awards, QRCI recognizes the expense associated with the awards over the vesting period. The liability for fair value of cash awards is reassessed at every balance sheet date, such that the vested portion of the liability is adjusted to reflect revised fair value through compensation expense.

Disclosure of Fair Value of Financial Instruments

QRCI’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 are recorded at cost which approximates fair value. SFAS No. 157,Fair Value Measurements, was adopted on January 1, 2008 and applied to fair value measurements of the Company’s financial instruments, including its financial derivative instruments. Additional information regarding the Company’s implementation of the accounting standard is found under “Recently Issued Accounting Standards” in this Note.

Foreign Currency Translation

The Company uses the Canadian dollar as its functional currency. All balance sheet accounts of QRCI are translated into U.S. dollars at the period-end rate of exchange and statement of income items are translated at the weighted average exchange rates for the period. The resulting translation adjustments are made directly to a component of accumulated other comprehensive income within stockholder’s equity. Gains and losses from foreign currency transactions are included in the statement of income.

Recently Issued Accounting Standards

•

Pronouncements Implemented During 2008

Adoption of SFAS No. 157—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 under 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 has changed current practice. On February 12, 2008, the FASB issued FASB Staff Position 157-2 (“FSP 157-2”) which delayed the effective date of SFAS No. 157 for non-financial assets and liabilities. The delay allows companies additional time to consider the effect of various implementation issues that have arisen, or that may arise, from the application of SFAS No. 157. FSP FAS 157-3 was issued by the FASB on October 10, 2008 to clarify application of SFAS No. 157 when determining the fair value of a financial asset when the market for that financial asset is not active. QRCI adopted SFAS No. 157 on January 1, 2008 for new fair value measurements of financial instruments, including its derivative instruments, and recurring fair value measurements of non-financial assets and liabilities. All financial instruments are measured using inputs from three levels of fair value hierarchy. The three levels are as follows:

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.

Level 3 inputs are unobservable inputs that reflect the Company’s assumptions about the assumptions that market participants would use in pricing an asset or liability.

Adoption of SFAS No. 159— In February 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 that are not currently required to be measured at fair value. While SFAS No. 159 became effective on January 1, 2008, QRCI did not elect the fair value measurement option for any of its financial assets or liabilities.

Adoption of FSP FIN 39-1— On April 30, 2007, the FASB issued FASB Staff Position (“FSP”) FIN 39-1,Amendment of FASB Interpretation No. (“FIN”) 39. The FSP amends GAAP to replace the terms “conditional contracts” and “exchange contracts” with the term “derivative instruments” as defined in SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. It also amends paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. QRCI adopted FSP FIN 39-1 on January 1, 2008 without significant impact.

Adoption of SFAS No. 162— In May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements in conformity with GAAP in the United States. This Statement is generally viewed as a necessary step in the ultimate convergence of global accounting rules. This Statement became effective on November 15, 2008, but had no impact on QRCI’s financial statements or related disclosures.

•

Pronouncements Not Yet Implemented

2. ACCOUNTS RECEIVABLE

Accounts receivable consisted of the following:


	As of December 31,
	2008		2007
	(In thousands)
Accrued production receivables	$	13,435	$	19,728
Joint interest receivables		15,386		16,150
Other receivables		348		2,770

	$	29,169	$	38,648

3. DERIVATIVES AND FAIR VALUE MEASUREMENTS

In accordance with the fair value hierarchy described in SFAS No. 157, the following table shows the fair value of QRCI’s financial assets and liabilities that are required to be measured at fair value as of December 31, 2008.


	Fair Value Measurements as of December 31, 2008
										Balance Sheet
	Level 1		Level 2		Level 3		Other⁽¹⁾			Total
	(in thousands)
Derivative assets	$	—	$	61,746	$	—	$	(2,501	)	$	59,245


Derivative liabilities	$	—	$	4,366	$	—	$	(2,501	)	$	1,865


⁽¹⁾		Represents amounts netted under master netting arrangements

The change in carrying value of QRCI’s derivatives and the contractual fixed-price sale commitments in the Company’s balance sheet since December 31, 2007 principally resulted from the decrease in market prices for natural gas to the prices in our derivative instruments and, to a lesser degree, from settlements made during 2008. The change in fair value of the effective portion of all cash flow hedges was reflected in accumulated other comprehensive income, net of deferred tax effects. QRCI recognized $2.5 million and $0.2 million of net gains in other revenue as the result of derivative hedge ineffectiveness for the years ended 2008 and 2007, respectively. QRCI had no gains or losses resulting from derivative hedge ineffectiveness during 2006.

The estimated fair values of all derivatives of QRCI as of December 31, 2008 and 2007 are provided below. The associated carrying values of these derivatives 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 where rights of offset exists.


	Asset Derivatives				Liability Derivatives
	December 31,				December 31,
	2008		2007		2008		2007
	(in thousands)				(in thousands)
Derivatives designated as hedging instruments under SFAS 133
Commodity contracts reported in:
Current derivative assets	$	61,746	$	1,643	$	2,501	$	1,224
Current derivative liabilities		—		—		1,865		—

Total derivatives designated as hedging instruments under SFAS 133	$	61,746	$	1,643	$	4,366	$	1,224

All hedge derivative assets and liabilities have been classified as current at December 31, 2008 based on the maturity of the derivative instruments, resulting in $38.8 million of after-tax gains expected to be reclassified from accumulated other comprehensive income in 2009.

The following table summarizes the open derivative positions that hedged QRCI’s natural gas production as of December 31, 2008:


					Weighted Avg Price Per
Product	Type	Contract Period	Volume		MMBtu⁽¹⁾			Fair Value
			(MMBtud)					(In thousands)
Gas	Swap	Jan 2009-Dec 2009		10,000	$	8.45		$	8,536
Gas	Swap	Jan 2009-Dec 2009		20,000		8.46			17,110
Gas	Collar	Jan 2009-Dec 2009		10,000		8.25-10.45			8,290
Gas	Collar	Jan 2009-Dec 2009		10,000		8.25-10.45			8,290
Gas	Collar	Jan 2009-Dec 2009		10,000		11.50-14.48			19,520
Gas	Basis	Jan 2009-Dec 2009		20,000		(2	)		(1,865	)
Gas	Basis	Jan 2009-Dec 2009		20,000		(2	)		(932	)
Gas	Basis	Jan 2009-Dec 2009		15,000		(2	)		(799	)
Gas	Basis	Jan 2009-Dec 2009		15,000		(2	)		(770	)

					Total			$	57,380


⁽¹⁾		“MMBtu” means million British Thermal Units, a measure of heating value

⁽²⁾		Basis swaps for 60,000 MMBtu per day hedge the AECO (a natural gas reference price for gas delivered onto NOVA Gas Transmission Ltd. System in Alberta, Canada) basis adjustment at a weighted average deduction of $0.84 per MMBtu from the New York Mercantile Exchange price for 2009.

4. OTHER CURRENT ASSETS

Other current assets consisted of the following:


	As of December 31,
	2008		2007
	(In thousands)
Spare parts and supplies	$	11,399	$	14,751
Prepaid expenses		1,664		3,988

	$	13,063	$	18,739

5. INVESTMENT IN EQUITY AFFILIATE

On February 4, 2008, QRCI sold its rights and interest in certain oil and gas leases, purchased by QRCI in November 2007, to 1373159 Alberta Ltd. (“1373159”) for consideration of 10 million fully paid, non-assessable, non-voting Series 1 Preferred Shares of 1373159 having an aggregate redemption price of approximately Canadian $30 million. In June 2008, QRCI sold its rights and interests in additional oil and gas leases, purchased by QRCI in March 2008, to 1373159 for consideration of 10 million fully paid, non-assessable, non-voting Series 2 Preferred Shares of 1373159, having an aggregate redemption price of approximately Canadian $53 million. Quicksilver owned 100% of 1373159, which was subsequently amalgamated by QRCI, effective January 1, 2009.

6. PROPERTY, PLANT AND EQUIPMENT

Property and equipment consisted of the following:


	December 31,			December 31,
	2008			2007
	(In thousands)
Oil and gas properties
Subject to depletion	$	547,249		$	616,192
Unevaluated costs		9,832			21,170
Accumulated depletion		(119,518	)		(103,961	)

Net oil and gas properties		437,563			533,401
Other plant and equipment
Pipelines and processing facilities		51,005			45,213
General properties		3,722			4,240
Accumulated depreciation		(12,142	)		(10,887	)

Net other property and equipment		42,585			38,566

Property, plant and equipment, net of accumulated depletion and depreciation	$	480,148		$	571,967

Unevaluated Natural Gas and Crude Oil Properties Excluded From Depletion

Under full cost accounting, QRCI excludes certain unevaluated costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of QRCI’s unevaluated properties excluded from natural gas and crude oil properties being amortized at December 31, 2008 and 2007 and the year in which they were incurred is as follows:


	December 31, 2008						December 31, 2007
	Costs Incurred During						Costs Incurred During
	2008		Prior		Total		2007		2006		2005		Prior		Total
	(In thousands)						(In thousands)
Acquisition costs	$	—	$	—	$	—	$	626	$	720	$	575	$	7,085	$	9,006
Exploration costs		9,218		—		9,218		12,164		—		—		—		12,164
Capitalized interest		614		—		614		—		—		—		—		—

Total	$	9,832	$	—	$	9,832	$	12,790	$	720	$	575	$	7,085	$	21,170

Capitalized Costs

Capitalized overhead costs that directly relate to QRCI’s exploration and development activities were $4.4 million, $4.6 million and $1.4 million for the years ended December 31, 2008, 2007 and 2006, respectively.

7. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:


	As of December 31,
	2008		2007
	(In thousands)
Accrued operating expenses	$	3,881	$	5,985
Accrued capital expenditures		—		11,417
Revenue payable		2,887		3,545
Prepayments from partners		844		732

	$	7,612	$	21,679

8. LONG-TERM DEBT

Quicksilver’s Senior Secured Credit Facility matures February 9, 2012, but has the option for Quicksilver to extend the maturity up to two additional years with lender approval. The facility provides for revolving loans, swingline loans and letters of credit from time to time in an aggregate amount not to exceed the borrowing base, which is calculated based on several factors. The borrowing base is subject to at least annual redeterminations. In September 2008, the lenders agreed to a borrowing base of $1.2 billion. The lenders also agreed to $1.2 billion of revolving credit commitments and, with lender approval, the Company has an option to increase the facility to $1.45 billion. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. currency available for borrowing by U.S. subsidiaries and either U.S. or Canadian currency available for borrowing by QRCI. QRCI borrowings under the facility are guaranteed by Quicksilver and most of Quicksilver’s domestic subsidiaries and are secured by, among other things, QRCI’s, Quicksilver’s and certain of Quicksilver’s domestic subsidiaries’ oil and gas properties and quantities of proved reserves of natural gas, NGLs and crude oil attributable to them.

At December 31, 2008, QRCI’s allocated borrowing base was $300 million with approximately $45 million of available borrowing capacity. All interest accrued on the facility must be paid quarterly, but there is no fixed payment schedule. Borrowings under the facility bear interest at the lender’s prime rate. In April 2009, the lenders affirmed Quicksilver’s borrowing base at $1.2 billion and the interest spreads under the facility were revised upward. QRCI’s portion of the borrowing base remained at $300 million.

9. ASSET RETIREMENT OBLIGATIONS

QRCI records the fair value of the liability for asset retirement obligations in the period in which it is legally or contractually incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is recognized as expense through depletion or depreciation 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 estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted fair value to its estimated settlement value.

The following table provides a reconciliation of the changes in the estimated asset retirement obligation from January 1, 2007 through December 31, 2008.


	December 31,			December 31,
	2008			2007
	(In thousands)
Beginning asset retirement obligations	$	14,278		$	10,117
Incremental liability incurred		1,651			1,586
Accretion expense		830			664
Change in estimates		3,928			—
Currency translation adjustment		(3,079	)		1,911

Ending asset retirement obligations	$	17,608		$	14,278

10. INCOME TAXES

Tax rate reductions were enacted during 2007 and 2006 by the Canadian federal government and by Alberta Province. The Company’s Canadian deferred income tax balances were revalued to reflect the changes in these tax rates. The Company recorded $6.3 million and $3.2 million of income tax benefits in 2007 and 2006, respectively, as a result of the enactment of Canadian rate reductions. No further rate changes were enacted in 2008. Significant components of the QRCI’s deferred tax assets and liabilities as of December 31, 2008 and 2007 are as follows:


	As of December 31,
	2008		2007
	(In thousands)
Current
Deferred tax liability on cash flow hedge gains	$	15,843	$	62


Non-current
Deferred tax assets
Net operating loss carry forwards	$	1,644	$	2,033

Total deferred tax assets		1,644		2,033

Deferred tax liabilities
Property, plant and equipment		57,858		48,498
Other		734		107

Total deferred tax liabilities		58,592		48,605

Net deferred tax liabilities	$	56,948	$	46,572

The components of income tax expense for 2008, 2007 and 2006 are as follows:


	2008		2007		2006
	(In thousands)
Current income tax expense	$	—	$	—	$	—
Deferred income tax expense		21,938		11,129		8,777

Total income tax expense	$	21,938	$	11,129	$	8,777

The following table reconciles the statutory federal income tax rate to the effective tax rate for 2008, 2007 and 2006


	2008			2007			2006
Income taxes at statutory rate		29.00	%		32.12	%		34.12	%
Enacted future federal rate reductions		(3.96	%)		(7.08	%)		(5.12	%)
Enacted future rate reductions effects for prior years		—			(9.35	%)		(6.62	%)
Permanent differences		1.44	%		0.77	%		(4.48	%)
Other		(0.12	%)		—			—

Effective income tax rate		26.36	%		16.46	%		17.90	%

11. RELATED PARTY TRANSACTIONS

QRCI pays Quicksilver for allocations of general and administrative expenses and salary, travel costs and other invoices paid by Quicksilver on the Company’s behalf. During 2008, 2007 and 2006, QRCI paid Quicksilver $3.7 million, $2.5 million and $1.8 million for its portion of general and administrative expenses allocated by Quicksilver. Amounts required for settlement of QRCI’s financial derivatives are paid or received and subsequently settled between Quicksilver and the Company. During 2008, QRCI paid Quicksilver $0.2 million for settlement of derivatives. For 2007 and 2006, Quicksilver paid QRCI $25.6 million and $9.7 million for these settlements. In 2007, QRCI received $11.5 million for the sales of natural gas to Quicksilver. All related party transactions occur in the normal course of business.

12. EMPLOYEE BENEFITS

QRCI has a retirement plan available to all Canadian employees. The plan provides for a match of employees’ contributions by the Company and a fixed annual contribution. Expenses associated with QRCI contributions were $0.8 million, $0.7 million and $0.5 million for 2008, 2007 and 2006, respectively.

13. COMMITMENTS AND CONTINGENCIES

QRCI leases office space and other property under operating leases. Future minimum lease payments, for operating leases with initial non-cancelable lease terms in excess of one year as of December 31, 2008, were as follows:


in thousands
2009	$	1,246
2010		369
2011		41
Thereafter		—

	$	1,656

Rent expense for operating leases with terms exceeding one month was $1.8 million in 2008, $1.5 million in 2007 and $0.9 million in 2006.

QRCI had approximately $2.6 million in letters of credit to fulfill contractual, legal or regulatory requirements. All letters of credit have annual renewable options.

QRCI is involved in various claims arising in the normal course of business. While the outcome of these matters is uncertain there can be no assurance that such matter will be resolved in the Company’s favor. QRCI does not currently believe that a material adverse outcome is likely related to these matters.

14. STOCKHOLDER’S EQUITY


	Shares		Book
	Issued		Value
			(In thousands)
Unlimited number of Class A common voting shares		—	$	—
Unlimited number of Class B common voting shares		2,495,646		1,785
Unlimited number of Class C common non-voting, exchangeable shares		394,482		32

Balance at December 31, 2008 and 2007		2,890,128	$	1,817

QRCI Class C common shares are exchangeable on a one-for-one basis for Quicksilver common shares. Class C common shares are entitled to preference over the Class B common shares upon certain events of liquidation or distribution of the assets of the Company.

Paid in capital in excess of par value at December 31, 2008 and 2007 is comprised of $2.1 million relating to the acquisition of the remaining non-controlling interest in the Company (10.2%) by Quicksilver in 2000, and cash of $26.0 million contributed by Quicksilver.

15. SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for interest and income taxes is as follows:


	Years Ended December 31,
	2008		2007		2006
	(In thousands)
Interest	$	14,374	$	15,547	$	13,004
Income taxes		—		—		—

Other significant non-cash transactions are as follows:


	Years Ended December 31,
	2008		2007		2006
	(In thousands)
Working capital related to acquisition of property, plant and equipment		16,450	$	19,653	$	39,189
Preferred interests in 1373159 Alberta Ltd.		82,542		—		—

16. SUBSEQUENT EVENT

Under the full cost method in accounting for oil and gas properties, QRCI must perform a quarterly ceiling test for its country-wide cost center. In determining the ceiling limitation, the ceiling test incorporates pricing, costs and discount rates over which management has no influence. The 2009 first quarter Canadian ceiling amount was computed using a natural gas benchmark price of $2.92 per MMBtu and the mandated 10% discount rate. Upon calculation of the present value of QRCI’s natural gas reserves, including its hedge derivatives, the carrying value of its oil and gas properties exceeded the ceiling limit by $109.6 million (pre-tax) which was recorded in the first quarter of 2009.

COWTOWN PIPELINE FUNDING, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



Independent Auditors’ Report

Consolidated Statements of Income for the Years Ended December 31, 2008, 2007 and 2006

Consolidated Balance Sheets as of December 31, 2008 and 2007

Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006

Consolidated Statements of Changes in Stockholder’s Equity for the Years ended December 31, 2008, 2007 and 2006

Notes to Consolidated Financial Statements for the Years Ended December 31, 2008, 2007 and 2006

INDEPENDENT AUDITORS’ REPORT

To the Stockholders of
Cowtown Pipeline Funding, Inc.
Fort Worth, Texas

We have audited the accompanying consolidated balance sheets of Cowtown Pipeline Funding, Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, cash flows and changes in stockholder’s equity for each of the three years in the period ended December 31, 2008. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Cowtown Pipeline Funding, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas
May 29, 2009 (June 16, 2009 as to the effects of the adoption of SFAS 160 and the related disclosures in Notes 2, 8, and 10)

COWTOWN PIPELINE FUNDING, INC.

CONSOLIDATED STATEMENTS OF INCOME
In thousands


	Year Ended December 31,
	2008			2007			2006
Revenues
Gathering and transportation revenue — Quicksilver	$	36,061		$	15,089		$	6,460
Gathering and transportation revenue		6,118			1,773			53
Gas processing revenue — Quicksilver		30,127			16,564			7,342
Gas processing revenue		5,366			1,990			63
Other revenue — Quicksilver		900			525			—

Total revenues		78,572			35,941			13,918


Expenses
Operations and maintenance — Quicksilver		21,638			12,037			7,567
General and administrative — Quicksilver		6,407			3,379			1,278
Depreciation and accretion		15,134			8,146			2,999

Total expenses		43,179			23,562			11,844


Impairment Expense		9,200			—			—

Operating income		26,193			12,379			2,074

Other income		11			236			12
Interest expense		4,154			2,022			—


Income before income taxes		22,050			10,593			2,086

Income tax provision		7,861			3,591			730


Net income		14,189			7,002			1,356

Net income attributable to noncontrolling interests		(4,716	)		(1,092	)		(99	)

Net income attributable to Cowtown Pipeline Funding, Inc.	$	9,473		$	5,910		$	1,257

The accompanying notes are an integral part of these consolidated financial statements.

COWTOWN PIPELINE FUNDING, INC.

CONSOLIDATED BALANCE SHEETS
In thousands


	December 31,		December 31,
	2008		2007
ASSETS
Current assets
Cash and cash equivalents	$	303	$	1,125
Accounts receivable		2,245		882
Accounts receivable from Quicksilver		—		3,494
Prepaid expenses and other current assets		594		690

Total current assets		3,142		6,191

Properties, plant and equipment, net		489,893		284,885
Deferred tax asset		—		5,979
Other assets		1,916		965

	$	494,951	$	298,020


LIABILITIES AND EQUITY
Current liabilities
Current maturities of debt	$	1,375	$	1,100
Accounts payable to Quicksilver		12,173		9,079
Accrued additions to property, plant and equipment		17,433		23,624
Accounts payable and other		1,930		2,425
Current tax payable		10,844		10,844

Total current liabilities		43,755		47,072

Long-term debt		174,900		5,000
Note payable to Quicksilver		52,271		50,569
Asset retirement obligations		5,234		2,793
Deferred income tax liability		1,882		—

Commitments and contingent liabilities (Note 7)

Common stock		1		1
Additional paid in capital		171,150		153,561
Retained earnings		17,656		8,183

Cowtown Pipeline Funding Inc. equity		188,807		161,745
Noncontrolling interests		28,102		30,841

Total equity		216,909		192,586

	$	494,951	$	298,020

The accompanying notes are an integral part of these consolidated financial statements.

COWTOWN PIPELINE FUNDING, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands


	Year Ended December 31,
	2008			2007			2006
Operating activities:
Net income	$	14,189		$	7,002		$	1,356
Items included in net income not affecting cash:
Depreciation		14,950			8,063			2,978
Impairment of midstream assets		9,200			—			—
Accretion of asset retirement obligation		184			83			21
Deferred income taxes		7,861			3,591			730
Equity-based compensation		1,017			130			—
Amortization of debt issuance costs		243			88			—
Non-cash interest expense		2,802			1,669			—
Changes in assets and liabilities:
Accounts receivable		(1,363	)		(815	)		(66	)
Prepaid expenses and other assets		(612	)		(543	)		(146	)
Accounts receivable from Quicksilver		4,707			(6,046	)		—
Accounts payable and other		(495	)		1,131			1,138

Net cash provided by operating activities		52,683			14,353			6,011


Investing activities:
Capital expenditures		(148,079	)		(74,064	)		(77,539	)
Other		—			—			(821	)

Net cash used in investing activities		(148,079	)		(74,064	)		(78,360	)


Financing activities:
Proceeds from revolving credit facility borrowings		169,900			5,000			—
Debt issuance costs		(486	)		(1,041	)		—
Repayment of subordinated note payable to Quicksilver		(829	)		—			—
Net proceeds from issuance of equity units		—			112,298			—
Issuance costs of equity units paid		—			(2,933	)		—
Distribution to Quicksilver		(65,367	)		(115,074	)		—
Contributions by Quicksilver		—			68,416			67,855
Contributions by noncontrolling interests		—			167			7,291
Distributions to noncontrolling interests		(8,644	)		(8,794	)		—

Net cash provided by financing activities		94,574			58,039			75,146


Net increase (decrease) in cash		(822	)		(1,672	)		2,797

Cash at beginning of period		1,125			2,797			—


Cash at end of period	$	303		$	1,125		$	2,797


Cash paid for interest	$	2,341			—			—
Cash paid for income taxes	$	332			—			—
Non-cash transactions:
Working capital related to capital expenditures	$	31,920		$	30,809		$	6,608
Debt issuance costs		—			(12	)		—
Cost in connection with the initial public offering		—			(275	)		—
Issuance of subordinated note payable to Quicksilver		—			50,000			—

The accompanying notes are an integral part of these consolidated financial statements.

COWTOWN PIPELINE FUNDING, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY
In thousands


	Cowtown Pipeline Funding Inc. Equity
			Retained		Additional Paid			Noncontrolling
	Common Stock		Earnings		In Capital			Interests			Total Equity
Balance at January 1, 2006	$	1	$	1,016	$	48,595		$	496		$	50,108
Contributions		—		—		71,685			7,970			79,655
Cash distributions to Quicksilver		—		—		(4,508	)		—			(4,508	)
Net income		—		1,257		—			99			1,356

Balance at December 31, 2006		1		2,273		115,772			8,565			126,611
Contributions		—		—		200,473			29,848			230,321
Reclass Quicksilver’s equity balance to receivable from Quicksilver		—		—		1,971			—			1,971
Distribution of subordinated note payable to Quicksilver		—		—		(50,000	)		—			(50,000	)
Cash distributions to Quicksilver		—		—		(114,655	)		—			(114,655	)
Cash distributions to noncontrolling interests		—		—		—			(8,794	)		(8,794	)
Equity-based compensation expense		—		—		—			130			130
Net income		—		5,910		—			1,092			7,002

Balance at December 31, 2007		1		8,183		153,561			30,841			192,586
Contributions		—		—		82,956			172			83,128
Cash distributions to Quicksilver		—		—		(65,367	)		—			(65,367	)
Cash distributions to noncontrolling interests		—		—		—			(8,644	)		(8,644	)
Equity-based compensation expense		—		—		—			1,017			1,017
Net income		—		9,473		—			4,716			14,189

Balance at December 31, 2008	$	1	$	17,656	$	171,150		$	28,102		$	216,909

The accompanying notes are an integral part of these consolidated financial statements.

COWTOWN PIPELINE FUNDING, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Description of Business— Cowtown Pipeline Funding, Inc. (“CPFI”) is a Delaware corporation that holds approximately 73% ownership of Quicksilver Resources Inc.’s (“Quicksilver”) interest in Quicksilver Gas Services LP (“KGS”).

CPFI also owns 99% of both Cowtown Pipeline L.P. (CPLP) and Cowtown Gas Processing L.P. (CGPLP), consolidating both entities. CPLP and CGPLP, in addition to owning the majority of KGS, are engaged in performing gathering and processing services for unaffiliated companies in the Delaware Basin in West Texas. Operations in West Texas accounted for less than 1% of CPFI consolidated revenues for all periods presented and are also immaterial to CPFI’s assets and cash flows. CPFI has no discrete operations but controls KGS and therefore the financials are consolidated and recognizes a noncontrolling interest.

KGS is engaged in gathering and processing natural gas and NGLs, produced from the Barnett Shale formation in the Fort Worth Basin located in North Texas. KGS provides services under contracts, whereby it receives fees for performing the gathering and processing services. KGS does not take title to the natural gas or associated NGLs that it gathers and processes therefore avoids direct commodity price exposure.

KGS’ assets include:

•

The Cowtown System, which includes:

	—		the Cowtown Pipeline, which consists of a pipeline gathering system and gas compression facilities in the southern portion of the Fort Worth Basin and gathers natural gas produced by KGS’ customers and delivers it for processing;

	—		the Cowtown Plant, in Hood County, Texas, which consists of two natural gas processing units that extract NGLs from the natural gas stream and deliver customers’ residue gas to unaffiliated pipelines for transport and sale downstream; and

	—		the Corvette Plant in Hood County, Texas, which was placed in service during the first quarter 2009, and consists of a natural gas processing unit that extracts NGLs from the natural gas stream and delivers KGS customers’ residue gas to unaffiliated pipelines for transport and sale downstream.

	•		The Lake Arlington Dry System, located in Tarrant County, Texas, which consists of a gathering system and a gas compression facility, which KGS purchased from Quicksilver in the fourth quarter of 2008. This system is connected to affiliated pipelines for transport and sale downstream.

	•		The West Texas System, which consists of a 12 mile gathering system and a dehydration facility with capacity up to 6MMcfd.

2. ADJUSTMENTS AND SIGNIFICANT ACCOUNTING POLICIES

Adjustment for Retrospective Application of SFAS No. 160

We have adjusted the financial statements and notes thereto for the years ended December 31, 2008, 2007 and 2006 to reflect our adoption of SFAS No. 160.

SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements

The following tables summarize the effect of retrospective adoption of SFAS No. 160:


	Statement of Income information for the years ended December 31,
	2008					2007					2006
	Originally		As			Originally		As			Originally		As
(amounts in 000’s)	Reported		Adjusted			Reported		Adjusted			Reported		Adjusted
Income before income taxes	$	22,050	$	22,050		$	10,593	$	10,593		$	2,086	$	2,086
Income tax provision		7,861		7,861			3,591		3,591			730		730
Minority interest		4,716		—			1,092		—			99		—
Net income		9,473		14,189			5,910		7,002			1,257		1,356
Net income attributable to noncontrolling interests		—		(4,716	)		—		(1,092	)		—		(99	)
Net income attributable to Cowtown Pipeline Funding, Inc.		—		9,473			—		5,910			—		1,257


	Balance Sheet information as of December 31,
	2008				2007
	Originally		As		Originally		As
	Reported		Adjusted		Reported		Adjusted
Minority interest liability	$	31,287	$	—	$	31,487	$	—
Total liabilities		386,763		278,042		216,237		105,434
Cowtown Pipeline Funding, Inc. equity		109,491		188,807		82,429		161,745
Noncontrolling interests		—		28,102		—		30,841
Total equity		109,491		216,909		82,429		192,586

Significant Accounting Policies

Basis of Presentation— The accompanying consolidated financial statements and related notes of CPFI present the financial position, results of operations, cash flows and changes in equity of CPFI. CPFI eliminates all inter-company balances and transactions in preparing consolidated financial statements.

Use of Estimates —The preparation of the financial statements in accordance with GAAP in the United States requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Although management believes the estimates are appropriate, actual results can differ from those estimates.

Cash and Cash Equivalents— CPFI considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash or cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Accounts receivable— Accounts receivable are due from Quicksilver and other independent natural gas producers. Each customer of CPFI is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although CPFI does not require collateral, appropriate credit ratings are required. Receivables are generally due within 60 days. At December 31, 2008 and 2007, CPFI recorded no allowance for uncollectible accounts receivable. During 2008, CPFI experienced no non-payment for its services.

Property, Plant and Equipment— Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.

The cost of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use.

Asset Retirement Obligations —CPFI records the discounted fair value of the liability for asset retirement obligations in the period in which it is legally or contractually 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 the initial measurement, the asset retirement cost is allocated to expense using a straight line method over the asset’s useful life. Changes in the liability for the asset retirement obligation are recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the estimated cash flows.

Impairment of Long-Lived Assets— CPFI reviews its long-lived assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for the asset to its estimated fair value if such carrying amount exceeds the fair value. At December 31, 2008, CPFI’s analysis of its estimated future cash flows resulted in CPFI recording an impairment of $9.2 million for the midstream assets in West Texas.

Other Assets— Other assets as of December 31, 2008 consist of costs associated with debt issuance and pipeline license agreements net of amortization. Other assets at December 31, 2007 consisted of cost associated with debt issuance net of amortization. Debt issuance costs are amortized over the term of the associated debt. Pipeline license agreements provide CPFI the right to construct, operate and maintain certain pipelines with local municipalities. The pipeline license agreements are amortized over the term of the agreement.

Environmental Liabilities— Liabilities for environmental loss contingencies, including environmental remediation costs, are charged to expense when it is probable that a liability has been incurred and the amount of the assessment or remediation can be reasonably estimated.

Revenue Recognition— CPFI’s primary service offerings are the gathering and processing of natural gas. CPFI’s subsidiaries have contracts under which they receive revenues based on the volume of natural gas gathered and processed. CPFI recognizes revenue when all of the following criteria are met:

	•		persuasive evidence of an exchange arrangement exists;

	•		services have been rendered;

	•		the price for its services is fixed or determinable; and

	•		collectability is reasonably assured.

Income Taxes— CPFI is subject to federal income taxes and recognizes the impact of tax on temporary differences between the book and the tax basics of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that we expect will be in effect during years in which we expect the temporary differences will reverse. 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.

Segment Information— CPFI operates solely in the midstream segment in Texas where it provides natural gas gathering, transportation and processing services.

Fair Value of Financial Instruments —The fair value of accounts receivable, accounts payable, long-term debt and the note payable to Quicksilver approximate their carrying amounts.

such that the vested portion of the liability is adjusted to reflect revised fair value through compensation expense. Phantom unit awards payable in units are valued at the closing market price of KGS common units on the date of grant. The unearned compensation is amortized to compensation expense over the vesting period of the phantom unit award.

Recently Issued Accounting Standards

•

Pronouncements Implemented

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements(“SFAS 157”), which defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. The Statement applies under other accounting pronouncements that require or permit fair value measurements. No new requirements are included in SFAS No. 157, but application of the Statement has changed current practice. CPFI adopted SFAS No. 157 on January 1, 2008 with no impact.

In February 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 that were not previously required to be measured at fair value. While SFAS No. 159 became effective on January 1, 2008, CPFI did not elect the fair value measurement option for any of its financial assets or liabilities.

In May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements in conformity with GAAP in the United States. This Statement is generally viewed as a necessary step in the ultimate convergence of global accounting rules. This Statement became effective on November 15, 2008 and was adopted by CPFI with no significant impact on our financial statements or related disclosures.

•

Pronouncements Not Yet Implemented

SFAS No. 141(R) (revised 2007),Business Combinations, was issued in December 2007. SFAS No. 141(R) replaces SFAS No. 141,Business Combinations, while retaining its fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) defines the acquirer as the entity that obtains control in the business combination and it establishes the criteria to determine the acquisition date. The Statement also requires an acquirer to recognize the assets acquired and liabilities assumed measured at their fair values as of the acquisition date. In addition, acquisition costs are required to be recognized as period expenses as incurred. The Statement will apply to any acquisition completed by CPFI after January 1, 2009, but otherwise had no effect on our financial statements upon adoption.

In May 2008, the FASB issued Staff Position APB 14-1,Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)(“FSP APB 14-1”), which indicates that issuers of convertible debt instruments generally should separately account for the liability component at its fair value and may result in amounts previously reported as debt being reclassified to equity. Furthermore, interest expense in periods subsequent to issuance may increase if the amount of reported debt changes. We adopted FSP APB 14-1 on January 1, 2009 with no impact to 2009 or previously reported results.

3. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist of the following:


		December 31,
	Depreciable Life	2008			2007
		(in thousands)
Gathering and transportation systems	20 years	$	187,832		$	114,618
Processing plants	20-25 years		160,404			120,477
Construction in progress — plant			106,563			12,636
Construction in progress — pipeline			27,994			20,046
Rights-of-way and easements	20 years		39,834			26,905
Land			1,239			952
Buildings and other	20-40 years		1,836			910

			525,702			296,544
Accumulated Depreciation			(35,809	)		(11,659	)

Net property, plant and equipment		$	489,893		$	284,885

Construction in progress – plant reflects the construction of the Corvette Plant, a processing plant and compression facility attached to the Cowtown Pipeline, which was placed in service during the first quarter of 2009.

4. ACCOUNTS PAYABLE AND OTHER

Accounts payable and other consists of the following:


	December 31,
	2008		2007
	(in thousands)
Accrued operating expenses	$	957	$	882
Accrued property taxes		—		895
Equity compensation payable		116		275
Interest payable		734		147
Other		123		226

	$	1,930	$	2,425

5. LONG-TERM DEBT

The following table summarizes our long-term debt payments due by period:


	Payments Due by Period
Long-Term Debt	Total		2009		2010-2012		2013-2014		Thereafter
					(in millions)
Credit Agreement	$	174.9	$	—	$	174.9	$	—	$	—
Subordinated Note to Quicksilver		53.6		1.4		3.3		48.9		—

Total long-term debt	$	228.5	$	1.4	$	178.2	$	48.9	$	—

Credit Agreement— On August 10, 2007, KGS entered into a five-year $150 million senior secured revolving credit facility (“Credit Agreement”). The Credit Agreement featured an accordion option that with lenders approval increases the facility up to $250 million. On October 10, 2008, the lenders approved an increase of the facility to $235 million. Also, the revised Credit Agreement permits the future expansion of the facility to $350 million, with lender approval. The facility, which matures August 10, 2012, can be extended up to two additional years with requisite lender consent.

The Credit Agreement provides for revolving credit loans, swingline loans and letters of credit. Borrowings under the facility are guaranteed by KGS’ subsidiaries and are secured by substantially all of the assets of KGS and its subsidiaries. KGS has both LIBOR and U.S. prime rate options for revolving loans and a specified rate for swingline loans.

The Credit Agreement contains certain covenants which can limit KGS’ borrowing capacity. All of the covenants exclude the subordinated note payable to Quicksilver and KGS’ obligations to Quicksilver and related non-cash interest. These financial covenants are summarized below:


Quarters Ended	Maximum Debt to EBITDA	Minimum EBITDA to Interest
December 31, 2008 and thereafter	4.50 to 1	2.50 to 1

At December 31, 2008, the lenders’ commitments under our credit agreement were $235 million and may be further increased to as much as $350 million. Based on our results through December 31, 2008, our total borrowing capacity is $235 million and our borrowings were $174.9 million, and the weighted average interest rate was 2.9%. The Credit Agreement contains restrictive covenants that prohibit the declaration or payment of distributions by KGS if a default then exists or would result therefrom, and otherwise limits the amount of distributions that KGS can make. In the event of default, the Credit Agreement allows for the acceleration of the loans, the termination of the credit agreement and foreclosure on collateral.

Subordinated Note— On August 10, 2007, KGS executed a subordinated promissory note (the “Subordinated Note”) payable to Quicksilver in the principal amount of $50.0 million.

The Subordinated Note accrues interest based upon the rate applicable to borrowings under the Credit Agreement plus 1%, which is locked at the time of borrowing. The interest rate at December 31, 2008 was 4.485%. Accrued and unpaid interest is payable quarterly on the last business day of each calendar quarter, beginning on March 31, 2008, and on the Subordinated Note’s maturity date described below. Quarterly interest may be paid in cash or by adding it to the outstanding principal balance of the Subordinated Note. Subject to certain restrictions, quarterly installments of $275,000 are payable on the last business day of each calendar quarter. The final payment is due on February 10, 2013. However, if the maturity date of the Credit Agreement is extended, the maturity date of the Subordinated Note will also be automatically extended to the date that is six months after the revised Credit Agreement maturity date. Amounts payable under the Subordinated Note may at all times, at Quicksilver’s election, be paid, in whole or in part, using KGS units. The Subordinated Note contains events of default that permit, among other things, the acceleration of the debt (unless otherwise prohibited pursuant to the subordination provisions described below). Such events of default include, but are not limited to, payment defaults under the Subordinated Note, the breach of certain covenants after applicable grace periods and the occurrence of an event of default under the Credit Agreement.

Amounts due under the Subordinated Note are subordinated in right of payment to all of our obligations under the Credit Agreement. KGS is precluded from making any payments under the Subordinated Note if any of the following events exist or would result as of the date of the proposed Subordinated Note payment:

	•		an event of default under the revolving credit agreement;

	•		the existence of a pending judicial proceeding with respect to any event of default under the revolving credit agreement; or

	•		our ratio of total indebtedness (which includes the $50.0 million Subordinated Note) to EBITDA as of the end of the fiscal quarter immediately preceding the date of such payment was equal to or greater than 3.5 or would be greater than 3.5 after consideration of such payment.

Through December 31, 2008, we have made all scheduled quarterly interest payments at the end of each quarter by adding them to the principal of the Subordinated Note in accordance with its terms. Accordingly, interest expense of $2.8 million recognized during 2008 was added to the Subordinated Note. In 2008, we made three quarterly principal payments of the Subordinated Note for a total of $0.8 million. The fourth quarter principal payment was prevented by the indebtedness limitation on EBITDA described above.

6. ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the asset retirement obligation:


	Year Ended December 31,
	2008		2007
	(in thousands)
Beginning asset retirement obligations	$	2,793	$	503
Additional liability incurred		2,257		2,207
Accretion expense		184		83

Ending asset retirement obligations	$	5,234	$	2,793

As of December 31, 2008, no assets are legally restricted for use in settling asset retirement obligations.

7. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation— In February 2009, McGuffy Energy Services, L.P. (“McGuffy”) filed a lawsuit against KGS and subsequently added Quicksilver as a party. McGuffy alleges, among other things, claims for breach of contract, fraud and negligent misrepresentation arising from a written agreement by which McGuffy was retained to provide certain engineering and construction services for KGS’ Corvette Plant. McGuffy further seeks to foreclose on a $3.2 million lien that it filed on the Corvette Plant. KGS disputes the amounts claimed by McGuffy and asserts a number of defenses to McGuffy’s claims, including that payments to McGuffy must be withheld as demanded by McGuffy’s unpaid subcontractors. In March 2009, KGS filed a lawsuit against McGuffy seeking damages and declaratory relief for the disputes between KGS and McGuffy. The McGuffy subcontractors that made demands on KGS were also named as parties. Several of the subcontractor defendants have filed counterclaims against KGS seeking to foreclose on their purported liens. Through March 31, 2009 KGS had recognized $2.0 million of the disputed amounts as a part of the Corvette Plant construction costs. KGS intends to vigorously defend this matter and does not expect its outcome to have a material adverse effect on our financial condition or results of operation.

Casualties or Other Risks— Quicksilver maintains coverage in various insurance programs on CPFI’s behalf, which provides it with property damage, business interruption and other coverage’s which are customary for the nature and scope of its operations.

Management of the general partner believes that Quicksilver and CPFI has adequate insurance coverage, although insurance will not cover every type of loss that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially and, in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Quicksilver may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. KGS maintains its own general partners’ liability insurance policy separate from the directors and officers policy maintained by Quicksilver.

If CPFI or its subsidiaries were to incur a significant loss for which they were was not fully insured, the loss could have a material impact on the consolidated financial position and results of operations. In addition, the proceeds of any available insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by CPFI, or which causes CPFI to make significant expenditures not covered by insurance, could reduce its ability to meet its financial obligations.

Regulatory Compliance— In the ordinary course of business, CPFI and it subsidiaries are subject to various laws and regulations. In the opinion of CPFI’s management, compliance with current laws and regulations will not have a material adverse effect on CPFI’s financial position or results of operations.

Environmental Compliance— The operation of CPFI’ pipelines, plants and other facilities is subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner or operator of these facilities, CPFI must comply with laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating CPFI’ facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At December 31, 2008, CPFI had no liabilities recorded for environmental matters.

Commitments— CPFI, through its subsidiaries, has entered into agreements with third parties providing for natural gas compression equipment and the construction of the Corvette plant, which was placed in service during the first quarter of 2009.

The following table summarizes CPFI’ contractual obligations:


	Payments Due by Period
Contractual Obligations	Total		2009		2010-2012		2013-2014		Thereafter
					(in millions)
Construction commitments	$	13.8	$	13.8	$	—	$	—	$	—

Total contractual obligations	$	13.8	$	13.8	$	—	$	—	$	—

8. INCOME TAXES

CPFI recognized income tax at the federal statutory income tax rate of 35%. CPFI is also subject to the Texas margin tax rate of 1% beginning in 2007. As the tax base for computing Texas margin tax is derived from an income-based measure, the Company recognizes this tax as an income tax. Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2008 and 2007 are as follows:


	As of December 31,
	2008		2007
	(In thousands)
Non-current
Deferred tax assets
Deferred tax benefit (liability) on partnership income	$	—	$	5,979

Total deferred tax assets	$	—	$	5,979

Deferred tax liabilities
Deferred tax liabilities on partnership income	$	1,882	$	—

Total deferred tax liabilities	$	1,882	$	—

The components of income tax expense for 2008, 2007 and 2006 are as follows:


	2008		2007			2006
			(In thousands)
Current state income tax expense	$	—	$	371		$	—
Current U.S. federal income tax expense		—		10,273			—


Total current income tax expense		—		10,644			—


Deferred state income tax expense (benefit)		221		(265	)		—
Deferred U.S. federal income tax expense (benefit)		7,640		(6,788	)		730


Total deferred income tax expense (benefit)		7,861		(7,053	)		730

Total income tax expense	$	7,861	$	3,591		$	730

The following table reconciles the statutory federal income tax rate to the effective tax rate for 2008, 2007 and 2006:


	2008			2007			2006
U.S. federal statutory tax rate		35.00	%		35.00	%		35.00	%
State income taxes net of federal deduction		0.65	%		(1.10	)%		0.00	%


Effective income tax rate		35.65	%		33.90	%		35.00	%

9. EQUITY PLAN


	Payable in cash					Payable in units
				Weighted					Weighted
				Average					Average
				Grant Date					Grant Date
	Units			Fair Value		Units			Fair Value
Unvested phantom units — January 1, 2008		84,961		$	21.36		9,833		$	21.36

Vested		(28,247	)		21.43		(6,089	)		21.36
Issued		6,605			24.12		137,148			25.25
Cancelled		(3,000	)		21.36		(974	)		25.25

Unvested phantom units — December 31, 2008		60,319		$	21.63		139,918		$	25.15

At January 1, 2008, total unvested compensation cost was $1.9 million related to unvested phantom units. Compensation expense of approximately $1.4 million was recognized during 2008, including $0.4 million for remeasuring the vested portion of awards to be settled in cash to their revised fair value. Grants of phantom units during the year ended December 31, 2008 had an estimated grant date fair value of $3.6 million. Unearned compensation expense of $2.3 million at December 31, 2008 will be recognized in expense over the next 1.9 years. Phantom units that vested during the year ended December 31, 2008 had a fair value of $0.7 million on their vesting date.

10. NONCONTROLLING INTERESTS

CPFI owns a 99% limited partnership interest in CPLP and CGPLP and consolidates these entities into its financial statements. Cowtown Pipeline Management Inc. (“CPMI”) owns a 1% general partner interest of both CPLP and CGPLP, as a result, the carrying value of CPMI’s ownership is reflected as a component of noncontrolling interests.

As a result of the KGS IPO, the outside ownership of KGS increased and therefore consolidated KGS’ financial position and results of operations and recognized noncontrolling interests’ equity for that portion of KGS that is owned by entities not affiliated with Quicksilver.

11. TRANSACTIONS WITH RELATED PARTIES

Upon completion of, or in connection with, its IPO, KGS entered into a number of agreements with related parties. A description of those agreements follows:

Omnibus Agreement— On August 10, 2007, KGS entered into an omnibus agreement (the “Omnibus Agreement”) with Quicksilver, which addresses, among other matters:

	•		restrictions on Quicksilver’s ability to engage in midstream business activities in Quicksilver Counties;

	•		Obligation to reimburse Quicksilver for all general and administrative expenses incurred by them on behalf of KGS; and

	•		Quicksilver’s obligation to provide cross-indemnification for certain liabilities.

Secondment Agreement— On August 10, 2007, Quicksilver and KGS’ general partner entered into a services and secondment agreement (the “Secondment Agreement”) pursuant to which specified employees of Quicksilver have been seconded to KGS’ general partner to provide operating, routine maintenance and other services with respect to the assets owned or operated by KGS. Under the Secondment Agreement, the general partner reimburses Quicksilver for the services provided by the seconded employees. The initial term of the Secondment Agreement is 10 years, but will extend for additional annual periods unless cancelled by either party with 180 days’ written notice.

Gas Gathering and Processing Agreement— On August 10, 2007, Quicksilver, Cowtown Gas Processing Partners LP (“Processing Partners”) and Cowtown Pipeline Partners LP (“Pipeline Partners”) together with Processing Partners (the “Cowtown Partnerships”) entered into the Fifth Amended and Restated Gas Gathering and Processing Agreement. In connection with the IPO, Processing Partners and Pipeline Partners became indirect wholly-owned subsidiaries of KGS. Under the Gas Gathering and Processing Agreement, Quicksilver has agreed, for an initial term of 10 years, to dedicate and deliver for processing all of the natural gas produced on properties operated by Quicksilver within the Quicksilver Counties. The dedication does not oblige Quicksilver to develop the reserves subject to the Gas Gathering and Processing Agreement.

Effective September 1, 2008, Quicksilver and KGS entered into the Sixth Amended and Restated Gas Gathering and Processing Agreement, which amended the previous agreement by specifying that Quicksilver has agreed to pay $0.4163 per MMBtu gathered and $0.5204 per MMBtu processed and a compression fee of up to $0.30 per MMBtu on the Cowtown System. The compression fee payable by Quicksilver at a gathering system delivery point shall never be less than KGS’ actual cost to perform such compression service. Quicksilver may also pay KGS a treating fee based on carbon dioxide content at the pipeline entry point. The rates above are each subject to an annual inflationary escalation.

If KGS determines that the gathering or processing of Quicksilver’s production becomes uneconomical, KGS may cease gathering and processing Quicksilver’s production as long as the uneconomical conditions exist. If KGS is unable to provide either gathering or processing services, Quicksilver may use other providers. If KGS is unable to provide either gathering or processing services for a period of 60 consecutive days, for reasons other than force majeure, causing Quicksilver’s wells to be shut-in (in the case of gathering) or resulting in Quicksilver’s inability to by-pass the Cowtown Plant and deliver its natural gas production to an alternative pipeline (in the case of processing), Quicksilver has the right to terminate the Gas Gathering and Processing Agreement as it relates to the affected gas.

Absent written notice of termination, the Gas Gathering and Processing Agreement is automatically renewed for one year periods. In addition, if the Gas Gathering and Processing Agreement, or performance under this agreement, becomes subject to FERC jurisdiction, the agreement would be terminated unless both parties agree to continue the agreement.

During the second quarter of 2008, KGS agreed to purchase land and a warehouse located in Hood County, Texas, from Quicksilver for a purchase price of $0.3 million and the reimbursement to Quicksilver of $0.6 million of costs. KGS also obtained additional easement rights for a total cost of $0.2 million from an affiliate of an entity that beneficially owns a small portion of KGS’ outstanding units.

Contribution, Conveyance and Assumption Agreement— On August 10, 2007 KGS entered into a contribution, conveyance, and assumption agreement (“Contribution Agreement”) with its general partner, certain other affiliates of Quicksilver and the private investors. The following transactions, among others, occurred just prior to the KGS IPO pursuant to the Contribution Agreement:

	•		the transfer of all of the interests of certain entities to KGS and its subsidiaries;

	•		the issuance of the incentive distribution rights to the general partner and the continuation of its 2% general partner interest in KGS;

	•		KGS’ issuance of 5,696,752 common units, 11,513,625 subordinated units and the right to receive $162.1 million, to Holdings in exchange for the contributed interests; and

	•		KGS’ issuance of 816,873 common units and the right to receive $7.7 million to private investors in exchange for their contributed interests.

Centralized cash management— As of December 31, 2008 revenues settled with Quicksilver and other customers, net of expenses paid by Quicksilver on behalf of KGS, are reflected as a receivable from or a payable to Quicksilver on the consolidated balance sheets and as a reduction of net cash provided by or used by operating activities on the consolidated statements of cash flows.

Services to affiliates— KGS routinely conducts business with Quicksilver and its affiliates. The related transactions result primarily from fee-based arrangements for gathering and processing of natural gas. Fees were determined based on fees to third parties and reflect the cost of providing such services. Quicksilver has engaged us to operate midstream assets owned by it for a monthly fee of $75,000.

Allocation of costs— The individuals supporting CPFI’s operating subsidiaries are employees of Quicksilver. CPFI’s consolidated financial statements include costs allocated to KGS by Quicksilver for centralized general and administrative services performed by Quicksilver, as well as depreciation of assets utilized by Quicksilver’s centralized general and administrative functions. Costs allocated to KGS are based on identification of Quicksilver’s resources which directly benefit KGS and its estimated usage of shared resources and functions. All of the allocations are based on assumptions that management believes are reasonable.

QUICKSILVER GAS SERVICES HOLDINGS LLC
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS




Independent Auditors’ Report
Consolidated Statements of Income for the Years Ended December 31, 2008, 2007 and 2006
Consolidated Balance Sheets as of December 31, 2008 and 2007
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006
Consolidated Statements of Changes in Members’ Capital for the Years ended December 31, 2008, 2007 and 2006
Notes to Consolidated Financial Statements for the Years Ended December 31, 2008, 2007 and 2006

INDEPENDENT AUDITORS’ REPORT

To the Members of
Quicksilver Gas Services Holdings LLC
Fort Worth, Texas

We have audited the accompanying consolidated balance sheets of Quicksilver Gas Services Holdings LLC and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, cash flows and changes in members’ capital for each of the three years in the period ended December 31, 2008. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Quicksilver Gas Services Holdings LLC and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas
May 29, 2009 (June 16, 2009 as to the effects of the adoption of SFAS 160 and the related disclosures in Notes 2 and 10)

QUICKSILVER GAS SERVICES HOLDINGS LLC

CONSOLIDATED STATEMENTS OF INCOME
In thousands


	Year Ended December 31,
	2008			2007			2006
Revenues
Gathering and transportation revenue — Quicksilver	$	36,061		$	15,089		$	6,460
Gathering and transportation revenue		5,612			1,773			53
Gas processing revenue — Quicksilver		30,127			16,564			7,342
Gas processing revenue		5,358			1,990			63
Other revenue — Quicksilver		900			525			—

Total revenues		78,058			35,941			13,918


Expenses
Operations and maintenance — Quicksilver		20,250			11,512			7,475
General and administrative — Quicksilver		6,407			3,379			937
Depreciation and accretion		14,566			8,070			2,963

Total expenses		41,223			22,961			11,375


Operating income		36,835			12,980			2,543

Other income		11			236			13
Interest expense		10,177			4,647			—


Income before income taxes		26,669			8,569			2,556

Income tax provision		253			313			135


Net income		26,416			8,256			2,421

Net income attributable to noncontrolling interests		(7,160	)		(1,304	)		(140	)

Net income attributable to Quicksilver Gas Services Holdings LLC	$	19,256		$	6,952		$	2,281

The accompanying notes are an integral part of these consolidated financial statements.

QUICKSILVER GAS SERVICES HOLDINGS LLC

CONSOLIDATED BALANCE SHEETS
In thousands


	December 31,		December 31,
	2008		2007
ASSETS
Current assets
Cash and cash equivalents	$	303	$	1,125
Accounts receivable		2,082		882
Accounts receivable from Quicksilver		—		800
Prepaid expenses and other current assets		594		690

Total current assets		2,979		3,497

Properties, plant and equipment, net		488,120		273,948
Other assets		1,916		965

	$	493,015	$	278,410


LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities
Current maturities of debt	$	1,375	$	1,100
Accounts payable to Quicksilver		10,502		—
Accrued additions to property, plant and equipment		17,433		23,624
Accounts payable and other		1,930		2,700

Total current liabilities		31,240		27,424

Long-term debt		174,900		5,000
Note payable to Quicksilver		52,271		50,569
Repurchase obligations to Quicksilver		123,298		82,251
Asset retirement obligations		5,234		2,793
Deferred income tax liability		369		173

Commitments and contingent liabilities (Note 7)
Net members’ capital (deficit)		75,836		79,862
Noncontrolling interests		29,867		30,338

Total equity		105,703		110,200

	$	493,015	$	278,410

The accompanying notes are an integral part of these consolidated financial statements.

QUICKSILVER GAS SERVICES HOLDINGS LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands


	Year Ended December 31,
	2008			2007			2006
Operating activities:
Net income	$	26,416		$	8,256		$	2,421
Items included in net income not affecting cash:
Depreciation		14,382			7,987			2,942
Accretion of asset retirement obligation		184			83			21
Deferred income taxes		196			38			135
Equity-based compensation		1,017			130			—
Amortization of debt issuance costs		243			88			—
Non-cash interest expense		8,825			4,294			—
Changes in assets and liabilities:
Accounts receivable		(1,200	)		(815	)		(66	)
Prepaid expenses and other assets		(612	)		(543	)		(146	)
Accounts receivable from Quicksilver		4,002			(5,975	)		—
Accounts payable and other		(770	)		1,406			1,138

Net cash provided by operating activities		52,683			14,949			6,445


Investing activities:
Capital expenditures		(148,079	)		(73,797	)		(77,539	)
Other		—			—			(821	)

Net cash used in investing activities		(148,079	)		(73,797	)		(78,360	)


Financing activities:
Proceeds from sale of assets to Quicksilver		—			29,508			—
Proceeds from revolving credit facility borrowings		169,900			5,000			—
Debt issuance costs		(486	)		(1,041	)		—
Repayment of repurchase obligation to Quicksilver		(42,085	)		—			—
Repayment of subordinated note payable to Quicksilver		(829	)		—			—
Net proceeds from sale of KGS units		—			112,298			—
Costs paid for sale of KGS units		—			(2,933	)		—
Distributions to Quicksilver		(23,282	)		(115,074	)		—
Contributions by Quicksilver		—			38,045			67,421
Contributions by noncontrolling interests		—			167			7,291
Distributions to noncontrolling interests		(8,644	)		(8,794	)		—

Net cash provided by financing activities		94,574			57,176			74,712


Net increase (decrease) in cash		(822	)		(1,672	)		2,797

Cash at beginning of period		1,125			2,797			—


Cash at end of period	$	303		$	1,125		$	2,797


Cash paid for interest	$	2,341			—			—
Cash paid for income taxes	$	332			—			—
Non-cash transactions:
Working capital related to capital expenditures	$	31,920		$	30,809		$	6,608
Debt issuance costs		—			(12	)		—
Cost in connection with the initial public offering		—			(275	)		—
Issuance of subordinated note payable to Quicksilver		—			50,000			—
Acquisition of property, plant and equipment under repurchase obligation	$	(77,108	)	$	(50,118	)	$	—

The accompanying notes are an integral part of these consolidated financial statements.

QUICKSILVER GAS SERVICES HOLDINGS LLC
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’ CAPITAL
In thousands


	Net Members’			Noncontrolling
	Capital			Interests			Total
Balance at January 1, 2006	$	48,949		$	—		$	48,949
Contributions		71,930			7,291			79,221
Cash distributions to Quicksilver		(4,508	)		—			(4,508	)
Net income		2,281			140			2,421

Balance at December 31, 2006		118,652			7,431			126,083
Contributions		117,361			30,397			147,758
Distribution of subordinated note payable to Quicksilver		(50,000	)		—			(50,000	)
Reclass Quicksilver’s equity balance to receivable from Quicksilver		1,971			—			1,971
Cash distributions to Quicksilver		(115,074	)		—			(115,074	)
Cash distributions to noncontrolling interests		—			(8,794	)		(8,794	)
Equity-based compensation expense		—			—			—
Net income		6,952			1,304			8,256

Balance at December 31, 2007		79,862			30,338			110,200
Cash distributions to Quicksilver		(23,282	)		—			(23,282	)
Cash distributions to noncontrolling interests		—			(8,648	)		(8,648	)
Equity-based compensation expense		—			1,017			1,017
Net income		19,256			7,160			26,416

Balance at December 31, 2008	$	75,836		$	29,867		$	105,703

The accompanying notes are an integral part of these consolidated financial statements.

QUICKSILVER GAS SERVICES HOLDINGS LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization— Quicksilver Gas Services Holdings LLC (“KGSH”) is a Delaware limited liability corporation formed in January 2007 for the purpose of maintaining approximately 73% ownership of Quicksilver Resources Inc.’s (“Quicksilver”) interest in Quicksilver Gas Services, LP (“KGS”). KGSH is owned 50% by each of two entities which are each indirectly owned by Quicksilver.

KGSH has no discrete operations but controls KGS and therefore consolidates KGS’ financial position and results of operations and recognizes a noncontrolling interest for that portion of KGS that is owned by entities not affiliated with Quicksilver.

Description of Business— KGS is engaged in gathering and processing natural gas and NGLs, produced from the Barnett Shale formation in the Fort Worth Basin located in North Texas. KGS provides services under contracts, whereby it receives fees for performing the gathering and processing services. KGS does not take title to the natural gas or associated NGLs that it gathers and processes therefore avoids direct commodity price exposure.

KGSH’s assets consist solely of assets owned by KGS, whose assets include:

•

The Cowtown System, which includes:

	—		the Cowtown Pipeline, which consists of a pipeline gathering system and gas compression facilities in the southern portion of the Fort Worth Basin and gathers natural gas produced by KGS’ customers and delivers it for processing;

	—		the Cowtown Plant, in Hood County, Texas, which consists of two natural gas processing units that extract NGLs from the natural gas stream and deliver customers’ residue gas to unaffiliated pipelines for transport and sale downstream; and

	—		the Corvette Plant in Hood County, Texas, which was placed in service during the first quarter 2009, and consists of a natural gas processing unit that extracts NGLs from the natural gas stream and delivers KGS customers’ residue gas to unaffiliated pipelines for transport and sale downstream.

•

The Lake Arlington Dry System, located in Tarrant County, Texas, which consists of a gathering system and a gas compression facility, which KGS purchased from Quicksilver in the fourth quarter of 2008. This system is connected to affiliated pipelines for transport and sale downstream.

As more fully described in Note 2, KGSH’ financial statements also include the operations of a gathering system in Hill County, Texas (“Hill County Dry System”) that gathers production from the Fort Worth Basin and delivers it to unaffiliated pipelines for transport and sale downstream.

2. ADJUSTMENTS AND SIGNIFICANT ACCOUNTING POLICIES

Adjustment for Retrospective Application of SFAS No. 160

We have adjusted the financial statements and notes thereto for the years ended December 31, 2008, 2007 and 2006 to reflect our adoption of SFAS No. 160.

SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements

The following tables summarize the effect of retrospective adoption of SFAS No. 160:


	Statement of Income information for the years ended December 31,
	2008					2007					2006
	Originally		As			Originally		As			Originally		As
(amounts in 000’s)	Reported		Adjusted			Reported		Adjusted			Reported		Adjusted
Income before income taxes	$	26,669	$	26,669		$	8,569	$	8,569		$	2,556	$	2,556
Income tax provision		253		253			313		313			135		135
Minority interest		7,160		—			1,304		—			140		—
Net income		19,256		26,416			6,952		8,256			2,281		2,421
Net income attributable to noncontrolling interests		—		(7,160	)		—		(1,304	)		—		(140	)
Net income attributable to Quicksilver Gas Services Holdings LLC		—		19,256			—		6,952			—		2,281


	Balance Sheet information as of December 31,
	2008					2007
	Originally			As		Originally		As
	Reported			Adjusted		Reported		Adjusted
Minority interest liability	$	29,867		$	—	$	30,338	$	—
Total liabilities		496,495			387,312		277,864		168,210
Net members’ capital (deficit)		(3,480	)		75,836		546		79,862
Noncontrolling interests		—			29,867		—		30,338
Total equity		(3,480	)		105,703		546		110,200

Significant Accounting Policies

Basis of Presentation— The accompanying consolidated financial statements and related notes of KGSH present the financial position, results of operations, cash flows and changes in partners’ capital of KGS’ natural gas gathering and processing assets. The financial statements include historical cost-basis accounts of the assets of KGS Predecessor which were contributed to KGS through KGSH by Quicksilver and two private investors in connection with the KGS IPO.

Cash and Cash Equivalents— KGSH considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash or cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Accounts receivable— Accounts receivable are due from Quicksilver and other independent natural gas producers. Each customer of KGSH is reviewed as to credit worthiness prior to the extension of credit and on a regular basis

thereafter. Although KGSH does not require collateral, appropriate credit ratings are required. Receivables are generally due within 60 days. At December 31, 2008 and 2007, KGSH recorded no allowance for uncollectible accounts receivable. During 2008, KGSH experienced no non-payment for their services.

Asset Retirement Obligations —KGSH records the discounted fair value of the liability for asset retirement obligations in the period in which it is legally or contractually 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 the initial measurement, the asset retirement cost is allocated to expense using a straight line method over the asset’s useful life. Changes in the liability for the asset retirement obligation are recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the estimated cash flows.

Repurchase Obligations to Quicksilver —On June 5, 2007, KGSH sold several pipeline and gathering assets to Quicksilver. These assets consist of:

	•		a portion of the gathering lines in the Cowtown Pipeline;

	•		the Lake Arlington Dry System; and

	•		the Hill County Dry System.

At June 5, 2007, the assets were either constructed and in service or partially constructed. The selling price for these assets was approximately $29.5 million, which represented KGS Predecessor’s historical cost. KGS Predecessor collected the $29.5 million on August 9, 2007. All assets conveyed are or were subject to repurchase by KGS from Quicksilver as follows:

Cowtown Pipeline repurchase — KGS has the option to purchase portions of the Cowtown Pipeline from Quicksilver at their original cost in or before 2011 based upon the expected timing of their commerciality.

Lake Arlington Dry System repurchase — KGS was obligated to purchase the Lake Arlington Dry System from Quicksilver at its fair market value within two years after it was completed and commercial service commenced. During the fourth quarter 2008, KGS completed the acquisition of the Lake Arlington Dry System from Quicksilver for approximately $42 million. The purchase was financed through the use of the credit agreement and resulted in the reduction of the repurchase obligation. In conjunction with the purchase of the Lake Arlington Dry System, Quicksilver assigned its gas gathering agreement to KGS. Under the terms of that agreement, Quicksilver agreed to allow KGS to gather all of the natural gas produced by wells that it operated and from future wells operated by it within the Lake Arlington area through August 2017. Quicksilver’s fee of $0.62 per Mcf gathered by KGS in the Lake Arlington Dry System is subject to annual inflationary escalation.

Hill County Dry System repurchase — KGS is obligated to purchase the Hill County Dry System from Quicksilver at its fair market value in or before 2011 based upon the system’s expected timing of commerciality.

The following table summarizes the assets subject to KGS’ repurchase rights and obligations (in millions):


			Estimate of			Construction
			Construction			Costs Recognized		Repurchase
			Costs as of			through		obligation at
	June 5, 2007		December 31,			December 31,		December
	Sales Price		2008⁽¹⁾			2008		31, 2008		KGS Repurchase
Cowtown Pipeline	$	22.9	$	62.6		$	67.0	$	67.0	Optional at Cost
Lake Arlington Dry System		3.6		—	⁽²⁾		42.1		—	Repurchased at FV in 2008
Hill County Dry System		3.0		78.0			56.3		56.3	Obligatory at FV

	$	29.5	$	140.6		$	165.4	$	123.3


⁽¹⁾		Estimates may change based on changes in producers’ drilling progress, material and labor costs, easement costs and other factors

⁽²⁾		Excludes any estimated costs after completion of purchase

The assets’ conveyance was not treated as a sale for accounting purposes because KGS operates them and intends to purchase them. Accordingly, the original cost and subsequently incurred costs are recognized in both KGSH’s consolidated property, plant and equipment and its consolidated repurchase obligations to Quicksilver. Similarly, KGSH’s consolidated results of operations include the revenues and expenses for these operations. For 2008, KGSH recognized $6.0 million of interest expense associated with the repurchase obligations to Quicksilver based on a weighted-average interest rate of 5.2%.

Impairment of Long-Lived Assets— KGSH reviews its long-lived assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for the asset to its estimated fair value if such carrying amount exceeds the fair value. At December 31, 2008, KGSH performed an analysis of its estimated future cash flows and determined that there was no impairment on its long-lived assets.

Other Assets— Other assets as of December 31, 2008 consist of costs associated with debt issuance and pipeline license agreements net of amortization. Other assets at December 31, 2007 consisted of cost associated with debt issuance net of amortization. Debt issuance costs are amortized over the term of the associated debt. Pipeline license agreements provide KGSH the right to construct, operate and maintain certain pipelines with local municipalities. The pipeline license agreements are amortized over the term of the agreement.

Revenue Recognition— KGSH’s primary service offerings are the gathering and processing of natural gas. KGSH has contracts under which it receives revenues based on the volume of natural gas gathered and processed. KGSH recognizes revenue when all of the following criteria are met:

	•		persuasive evidence of an exchange arrangement exists;

	•		services have been rendered;

	•		the price for its services is fixed or determinable; and

	•		collectability is reasonably assured.

Income Taxes— KGSH is subject to a margin tax that requires tax payments at a maximum effective rate of 0.7% of the gross revenue apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires KGSH to recognize currently the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis. Under the margin tax, taxable entities that are part of an affiliated group engaged in a unitary business must file a combined group report. As a result, KGSH is included in a combined group report with Quicksilver and are allocated their proportionate share of the tax liability.

Segment Information— KGSH operates solely in the midstream segment in Texas where it provides natural gas gathering, transportation and processing services.

Fair Value of Financial Instruments —The fair value of accounts receivable, accounts payable, long-term debt, the note payable to Quicksilver and repurchase obligations to Quicksilver approximate their carrying amounts.

Equity Based Compensation —At time of issuance of phantom units, the Board of Directors of KGS determines whether they will be settled in cash or settled in KGS units. For awards payable in cash, KGSH amortizes the expense associated with the award over the vesting period. The liability for fair value is reassessed at every balance sheet date, such that the vested portion of the liability is adjusted to reflect revised fair value through compensation expense. Phantom unit awards payable in units are valued at the closing market price of KGS common units on the date of grant. The unearned compensation is amortized to compensation expense over the vesting period of the phantom unit award.

Recently Issued Accounting Standards

•

Pronouncements Implemented

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements(“SFAS 157”), which defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. The Statement applies under other accounting pronouncements that require or permit fair value measurements. No new requirements are included in SFAS No. 157, but application of the Statement has changed current practice. KGSH adopted SFAS No. 157 on January 1, 2008 with no impact.

In February 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 that were not previously required to be measured at fair value. While SFAS No. 159 became effective on January 1, 2008, KGSH did not elect the fair value measurement option for any of its financial assets or liabilities.

In May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements in conformity with GAAP in the United States. This Statement is generally viewed as a necessary step in the ultimate convergence of global accounting rules. This Statement became effective on November 15, 2008 and was adopted by KGSH with no significant impact on our financial statements or related disclosures.

•

Pronouncements Not Yet Implemented

SFAS No. 141(R) (revised 2007),Business Combinations, was issued in December 2007. SFAS No. 141(R) replaces SFAS No. 141,Business Combinations, while retaining its fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) defines the acquirer as the entity that obtains control in the business combination and it establishes the criteria to determine the acquisition date. The Statement also requires an acquirer to recognize the assets acquired and liabilities assumed measured at their fair values as of the acquisition date. In addition, acquisition costs are required to be recognized as period expenses as incurred. The Statement will apply to any acquisition completed by KGSH after January 1, 2009, but otherwise had no effect on our financial statements upon adoption.

3. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist of the following:


		December 31,
	Depreciable Life	2008			2007
		(in thousands)
Gathering and transportation systems	20 years	$	179,594		$	106,478
Processing plants	20-25 years		157,353			117,571
Construction in progress — plant			106,563			12,636
Construction in progress — pipeline			27,994			20,046
Rights-of-way and easements	20 years		39,473			26,905
Land			1,239			952
Buildings and other	20-40 years		1,836			910

			514,052			285,498
Accumulated Depreciation			(25,932	)		(11,550	)

Net property, plant and equipment		$	488,120		$	273,948

4. ACCOUNTS PAYABLE AND OTHER

Accounts payable and other consists of the following:


	December 31,
	2008		2007
	(in thousands)
Accrued operating expenses	$	957	$	882
Accrued property taxes		—		895
State income taxes		—		276
Equity compensation payable		116		275
Interest payable		734		147
Other		123		225

	$	1,930	$	2,700

5. LONG-TERM DEBT

The following table summarizes our long-term debt payments due by period:


	Payments Due by Period
Long-Term Debt	Total		2009		2010-2012		2013-2014		Thereafter
					(in millions)
Credit Agreement	$	174.9	$	—	$	174.9	$	—	$	—
Subordinated Note to Quicksilver		53.6		1.4		3.3		48.9		—

Total long-term debt	$	228.5	$	1.4	$	178.2	$	48.9	$	—


Quarters Ended	Maximum Debt to EBITDA	Minimum EBITDA to Interest
December 31, 2008 and thereafter	4.50 to 1	2.50 to 1

Subordinated Note— On August 10, 2007, KGS executed a subordinated promissory note (the “Subordinated Note”) payable to Quicksilver in the principal amount of $50.0 million.

	•		an event of default under the revolving credit agreement;

	•		the existence of a pending judicial proceeding with respect to any event of default under the revolving credit agreement; or

	•		our ratio of total indebtedness (which includes the $50.0 million Subordinated Note) to EBITDA as of the end of the fiscal quarter immediately preceding the date of such payment was equal to or greater than 3.5 or would be greater than 3.5 after consideration of such payment.

6. ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the asset retirement obligation:


	Year Ended December 31,
	2008		2007
	(in thousands)
Beginning asset retirement obligations	$	2,793	$	503
Additional liability incurred		2,257		2,207
Accretion expense		184		83

Ending asset retirement obligations	$	5,234	$	2,793

As of December 31, 2008, no assets are legally restricted for use in settling asset retirement obligations.

7. COMMITMENTS AND CONTINGENT LIABILITIES

Casualties or Other Risks— Quicksilver maintains coverage in various insurance programs on KGS’ and KGSH’s behalf, which provides them with property damage, business interruption and other coverage’s which are customary for the nature and scope of their operations.

Management of KGSH believes that there exists adequate insurance coverage, although insurance will not cover every type of loss that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially and, in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Quicksilver or KGSH may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. KGS maintains its own general partners’ liability insurance policy separate from the directors and officers policy maintained by Quicksilver.

If KGSH were to incur a significant loss for which they were not fully insured, the loss could have a material impact on KGSH’s consolidated financial position and results of operations. In addition, the proceeds of any available insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by KGSH, or which causes KGSH to make significant expenditures not covered by insurance, could reduce its ability to meet its financial obligations.

Regulatory Compliance— In the ordinary course of business, KGSH is subject to various laws and regulations. In the opinion of management of the general partner, compliance with current laws and regulations will not have a material adverse effect on KGSH’ financial condition or results of operations.

Environmental Compliance— The operation of pipelines, plants and other facilities is subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner or operator of these facilities, KGSH must comply with laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating KGSH’s facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At December 31, 2008, KGSH had no liabilities recorded for environmental matters.

Commitments— KGSH, through KGS, has entered into agreements with third parties providing for natural gas compression equipment and the construction of the Corvette plant, which was placed in service during the first quarter of 2009.

The following table summarizes KGSH’s consolidated contractual obligations:


	Payments Due by Period
Contractual Obligations	Total		2009		2010-2012		2013-2014		Thereafter
					(in millions)
Construction commitments	$	13.8	$	13.8	$	—	$	—	$	—

Total contractual obligations	$	13.8	$	13.8	$	—	$	—	$	—

8. INCOME TAXES

No provision for federal income taxes related to KGSH’s results of operations is included in the consolidated financial statements as such income is taxable only by KGSH’s partners and their owners.

Temporary differences relating to KGSH’ consolidated assets and liabilities will impact the provision for the Texas margin tax and a deferred tax liability has been recorded in the amount of $0.4 million and $0.2 million as of December 31, 2008 and 2007, respectively. KGSH derives all of its revenue from operations in Texas.

During the third quarter of 2008, KGSH paid $0.3 million related to its 2007 liability for Texas margin tax. Quicksilver does not expect to owe consolidated Texas margin tax for 2008 and, accordingly, KGSH does not expect to make a cash payment for its 2008 liability for Texas margin tax, based upon Texas filing rules. All effects of the 2008 Texas margin tax calculation are captured in deferred income taxes.

9. EQUITY PLAN


	Payable in cash					Payable in units
				Weighted					Weighted
				Average					Average
				Grant Date					Grant Date
	Units			Fair Value		Units			Fair Value
Unvested phantom units — January 1, 2008		84,961		$	21.36		9,833		$	21.36

Vested		(28,247	)		21.43		(6,089	)		21.36
Issued		6,605			24.12		137,148			25.25
Cancelled		(3,000	)		21.36		(974	)		25.25

Unvested phantom units — December 31, 2008		60,319		$	21.63		139,918		$	25.15

10. NONCONTROLLING INTERESTS

11. TRANSACTIONS WITH RELATED PARTIES

Upon completion of, or in connection with, its IPO, KGS entered into a number of agreements with related parties. A description of those agreements follows:

Omnibus Agreement— On August 10, 2007, KGS entered into an omnibus agreement (the “Omnibus Agreement”) with Quicksilver, which addresses, among other matters:

	•		restrictions on Quicksilver’s ability to engage in midstream business activities in Quicksilver Counties;

	•		Quicksilver’s construction of the Lake Arlington Dry System and the Hill County Dry System and the obligations to repurchase those assets from Quicksilver at their fair market value;

	•		Obligation to reimburse Quicksilver for all general and administrative expenses incurred by them on behalf of KGS; and

	•		Quicksilver’s obligation to provide cross-indemnification for certain liabilities.

	•		the transfer of all of the interests of certain entities to KGS and its subsidiaries;

	•		the issuance of the incentive distribution rights to the general partner and the continuation of its 2% general partner interest in KGS;

	•		KGS’ issuance of 5,696,752 common units, 11,513,625 subordinated units and the right to receive $162.1 million, to Holdings in exchange for the contributed interests; and

	•		KGS’ issuance of 816,873 common units and the right to receive $7.7 million to private investors in exchange for their contributed interests.

Centralized cash management— Prior to the IPO, revenues settled with Quicksilver and other customers, net of expenses paid by Quicksilver on behalf of KGS Predecessor, are reflected as equity activity on the consolidated balance sheets and as a reduction of net cash provided by financing activities on the consolidated statements of cash flows. Subsequent to the KGS IPO, revenues settled and expenses paid on behalf of KGS are settled in cash on a monthly basis utilizing KGS bank accounts. As of December 31, 2008 revenues settled with Quicksilver and other customers, net of expenses paid by Quicksilver on behalf of KGS, are reflected as a receivable from or a payable to Quicksilver on the consolidated balance sheets and as a reduction of net cash provided by or used by operating activities on the consolidated statements of cash flows.

Allocation of costs— The individuals supporting KGS operations are employees of Quicksilver. The consolidated financial statements include costs allocated to KGS by Quicksilver for centralized general and administrative services performed by Quicksilver, as well as depreciation of assets utilized by Quicksilver’s centralized general and administrative functions. Costs allocated to KGS are based on identification of Quicksilver’s resources which directly benefit KGS and its estimated usage of shared resources and functions. All of the allocations are based on assumptions that management believes are reasonable.

Report of Independent Registered Public Accounting Firm

To the Board of Directors of BreitBurn GP, LLC
and Unitholders of BreitBurn Energy Partners L.P.

In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of operations, partners’ equity and cash flows present fairly, in all material respects, the financial position of BreitBurn Energy Partners L.P. and its subsidiaries (“the Partnership”) at December 31, 2008, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 14 to the financial statements, the Partnership changed the manner in which it accounts for recurring fair value measurements of financial instruments in 2008.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California
March 2, 2009

BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statement of Operations
For the Year Ended December 31, 2008




*Thousands of dollars, except per unit amounts*
Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$	467,381
Gains on commodity derivative instruments, net (note 14)		332,102
Other revenue, net (note 10)		2,920

Total revenues and other income items		802,403
Operating costs and expenses:
Operating costs		149,681
Depletion, depreciation and amortization (note 5)		179,933
General and administrative expenses		43,435

Total operating costs and expenses		373,049


Operating income		429,354

Interest and other financing costs, net		29,147
Loss on interest rate swaps (note 14)		20,035
Other income, net		(191	)


Income before taxes and minority interest		380,363

Income tax expense (note 6)		1,939
Minority interest (note 19)		188


Net income		378,236


General Partner’s interest in net income (loss)		(2,019	)


Limited Partners’ interest in net income	$	380,255


Basic net income per unit (note 2)	$	6.42

Diluted net income per unit (note 2)	$	6.28

The accompanying notes are an integral part of these consolidated financial statements.

BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Balance Sheet
As of December 31, 2008



*Thousands of dollars, except unit amounts*
ASSETS
Current assets:
Cash	$	2,546
Accounts receivable, net (note 2)		47,221
Derivative instruments (note 14)		76,224
Related party receivables (note 7)		5,084
Inventory (note 8)		1,250
Prepaid expenses		5,300
Intangibles (note 9)		2,771
Other current assets		170

Total current assets		140,566
Equity investments (note 10)		9,452
Property, plant and equipment
Oil and gas properties (note 4)		2,057,531
Non-oil and gas assets (note 4)		7,806

		2,065,337
Accumulated depletion and depreciation (note 5)		(224,996	)

Net property, plant and equipment		1,840,341
Other long-term assets
Intangibles (note 9)		495
Derivative instruments (note 14)		219,003
Other long-term assets		6,977


Total assets	$	2,216,834

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	28,302
Book overdraft		9,871
Derivative instruments (note 14)		10,192
Revenue distributions payable		16,162
Derivative settlements payable		50
Salaries and wages payable		6,249
Accrued liabilities		9,164

Total current liabilities		79,990
Long-term debt (note 11)		736,000
Deferred income taxes (note 6)		4,282
Asset retirement obligation (note 12)		30,086
Derivative instruments (note 14)		10,058
Other long-term liabilities		2,987

Total liabilities		863,403
Minority interest (note 19)		539
Partners’ equity (note 13)
Limited partners’ interest (a)		1,352,892

Total liabilities and partners’ equity	$	2,216,834


(a) Limited partner units outstanding		52,635,634

The accompanying notes are an integral part of these consolidated financial statements.

BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statement of Cash Flows
For the Year Ended December 31, 2008


*Thousands of dollars*
Cash flows from operating activities
Net income	$	378,236
Adjustments to reconcile net income to cash flow from operating activities:
Depletion, depreciation and amortization		179,933
Unit-based compensation expense		6,907
Unrealized gain on derivative instruments		(370,734	)
Distributions greater than income from equity affiliates		1,198
Deferred income tax		1,207
Minority interest		188
Amortization of intangibles		3,131
Other		2,643
Changes in net assets and liabilities:
Accounts receivable and other assets		258
Inventory		4,454
Net change in related party receivables and payables		32,688
Accounts payable and other liabilities		(13,413	)

Net cash provided by operating activities		226,696

Cash flows from investing activities
Capital expenditures		(131,082	)
Property acquisitions		(9,957	)

Net cash used by investing activities		(141,039	)

Cash flows from financing activities
Purchase of common units		(336,216	)
Distributions⁽¹⁾		(121,349	)
Proceeds from the issuance of long-term debt		803,002
Repayments of long-term debt		(437,402	)
Book overdraft		7,951
Long-term debt issuance costs		(5,026	)

Net cash used by financing activities		(89,040	)

Decrease in cash		(3,383	)
Cash beginning of period		5,929

Cash end of period	$	2,546


(1)		Includes distributions on equivalent units of $2.3 million

The accompanying notes are an integral part of these consolidated financial statements.

BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statement of Partners’ Equity
For the Year Ended December 31, 2008


	Limited			General
*Thousands of dollars*	Partners			Partner			Total
Balance, January 1, 2008	$	1,423,418		$	1,390		$	1,424,808
Redemption of common units from predecessors (a)		(336,216	)		—			(336,216	)
Distributions		(118,580	)		(427	)		(119,007	)
Distributions paid on unissued units under incentive plans		(2,335	)		(7	)		(2,342	)
Unit-based compensation		7,383			—			7,383
Net income (loss) (b)		380,255			(2,019	)		378,236
Contribution of general partner interest to the partnership		(1,063	)		1,063			—
Other		30			—			30

Balance, December 31, 2008	$	1,352,892		$	—		$	1,352,892


(a)		Reflects the purchase of 14.405 million Common Units from subsidiaries of Provident.

(b)		General partner interests were purchased as of June 17, 2008.

The accompanying notes are an integral part of these consolidated financial statements.

Notes to Consolidated Financial Statements

Note 1. Organization and Operations

BreitBurn Energy Partners L.P.

The Partnership is a Delaware limited partnership formed on March 23, 2006. In October 2006, we completed an initial public offering of 6,000,000 Common Units and completed the sale of an additional 900,000 Common Units to cover over-allotments in the initial public offering at $18.50 per unit, or $17.205 per unit, after deducting the underwriting discount. On May 24, 2007, we sold 4,062,500 Common Units in a private placement at $32.00 per unit, resulting in proceeds of approximately $130 million. The net proceeds of this private placement were used to acquire certain interests in oil leases and related assets located in Florida from Calumet Florida L.L.C. and to reduce indebtedness under our credit facility. On May 25, 2007, we sold 2,967,744 Common Units in a private placement at $31.00 per unit, resulting in proceeds of approximately $92 million. The net proceeds of this private placement were used to acquire a 99 percent limited partner interest in BreitBurn Energy Partners I, L.P. (“BEPI”) from TIFD X-III LLC which owned interests in the Sawtelle and East Coyote oil fields located in California, and to terminate existing hedges related to future production from BEPI. On November 1, 2007, we sold 16,666,667 Common Units in a private placement at $27.00 per unit, resulting in proceeds of approximately $450 million. The net proceeds from this private placement were used to fund a portion of the cash consideration for our acquisition from Quicksilver of properties located in Michigan, Indiana and Kentucky (the “Quicksilver Acquisition”). Also on November 1, 2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition as a private placement.

Our general partner is BreitBurn GP, a Delaware limited liability company, also formed on March 23, 2006. The board of directors of our General Partner has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly owned subsidiary, BOLP and BOLP’s general partner BOGP. We own all of the ownership interests in BOLP and BOGP.

Our wholly owned subsidiary BreitBurn Management manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 7 for information regarding our relationship with BreitBurn Management.

On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at $23.26 per unit, for a purchase price of approximately $335 million (the “Common Unit Purchase”). These units have been cancelled and are no longer outstanding. This purchase was accounted for as a repurchase of issued Common Units and a cancellation of those Common Units. It increased debt by $336.2 million and decreased equity by $336.2 million, including $1.2 million in capitalized transaction costs.

On June 17, 2008, we also purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management, which owned the General Partner, for a purchase price of approximately $10 million (the “BreitBurn Management Purchase”). See Note 4 for the purchase price allocation for this transaction. Also on June 17, 2008, we entered into a contribution agreement (the “Contribution Agreement”) with the General Partner, BreitBurn Management and BreitBurn Corporation, which is wholly owned by the Co-Chief Executive Officers of the General Partner, Halbert S. Washburn and Randall H. Breitenbach, pursuant to which BreitBurn Corporation contributed its 4.45 percent limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units, the economic value of which was equivalent to the value of their combined 4.45 percent interest in BreitBurn Management, and BreitBurn Management contributed its 100 percent limited liability company interest in the General Partner to us. On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated and our limited partners holding Common Units were given a right to nominate and vote in the election of directors to the Board of Directors of the General Partner. As a result of these transactions (collectively, the “Purchase, Contribution and Partnership Transactions”), the General Partner and BreitBurn Management became our wholly owned subsidiaries.

On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, we and our wholly owned subsidiaries entered into the First Amendment to Amended and Restated Credit Agreement, Limited Waiver and Consent and First Amendment to Security Agreement (“Amendment No. 1 to the Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent. Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement dated November 1, 2007 from $750 million to $900 million. We used borrowings under Amendment No. 1 to the Credit Agreement to finance the Common Unit Purchase and the BreitBurn Management Purchase.

On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, the Omnibus Agreement, dated October 10, 2006, among us, the General Partner, Provident, Pro GP and BEC was terminated in all respects.

As of December 31, 2008, the public unitholders, the institutional investors in our private placements and Quicksilver owned 98.69 percent of the Common Units. BreitBurn Corporation owned 690,751 Common Units, representing a 1.31 percent limited partner interest. We own 100 percent of the General Partner, BreitBurn Management and BOLP.

On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark Capital Partners (“Metalmark”), Greenhill Capital Partners (“Greenhill”) and a third-party institutional investor, completed the acquisition of BEC, our Predecessor. This transaction included the acquisition of a 96.02 percent indirect interest in BEC, previously owned by Provident, and the remaining indirect interests in BEC, previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of the our senior management. BEC was a separate U.S. subsidiary of Provident and was our Predecessor.

2. Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. Investments in affiliated companies with a 20 percent or greater ownership interest, and in which we do not have control, are accounted for on the equity basis. Investments in affiliated companies with less than a 20 percent ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than 50 percent interest are consolidated. Investments in which we own less than a 50 percent interest but are deemed to have control or where we have a variable interest in an entity where we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The effects of all intercompany transactions have been 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 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 during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation, amortization, asset retirement obligations and impairment of oil and gas properties.

We account for business combinations using the purchase method, in accordance with SFAS No. 141Accounting for Business Combinations. We use estimates to record the assets and liabilities acquired. All purchase price allocations are finalized within one year from the acquisition date.

Basis of Presentation

Our financial statements are prepared in conformity with U.S. generally accepted accounting principles.

Business segment information

SFAS No. 131,Disclosures about Segments of an Enterprise and Related Information, establishes standards for reporting information about operating segments. Segment reporting is not applicable because our oil and gas operating areas have similar economic characteristics and meet the criteria for aggregation as defined in SFAS No. 131. We acquire, exploit, develop and explore for and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.

Revenue recognition

Revenues associated with sales of our crude oil and natural gas are recognized when title passes from us to our customer. Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (“entitlement” method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As a result, we have no material natural gas producer imbalance positions.

Cash and cash equivalents

We consider all investments with original maturities of three months or less to be cash equivalents. At December 31, 2008 we had no such investments.

Accounts Receivable

Our accounts receivable are primarily from purchasers of crude oil and natural gas and counterparties to our financial instruments. Crude oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. During 2008 we terminated our crude oil derivative instruments with Lehman Brothers due to their bankruptcy, and at December 31, 2008, we had an allowance of $4.6 million related to these contracts.

Inventory

Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded as inventory.

Investments in Equity Affiliates

Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of our natural gas production.

Property, plant and equipment

Oil and gas properties

We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred, including internal acquisition costs, relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred.

Upon sale or retirement of proved properties, the cost thereof and the accumulated depletion, depreciation and amortization (“DD&A”) are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, are computed on a property-by-property basis and recognized using the units-of-production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using straight line, generally over 20 years.

Non-oil and gas assets

Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from 3 to 30 years.

Oil and natural gas reserve quantities

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports.

Asset retirement obligations

We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The computation of our asset retirement obligations (“ARO”) is prepared in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143,Accounting for Asset Retirement Obligations. This accounting standard applies to the fair value of a liability for an asset retirement obligation that is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and expensed. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of crude oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO

estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.

Impairment of assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” as amended. Under SFAS 144, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted cash flows are forecast using five-year NYMEX forward strip prices at the end of the period and escalated thereafter at 2.5 percent. For impairment charges, the associated property’s expected future net cash flows are discounted using a rate of approximately ten percent. Reserves are calculated based upon reports from third-party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Because of the low commodity prices that existed at year end 2008, and the uncertainty surrounding future commodity prices and costs, we performed impairment tests on our long-lived assets at December 31, 2008.

We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. In 2008, we recorded $51.9 million in impairments and $34.5 million in price related depletion and depreciation adjustments. See Note 5 — Impairments and Price Related Depletion and Depreciation Adjustments. The charge was included in DD&A on the consolidated statement of operations.

Debt issuance costs

The costs incurred to obtain financing have been capitalized. Debt issuance costs are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.

Equity-based compensation

BreitBurn Management had various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 15.

Effective January 1, 2006, the Predecessor adopted the fair value recognition provisions of SFAS No. 123 (revised 2004) (SFAS No. 123(R)),Share Based Payments, using the modified-prospective transition method. Under this transition method, unit based compensation awards granted prior to but not yet vested as of January 1, 2006 that are classified as liabilities are charged to compensation expense based on the fair value provisions of SFAS No. 123(R). We and the Predecessor recognized these compensation costs on a graded-vesting method. Under the graded-vesting method a company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award was, in substance, multiple awards.

Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period.

Fair market value of financial instruments

The carrying amount of our cash, accounts receivable, accounts payable, and accrued expenses, approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt approximates fair value; however, changes in the credit markets at year-end may impact our ability to enter into future credit facilities at similar terms.

Accounting for business combinations

We have accounted for all business combinations using the purchase method, in accordance with SFAS No. 141,Accounting for Business Combinations. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and

liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets. We have not recognized any goodwill from any business combinations.

Concentration of credit risk

We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings.

Derivatives

SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets or liabilities in our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. For derivatives designated as cash flow hedges, changes in fair value are recognized in other comprehensive income, to the extent the hedge is effective, until the hedged item is recognized in earnings. Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS No.133, is recognized immediately in earnings. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities. We currently do not designate any of our derivatives as hedges for accounting purposes.

Effective January 1, 2008, we adopted SFAS No. 157,“Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value measurement under SFAS No. 157 is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date, considered from the perspective of a market participant that holds the asset or owes the liability. The objective of fair value measurement as defined in SFAS No. 157 is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If there is an active market for the asset or liability, the fair value measurement shall represent the price in that market whether the price is directly observable or otherwise obtained using a valuation technique.

Income taxes

Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided.

We have three wholly owned subsidiaries, which are subject to corporate income taxes. We account for the taxes associated with one entity in accordance with SFAS No. 109,“Accounting for Income Taxes.”Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities.

Effective January 1, 2007, we implementedFASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109(“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies.

We performed an evaluation as of December 31, 2008 and concluded that there were no uncertain tax positions requiring recognition in the financial statements. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows.

Net Income per unit

Weighted average units outstanding for computing basic and diluted net income per unit were:


	Year Ended
	December 31,
	2008
Weighted average number of Common Units used to calculate basic and diluted net income or loss per unit:
Basic		59,238,588
Dilutive		1,322,107

Diluted		60,560,695

We had 6,700,000 Common Units authorized for issuance under our long-term incentive compensation plans and there were approximately 1,422,171 partnership-based units outstanding that are eligible for receiving Common Units upon vesting at December 31, 2008.

Environmental expenditures

We review, on an annual basis, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. We do not discount any of these liabilities. At December 31, 2008, we had a $2.0 million environmental liability related to a closure of a drilling pit in Michigan, which we assumed in the Quicksilver Acquisition.

3. Accounting Pronouncements

SFAS No. 157, Fair Value Measurements.In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 12, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2,“Effective Date of FASB Statement No. 157,”which defers the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Earlier adoption is permitted, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. Effective January 1, 2008, we adopted SFAS No. 157, as amended by FSP 157-2. Adoption of SFAS No. 157 did not have a material impact on our results from operations or financial position.

SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FAS 115” (“SFAS No. 159”).In February 2007, the FASB issued SFAS No. 159 which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value in situations in which they are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. The provisions of SFAS No. 159 became effective for us on January 1, 2008. We have elected not to adopt the fair value option allowed by SFAS No. 159, and, therefore, it had no impact on our financial position, results from operations or cash flows.

SFAS No. 141(revised 2007) “Business Combinations” (“SFAS No. 141R”).In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141R was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the acquisition. SFAS No. 141R also impacts the goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141R. The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141R is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. We may experience a financial statement impact depending on the nature and extent of any new business combinations entered into after the effective date of SFAS No. 141R.

SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS No. 160”).In December 2007, the FASB issued SFAS No. 160 which requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS No. 160 is not expected to have a material impact on our results from operations or financial position.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS No. 161”).In March 2008, the FASB issued SFAS No. 161 which requires enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 has the same scope as Statement 133, and, accordingly, applies to all entities. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. This statement will require the additional disclosures detailed above.

FSP 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP 142-3”).In April 2008, the FASB issued FSP 142-3, which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142,“Goodwill and Other Intangible Assets.”The intent of this FSP is to improve consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007),“Business Combination”and other U.S. generally accepted accounting principles. FSP 142-3 is effective for fiscal years beginning after December 15, 2008. We do not expect the adoption of FSP 142-3 to have a material impact on our financial position, results of operations or cash flows.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). In May 2008, the FASB issued SFAS No. 162 which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States (the GAAP hierarchy). SFAS No. 162 became effective November 13, 2008. The adoption of SFAS No. 162 did not have an impact on our results from operations or financial position.

FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”).In June 2008, the FASB issued FSP EITF 03-6-1. Under this FSP, unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether they are paid or unpaid, are considered participating securities and should be included in the computation of earnings per share pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. In addition, all prior period earnings per share data presented should be adjusted retrospectively and early application is not permitted. We are currently evaluating the impact adoption of FSP EITF 03-6-1 may have on our earnings per share disclosures.

On December 31, 2008, the SEC issued Release No. 33-8995 for guidelines on new reserves estimate calculations and related disclosures. The new reserve estimate disclosures apply to all annual reports for fiscal years ending on or after December 31, 2009 and thereafter, and to all registration statements filed after that date. It does not permit companies to voluntarily comply at an earlier date. The revised proved reserve definition incorporates a new definition of “reasonable certainty” using the PRMS (Petroleum Resource Management System) standard of “high degree of confidence” for deterministic method estimates, or a 90 percent recovery probability for probabilistic methods used in estimating proved reserves. The guideline also permits a company to establish undeveloped reserves as proved with appropriate degrees of reasonable certainty established absent actual production tests and without artificially limiting such reserves to spacing units adjacent to a producing well. For reserve reporting purposes, it also replaces the end-of-the-year oil and gas reserve pricing with an unweighted average first-day-of-the-month pricing for the past 12 fiscal months. This would impact depletion calculations. Costs associated with reserves will continue to be measured on the last day of the fiscal year. A revised tabular presentation of reserves by development category, final product type, and oil and gas activity disclosure by geographic regions and significant fields and a general disclosure of the internal controls a company uses to assure objectivity in reserves estimation will be required. The adoption of SEC release No. 33-8995 is expected to have a material impact, which cannot be quantified at this point, on the calculation of our crude oil and natural gas reserves.

4. Acquisitions

On June 17, 2008, we purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management for a purchase price of approximately $10.0 million. This transaction resulted in BreitBurn Management becoming our wholly owned subsidiary and was accounted for as a business combination. The following table presents the purchase price allocation of the BreitBurn Management Purchase:


*Thousands of dollars*
Related party receivables — current, net	$	10,662
Other current assets		21
Oil and gas properties		8,451
Non-oil and gas assets		4,343
Related party receivables — non-current		6,704
Current liabilities		(13,510	)
Long-term liabilities		(6,704	)

	$	9,967

Certain of the current and long-term related party receivables are with the Partnership, so they are now eliminated in consolidation.

5. Impairments and Price Related Depletion and Depreciation Adjustments

Because of the low commodity prices at year end 2008, and the uncertainty surrounding future commodity prices as well as future costs, we performed impairment tests on our long-lived assets at December 31, 2008. For the year ended December 31, 2008, we recorded approximately $51.9 million for total impairments and $34.5 million for price related adjustments to depletion and depreciation expense.

We assess our developed and undeveloped oil and gas properties and other long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved-reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for market supply and demand conditions for crude oil and natural gas. The impairment reviews and calculations are based on assumptions that are consistent with our business plans. See “Impairment of Assets” in Note 2. The low commodity price environment that existed at December 31, 2008 influenced our future commodity price projections. As a result, the expected discounted cash flows for many of our fields (i.e., fair values) were negatively impacted resulting in a charge to depletion and depreciation expense of approximately $51.9 million for field impairments for the year ended December 31, 2008.

An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable, given the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

Lower commodity prices also negatively impacted our oil and gas reserves in the fourth quarter of 2008 resulting in significant price related adjustments to our depletion and depreciation expense in the fourth quarter of 2008 as compared to the fourth quarter of 2007. These price

related reserve reductions in 2008 resulted in additional depletion and depreciation charges of approximately $34.5 million for the fourth quarter and for the year ended December 31, 2008.

6. Income Taxes

We, and all of our subsidiaries, with the exception of Phoenix Production Company, Alamitos Company and BreitBurn Management, are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes. Essentially all of our taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our partners. As such, we have not recorded any federal income tax expense for those pass-through entities. State income tax expenses are recorded for certain operations that are subject to state taxation in various states, primarily Michigan, California and Texas. The total state taxes paid were $0.5 million in 2008.

Our wholly-owned subsidiary, Phoenix Production Company, is a tax-paying corporation. We record an income tax provision in accordance with SFAS No. 109 “Accounting for Income Taxes.” In 2008, Phoenix Production Company recorded $0.1 million for alternative minimum taxes. Phoenix Production Company also recorded a deferred federal income tax expense of $1.2 million in 2008. The following is a reconciliation for Phoenix Production Company of federal income taxes at the statutory rates to federal income tax expense or benefit as reported in the consolidated statements of operations.


	Year Ended
	December 31,
*Thousands of dollars*	2008
Income before taxes and minority interest	$	380,363
Partnership income not subject to tax		376,459

Income subject to tax		3,904
Federal income tax rate		34

Income tax at statutory rate		1,327
Other		—

Income tax expense	$	1,327

At December 31, 2008, a net deferred federal income tax liability of $4.3 million was included in our consolidated balance sheet for Phoenix Production Company. As shown in the table below, the net deferred federal income tax liability primarily consisted of the tax effect of book and tax basis differences of certain assets and liabilities and the deferred federal income tax asset for net operating loss carry forwards. Management expects to utilize $2.3 million of estimated unused operating loss carry forwards to offset future taxable income. As such, no valuation allowance has been recorded against the deferred federal income tax asset.


	December 31,
*Thousands of dollars*	2008
Deferred tax assets:
Net operating loss carryforwards	$	767
Asset retirement obligation		337
Unrealized hedge loss		—
Other		103
Deferred tax liabilities:
Depreciation, depletion and intangible drilling costs		(3,404	)
Other		(2,085	)

Net deferred tax liability	$	(4,282	)

In 2008, our other wholly-owned tax-paying corporation, Alamitos Company, incurred a current federal tax expense of $0.1 million. No deferred federal or state income tax is recognized for this company as the temporary differences between the tax basis and the reported financial amounts of its assets and liabilities are immaterial. BreitBurn Management became our wholly-owned subsidiary and a taxable entity on June 17, 2008. However, no federal or state income tax expense is expected due to the nature of its business as expenses incurred are essentially offset by amounts recovered for services provided to the operating companies.

Cash paid for federal and state income taxes was $0.6 million in 2008.

New Accounting Pronouncement

7. Related Party Transactions

BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. Prior to June 17, 2008, BreitBurn Management provided services to us and to BEC, and allocated its expenses between the two entities. On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, BreitBurn Management became our wholly owned subsidiary and entered into an Amended and Restated Administrative Services Agreement with BEC, pursuant to which BreitBurn Management agreed to continue to provide administrative services to BEC, in exchange for a monthly fee of $775,000 for indirect expenses. In addition to the monthly fee, BreitBurn Management agreed to continue to charge BEC for direct expenses including incentive plan costs and direct payroll and administrative costs. Beginning on June 17, 2008, all of the costs charged to BOLP are consolidated with our results.

On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark, Greenhill and a third-party institutional investor, completed the acquisition of BEC, our Predecessor. This transaction included the acquisition of a 96.02 percent indirect interest in BEC previously owned by Provident and the remaining indirect interests in BEC previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of our senior management. BEC was an indirectly owned subsidiary of Provident.

In connection with the acquisition of Provident’s ownership in BEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management entered into a five year Administrative Services Agreement to manage BEC’s properties. The monthly fee charged to BEC remained $775,000 for indirect expenses through December 31, 2008. We expect this fee to be renegotiated annually during the term of the agreement and expect a monthly fee of less than $775,000 in 2009. In addition, we have entered into an Omnibus Agreement with BEC detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of assets by BEC.

At December 31, 2008, we had current receivables of $4.4 million due from BEC related to the Administrative Services Agreement, outstanding liabilities for employee related costs and oil and gas sales made by BEC on our behalf from certain properties. In 2008, total oil and gas sales made on our behalf for these properties were approximately $2.1 million.

Mr. Greg L. Armstrong is the Chairman of the Board and Chief Executive Officer of Plains All American GP LLC (“PAA”). Mr. Armstrong was a director of our General Partner until March 26, 2008 when his resignation became effective. We sell all of the crude oil produced from our Florida properties to Plains Marketing, L.P., a wholly owned subsidiary of PAA. In 2008, prior to Mr. Armstrong’s resignation on March 26, 2008, we sold $19.3 million of our crude oil to Plains Marketing, L.P.

Through a transition services agreement through March 2008, Quicksilver provided services to us for accounting, land administration, and marketing and charged us $0.9 million for the first three months of 2008. These charges were included in general and administrative expenses on the consolidated statements of operations. Quicksilver also buys natural gas from us in Michigan. For the year ended

December 31, 2008, total net gas sales to Quicksilver were approximately $8.0 million and the related receivable was $0.6 million as of December 31, 2008.

At December 31, 2008, we had a receivable of $0.1 million for management fees due from equity affiliates and operational expenses incurred on behalf of equity affiliates.

8. Inventory

Our crude oil inventory from our Florida operations at December 31, 2008 was $1.3 million. For the year ended December 31, 2008, we sold 762 MBbls of crude oil and produced 707 MBbls from our Florida operations. Crude oil inventory additions are at cost and represent our production costs. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded to inventory. Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter.

We carry inventory at the lower of cost or market. When using lower of cost or market to value inventory, market should not exceed the net realizable value or the estimated selling price less costs of completion and disposal. During the fourth quarter of 2008, commodity prices decreased substantially. As a result, we assessed our crude oil inventory for possible write-down, and recorded $1.2 million to write-down the Florida crude oil inventory to our net realizable value at December 31, 2008.

For our properties in Florida, there are a limited number of alternative methods of transportation for our production. Substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil production in Florida, which could have a negative impact on our future consolidated financial position, results of operations or cash flows.

9. Intangibles

In May 2007, we acquired certain interests in oil leases and related assets through the acquisition of a limited liability company from Calumet Florida, L.L.C. As part of this acquisition, we assumed certain crude oil sales contracts for the remainder of 2007 and for 2008 through 2010. A $3.4 million intangible asset was established to value the portion of the crude oil contracts that were above market at closing in the purchase price allocation. Realized gains or losses from these contracts are recognized as part of oil sales and the intangible asset will be amortized over the life of the contracts. As of December 31, 2008, our intangible asset related to the crude oil sales contracts was $1.6 million.

In November 2007, we acquired oil and gas properties and facilities from Quicksilver. Included in the Quicksilver purchase price was a $5.2 million intangible asset related to retention bonuses. In connection with the acquisition, we entered into an agreement with Quicksilver which provides for Quicksilver to fund retention bonuses payable to 139 former Quicksilver employees in the event these employees remain continuously employed by BreitBurn Management from November 1, 2007 through November 1, 2009 or in the event of termination without cause, disability or death. The amortization expense of $2.1 million for 2008 is included in the total operating expenses line on the consolidated statement of operations. As of December 31, 2008, our intangible asset related to Quicksilver retention bonuses was $1.7 million.

10. Equity Investments

We had equity investments at December 31, 2008 of $9.5 million. These investments are reported in the “Equity investments” line caption on the consolidated balance sheet and primarily represent investments in natural gas processing facilities. For the year ended December 31, 2008, we recorded $0.8 million in earnings from equity investments. Earnings from equity investments are reported in the “Other Revenue” line caption on the consolidated statement of operations.

At December 31, 2008, our equity investments consisted primarily of a 24.5 percent limited partner interest and a 25.5 percent general partner interest in Wilderness Energy Services LP, with a combined carrying value of $8.2 million. The remaining $1.3 million consists of smaller interests in several other investments.

11. Long-Term Debt

On November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as borrower, and we and our wholly owned subsidiaries, as guarantors, entered into a four year, $1.5 billion amended and restated revolving credit facility with Wells Fargo Bank, N.A., Credit Suisse Securities (USA) LLC and a syndicate of banks (the “Amended and Restated Credit Agreement”).

The initial borrowing base of the Amended and Restated Credit Agreement was $700 million and was increased to $750 million on April 10, 2008. Under the Amended and Restated Credit Agreement, borrowings were allowed to be used (i) to pay a portion of the purchase price for the Quicksilver Acquisition, (ii) for standby letters of credit, (iii) for working capital purposes, (iv) for general company purposes and (v) for certain permitted acquisitions and payments enumerated by the credit facility. Borrowings under the Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of the Partnership’s and certain of its subsidiaries’ assets, representing not less than 80 percent of the total value of their oil and gas properties.

The Amended and Restated Credit Agreement contains (i) financial covenants, including leverage, current assets and interest coverage ratios, and (ii) customary covenants, including restrictions on the Partnership’s ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to unitholders or repurchase units if aggregated letters of credit and outstanding loan amounts exceed 90 percent of its borrowing base; make dispositions; or enter into a merger or sale of its property or assets, including the sale or transfer of interests in its subsidiaries.

The events that constitute an Event of Default (as defined in the Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against the Partnership in excess of a specified amount; changes in management or control; loss of permits; failure to perform under a material agreement; certain insolvency events; assertion of certain environmental claims; and occurrence of a material adverse effect. At December 31, 2008, the Partnership was in compliance with the credit facility’s covenants.

On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, we and our wholly owned subsidiaries entered into Amendment No. 1 to the Amended and Restated Credit Agreement, with Wells Fargo Bank, National Association, as administrative agent (the “Agent”). Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement, from $750 million to $900 million. In addition, Amendment No. 1 to the Credit Agreement enacted certain additional amendments, waivers and consents to the Amended and Restated Credit Agreement and the related Security Agreement, dated November 1, 2007, among BOLP, certain of its subsidiaries and the Agent, necessary to permit the Amendment No. 1 to the First Amended and Restated Limited Partnership Agreement and the transactions consummated in the Purchase, Contribution and Partnership Transactions. Under Amendment No. 1 to the Credit Agreement, the interest margins applicable to borrowings, the letter of credit fee and the commitment fee under the Amended and Restated Credit Agreement were increased by amounts ranging from 12.5 to 25 basis points.

As of December 31, 2008, approximately $736.0 million in indebtedness was outstanding under the Amended and Restated Credit Agreement. The credit facility will mature on November 1, 2011. At December 31, 2008, the LIBOR interest rate, a weighted average interest rate of our four outstanding LIBOR loans, was 2.350 percent on the LIBOR portion of $736.0 million.

The credit facility contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders (including the restriction in our ability to make distributions if aggregated letters of credit and outstanding loan amounts exceed 90 percent of our borrowing base); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.

As of December 31, 2008, we were in compliance with the credit facility’s covenants. At December 31, 2008, we had $0.3 million in letters of credit outstanding.

Our interest expense is detailed in the following table:


	Year Ended
	December 31,
*Thousands of dollars*	2008
Credit facility	$	25,487
Commitment fees		1,047
Amortization of discount and deferred issuance costs		2,613

Total	$	29,147
Cash paid for interest on Credit facility (including realized losses on interest rate swaps)	$	29,767

12. Asset Retirement Obligation

Our asset retirement obligation is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities as well as our estimate of the future timing of the costs to be incurred. The total undiscounted amount of future cash flows required to settle our asset retirement obligations is estimated to be $256.8 million at December 31, 2008. Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from 7 to 50 years. Estimated cash flows have been discounted at our credit adjusted risk free rate of 7 percent and adjusted for inflation using a rate of 2 percent. Changes in the asset retirement obligation for the year ended December 31, 2008 are presented in the following table:


	Year Ended December 31,
*Thousands of dollars*	2008
Carrying amount, beginning of period	$	27,819
Liabilities settled in the current period		(1,054	)
Revisions (1)		1,363
Acquisitions		—
Accretion expense		1,958


Carrying amount, end of period	$	30,086


(1)		Increased cost estimates and revisions to reserve life.

13. Partners’ Equity

At December 31, 2008, we had 52,635,634 Common Units outstanding.

On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at $23.26 per unit, for a purchase price of approximately $335 million. These units have been cancelled and are no longer outstanding. This transaction was accounted for as a repurchase of issued Common Units and a cancellation of those Common Units. This transaction decreased equity by $336.2 million, including $1.2 million in capitalized transaction costs. We also purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management, which owned the General Partner. Also on June 17, 2008, we entered into a Contribution Agreement with the General Partner, BreitBurn Management and BreitBurn Corporation, pursuant to which BreitBurn Corporation contributed its 4.45 percent limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units and BreitBurn Management contributed its 100 percent limited liability company interest in the General Partner to us. On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated. As a result of these transactions, the General Partner and BreitBurn Management became our wholly owned subsidiaries.

On December 22, 2008, we entered into a Unit Purchase Rights Agreement, dated as of December 22, 2008 (the “Rights Agreement”), between us and American Stock Transfer & Trust Company LLC, as Rights Agent. Under the Rights Agreement, each holder of Common Units at the close of business on December 31, 2008 automatically received a distribution of one unit purchase right (a “Right”), which entitles the registered holder to purchase from us one additional Common Unit at a price of $40.00 per Common Unit, subject to adjustment. We entered into the Rights agreement to increase the likelihood that our unitholders receive fair and equal treatment in the event of a takeover proposal.

The issuance of the Rights was not taxable to the holders of the Common Units, had no dilutive effect, will not affect our reported earnings per Common Unit, and will not change the method of trading the Common Units. The Rights will not trade separately from the Common Units unless the Rights become exercisable. The Rights will become exercisable if a person or group acquires beneficial ownership of 20 percent or more of the outstanding Common Units or commences, or announces its intention to commence, a tender offer that could result in beneficial ownership of 20 percent or more of the outstanding Common Units. If the Rights become exercisable, each Right will entitle holders, other than the acquiring party, to purchase a number of Common Units having a market value of twice the then-current exercise price of the Right. Such provision will not apply to any person who, prior to the adoption of the Rights Agreement, beneficially owns 20 percent or more of the outstanding Common Units until such person acquires beneficial ownership of any additional Common Units.

The Rights Agreement has a term of three years and will expire on December 22, 2011, unless the term is extended, the Rights are earlier redeemed or we terminate the Rights Agreement.

Cash Distributions

The partnership agreement requires us to distribute all of our available cash quarterly. Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs. We may fund a portion of capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. The partnership agreement does not restrict our ability to borrow to pay distributions. The cash distribution policy reflects a basic judgment that unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.

Distributions are not cumulative. Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future.

Distributions are paid within 45 days of the end of each fiscal quarter to holders of record on or about the first or second week of each such month. If the distribution date does not fall on a business day, the distribution will be made on the business day immediately preceding the indicated distribution date.

We do not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves the General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. The partnership agreement provides that any determination made by the General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity.

On February 14, 2008, we paid a cash distribution of approximately $30.5 million to our General Partner and common unitholders of record as of the close of business on February 11, 2008. The distribution that was paid to unitholders was $0.4525 per Common Unit.

On May 15, 2008, we paid a cash distribution of approximately $33.7 million to our General Partner and common unitholders of record as of the close of business on May 9, 2008. The distribution that was paid to unitholders was $0.50 per Common Unit.

On August 14, 2008, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on August 11, 2008. The distribution that was paid to unitholders was $0.52 per Common Unit.

On November 14, 2008, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on November 10, 2008. The distribution that was paid to unitholders was $0.52 per Common Unit.

During the year ended December 31, 2008, we made payments equivalent to the distributions made to unitholders of $2.3 million on Restricted Phantom Units and Convertible Phantom Units issued under our Long-Term Incentive Plans.

2007 Private Placements

On May 24, 2007, we sold 4,062,500 Common Units, at a negotiated purchase price of $32.00 per unit, to certain investors (the “Purchasers”). We used $108 million from such sale to fund the cash consideration for the Calumet Acquisition and the remaining $22 million of the proceeds was used to repay indebtedness under our credit facility. Most of the debt repaid was associated with our first quarter 2007 acquisition of the Lazy JL Field properties in West Texas.

On May 25, 2007, we sold an additional 2,967,744 Common Units to the same Purchasers at a negotiated purchase price of $31.00 per unit. We used the proceeds of approximately $92 million to fund the BEPI Acquisition, including the termination of existing hedge contracts related to future production from BEPI.

On November 1, 2007, we sold 16,666,667 Common Units, at a negotiated purchase price of $27.00 per unit, to certain investors in a third private placement. We used the proceeds from such sale to fund a portion of the cash consideration for the Quicksilver Acquisition. Also on November 1, 2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition as a private placement.

In connection with the private placements of Common Units to finance the Quicksilver Acquisition, we entered into registration rights agreements with the institutional investors in our private placements and Quicksilver to file shelf registration statements to register the resale of the Common Units sold or issued in the Private Placements and to use our commercially reasonable efforts to cause the registration statements to become effective with respect to the Common Units sold to the institutional investors not later than August 2, 2008 and, with respect to the Common Units issued to Quicksilver, within one year from November 1, 2007. Quicksilver is prohibited from selling any of the Common Units issued to it prior to the first anniversary of November 1, 2007 or more than 50 percent of such Common Units prior to eighteen months after November 1, 2007. In addition, the agreements give the institutional investors and Quicksilver piggyback registration rights under certain circumstances. These registration rights are transferable to affiliates of the institutional investors and Quicksilver and, in certain circumstances, to third parties.

On July 31, 2008, the registration statement relating to the resale of the Common Units issued in the private placement to the institutional investors was declared effective. On October 28, 2008, the registration statement relating to the resale of the Common Units issued in the private placement to Quicksilver was declared effective.

14. Financial Instruments

Fair Value of Financial Instruments

Our commodity price risk management program is intended to reduce our exposure to commodity prices and to assist with stabilizing cash flow and distributions. Routinely, we utilize derivative financial instruments to reduce this volatility. During 2008, there has been extreme volatility and disruption in the capital and credit markets which has reached unprecedented levels and may adversely affect the financial condition of our derivative counterparties. Although each of our derivative counterparties carried an S&P credit rating of A or above at December 31, 2008, we could be exposed to losses if a counterparty fails to perform in accordance with the terms of the contract. This risk is managed by diversifying the derivative portfolio among counterparties meeting certain financial criteria.

Commodity Activities

The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under SFAS No. 133. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges and instead recognize changes in the fair value immediately in earnings. For the year ended December 31, 2008 we had realized losses of $55.9 million and unrealized gains of $388.0 million relating to our market based commodity contracts. We had net financial instruments receivable relating to our commodity contracts of $292.3 million at December 31, 2008.

On September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated our crude oil derivative instruments with Lehman Brothers. Our derivative contract with Lehman Brothers, commonly referred to as a “zero cost collar,” was for oil volumes of 1,000 Bbls/d for the full year 2011. This represented approximately 8 percent of our total 2011 oil and natural gas hedge portfolio. The floor price for the collar was $105.00 per Bbl and the ceiling price was $174.50 per Bbl. This contract was replaced with contracts by substantially similar terms, with different counterparties, for oil volumes of 1,000 Bbls/d covering January 1, 2011 to January 31, 2011 and March 1, 2011 to December 31, 2011.

We had the following contracts in place at December 31, 2008:


	Year			Year			Year			Year
	2009			2010			2011			2012
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMBtu/d)		45,802			43,869			25,955			19,129
Average Price ($/MMBtu)	$	8.14		$	8.20		$	9.21		$	10.12
Collars:
Hedged Volume (MMBtu/d)		1,740			3,405			16,016			19,129
Average Floor Price ($/MMBtu)	$	9.00		$	9.00		$	9.00		$	9.00
Average Ceiling Price ($/MMBtu)	$	16.36		$	12.79		$	11.28		$	11.89
Total:
Hedged Volume (MMMBtu/d)		47,542			47,275			41,971			38,257
Average Price ($/MMBtu)	$	8.17		$	8.26		$	9.13		$	9.56

Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbls/d)		1,838			2,308			2,116			1,939
Average Price ($/Bbl)	$	75.51		$	83.12		$	88.26		$	90.00
Participating Swaps:^(a)
Hedged Volume (Bbls/d)		2,847			1,993			1,439			—
Average Price ($/Bbl)	$	62.86		$	64.40		$	61.29		$	—
Average Part. %		60.9	%		55.5	%		53.2	%		—
Collars:
Hedged Volume (Bbls/d)		594			1,279			2,048			3,077
Average Floor Price ($/Bbl)	$	92.31		$	102.84		$	103.43		$	110.00
Average Ceiling Price ($/Bbl)	$	122.92		$	136.16		$	152.61		$	145.39
Floors:
Hedged Volume (Bbls/d)		500			500			—			—
Average Floor Price ($/Bbl)	$	100.00		$	100.00		$	—		$	—
Total:
Hedged Volume (Bbls/d)		5,778			6,080			5,603			5,016
Average Price ($/Bbl)	$	73.12		$	82.52		$	86.88		$	102.27


(a)		A participating swap combines a swap and a call option with the same strike price.

Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. As of December 31, 2008, our total debt outstanding was $736.0 million. In order to mitigate our interest rate exposure, we had the following interest rate swaps in place at December 31, 2008, to fix a portion of floating LIBOR-base debt on our credit facility:


*Notional amounts in thousands of dollars*	Notional Amount		Fixed Rate
Period Covered
January 1, 2009 to January 8, 2009	$	50,000		3.6200	%
January 1, 2009 to January 20, 2009		200,000		3.6825	%
January 1, 2009 to July 8, 2009		50,000		3.0450	%
January 1, 2009 to January 8, 2010		100,000		3.3873	%
January 20, 2009 to July 20, 2009		250,000		3.6825	%
July 20, 2009 to December 20, 2010		300,000		3.6825	%
December 20, 2010 to October 20, 2011		200,000		2.9900	%

On September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated, at no cost, our interest rate swap with Lehman Brothers on $50 million at a fixed rate of 3.438 percent, which covered the period from January 8, 2008 to July 8, 2009. On October 2, 2008, we entered into a new interest rate swap on $50 million at a fixed rate of 3.0450 percent, for the period from September 8, 2008 to July 8, 2009. These transactions are reflected in the table above.

For the year ended December 31, 2008, we had realized losses of $2.7 million and unrealized losses of $17.3 million relating to our interest rate swaps. We had net financial instruments payable related to our interest rate swaps of $17.3 million at December 31, 2008.

Balance Sheet presentation of commodity and interest derivatives is as follows:


	Oil			Natural Gas
	Commodity			Commodity		Interest Rate			Total Financial
*Thousands of dollars*	Derivatives			Derivatives		Derivatives			Instruments
Balance, December 31, 2008
Short-term assets	$	44,086		$	32,138	$	—		$	76,224
Long-term assets		145,061			73,942		—			219,003

Total assets		189,147			106,080		—			295,227

Short-term liabilities		(1,115	)		—		(9,077	)		(10,192	)
Long-term liabilities		(1,820	)		—		(8,238	)		(10,058	)

Total liabilities		(2,935	)		—		(17,315	)		(20,250	)


Net assets (liabilities)	$	186,212		$	106,080	$	(17,315	)	$	274,977

While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected.

Effective January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value measurement under SFAS No. 157 is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date, considered from the perspective of a market participant that holds the asset or owes the liability. The objective of fair value measurement as defined in SFAS No. 157 is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If there is an active market for the asset or liability, the fair value measurement shall represent the price in that market whether the price is directly observable or otherwise obtained using a valuation technique.

SFAS No. 157 requires valuation techniques consistent with the market approach, income approach or the cost approach to be used to measure fair value. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert future cash flows or earnings to a single present value amount and is based upon current market expectations about those future amounts. The cost approach, sometimes referred to as the current replacement cost approach, is based upon the amount that would currently be required to replace the service capacity of an asset.

We principally use the income approach for our recurring fair value measurements and strive to use the best information available. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements.

SFAS No. 157 also establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. The highest priority of Level 1 is given to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 is given to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs as defined in SFAS No. 157 are described further as follows:

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are markets in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. An example of a Level 1 input would be quoted prices for exchange traded commodity futures contracts.

Level 2 — Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. These models include industry standard models that consider standard assumptions

such as quoted forward prices for commodities, interest rates, volatilities, current market and contractual prices for underlying assets as well as other relevant factors. Substantially all of these inputs are evident in the market place throughout the terms of the financial instruments and can be derived by observable data, including third party data providers. These inputs may also include observable transactions in the market place. We consider the over the counter (OTC) commodity and interest rate swaps in our portfolio to be Level 2. These are assets and liabilities that can be bought and sold in active markets and quoted prices are available from multiple potential counterparties.

Level 3 — Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. These inputs generally reflect management’s estimates of the assumptions market participants would use when pricing the instruments. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Level 3 instruments primarily include derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Level 3 also includes complex structured transactions that sometimes require the use of non-standard models.

Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. We include these assets and liabilities in Level 3 as required by current interpretations of SFAS 157. As of December 31, 2008, our Level 3 assets and liabilities consisted entirely of OTC commodity put and call options.

Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data or the interpretation of Level 2 criteria is modified in practice to include non-binding market corroborated data.

As mentioned in Note 7, our wholly owned subsidiary BreitBurn Management provides us with general management services, including risk management activities. Pursuant to a transition services agreement that terminated on December 31, 2008, BreitBurn Management contracted with Provident for the risk management services provided to us.

Provident’s risk management group calculated the fair values of our commodity swaps using risk management software that marks to market monthly fixed price delivery swap volumes using forward commodity price curves and market interest rates. This pricing approach is commonly used by market participants to value commodity swap contracts for sale to the market. Inputs are obtained from third party data providers and are verified to published data where available (e.g., NYMEX).

Fair value measurements for our interest rate swaps were also provided by Provident. Monthly outstanding notional amounts are marked to market for each specific swap using forward interest rate curves. This pricing approach is commonly used by market participants to value interest rate swap contracts for sale to the market. Inputs are obtained from third party data providers and are verified to published data where available (e.g., LIBOR).

Provident’s risk management group used industry standard option pricing models contained in their risk management software to calculate the fair values associated with our commodity options. Inputs to the option pricing models included fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility and interest rate factors and time to expiry. Model inputs were obtained from third party data providers and are verified to published data where available (e.g., NYMEX).

We reviewed the fair value calculations for our derivative instruments that we received from Provident’s risk management group on a monthly basis. We also compared these fair value amounts to the fair value amounts that we receive from the counterparties to our derivative instruments. We investigated differences and resolved and recorded any required changes prior to the issuance of our financial statements.

Financial assets and liabilities carried at fair value on a recurring basis are presented in the table below. Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are categorized.

Recurring fair value measurements were:


	As of December 31, 2008
*Thousands of dollars*	Level 1		Level 2			Level 3		Total
Assets (Liabilities):
Commodity Derivatives (swaps, put and call options)	$	—	$	139,074		$	153,218	$	292,292
Other Derivatives (interest rate swaps)		—		(17,315	)		—		(17,315	)

Total	$	—	$	121,759		$	153,218	$	274,977

The following table sets forth a reconciliation of our derivative instruments classified as Level 3:


	Year Ended
*Thousands of dollars*	December 31, 2008
Assets (Liabilities):
Beginning balance	$	44,236
Realized and unrealized gains, net		106,154
Purchases and issuances		7,452
Settlements		(4,624	)

Balance at December 31, 2008	$	153,218

Following the termination of the Lehman Brothers interest rate swap and crude oil zero cost collar, we entered into similar contracts with other counterparties. Our net cost to replicate the terminated Lehman contracts was $4.2 million and we have recorded a provision related to the contract default in 2008. We have a claim of approximately $4.6 million in the Lehman bankruptcy case relating to the terminations.

Unrealized gains of $112.2 million for the year ended December 31, 2008 related to our derivative instruments classified as Level 3 are included in gains on commodity derivative instruments, net on the consolidated statements of operations. Realized losses of $6.0 million for the year ended December 31, 2008 related to our derivative instruments classified as Level 3 are also included in gains on commodity derivative instruments, net on the consolidated statements of operations. Determination of fair values incorporates various factors as required by SFAS No. 157 including but not limited to the credit standing of the counterparties, the impact of guarantees as well as our own abilities to perform on our liabilities.

15. Unit and Other Valuation-Based Compensation Plans

BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, BreitBurn Management became our wholly owned subsidiary and entered into an Amended and Restated Administrative Services Agreement with BEC, pursuant to which BreitBurn Management agreed to continue to provide administrative services to BEC, in exchange for a monthly fee of $775,000 for indirect expenses. In addition to the monthly fee, BreitBurn Management agreed to continue to charge BEC for direct expenses including incentive plan costs and direct payroll and administrative costs. Beginning on June 17, 2008, all of BMC’s costs that were not charged to BEC are consolidated with our results.

Prior to June 17, 2008, BreitBurn Management provided services to us and to BEC, and allocated its expenses between the two entities. We were managed by our General Partner, the executive officers of which were and are employees of BreitBurn Management. We had entered into an Administrative Services Agreement with BreitBurn Management. Under the Administrative Services Agreement, we reimbursed BreitBurn Management for all direct and indirect expenses it incurred in connection with the services it performed on our behalf (including salary, bonus, certain incentive compensation and other amounts paid to executive officers and other employees).

Effective on the initial public offering date of October 10, 2006, BreitBurn Management adopted the existing Long-Term Incentive Plan (BreitBurn Management LTIP) and the Unit Appreciation Rights Plan (UAR plan) of the predecessor as previously amended. The predecessor’s Executive Phantom Option Plan, Unit Appreciation Plan for Officers and Key Individuals (Founders Plan), and the Performance Trust Units awarded to the Chief Financial Officer during 2006 under the BreitBurn Management LTIP, were adopted by BreitBurn Management with amendments at the initial public offering date as described in the subject plan discussions below.

We may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. We also have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the Common Units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire when units are no longer available under the plan for grants or, if earlier, its termination by us.

Unit Based Compensation

Effective January 1, 2006, our predecessor adopted the fair value recognition provisions of SFAS No. 123(R),Share-Based Payments, using the modified-prospective transition method. BreitBurn Management as successor is following the same method as BEC, our predecessor. Unit based compensation awards granted prior to but not yet vested as of January 1, 2006 that are classified as liabilities were charged to compensation expense based on the fair value provisions of SFAS No. 123(R). For the liability-based plans, we recognize these compensation expenses on a graded-vesting method. Under the graded-vesting method, a company recognizes compensation expense over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. For our RPU and CPU equity-based plans, we recognize our compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements.

Awards classified as liabilities are revalued at each reporting period using the Black-Scholes option pricing model and changes in the fair value of the options are recognized as compensation expense over the vesting schedules of the awards. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period(s). Option awards outstanding at the end of 2008 are liability-classified because the awards are settled in cash or have the option of being settled in cash or units at the choice of the holder, and they are indexed to either our Common Units or to Provident Trust Units. The liability-classified option awards are distribution-protected awards through either an Adjustment Ratio as defined in the plan or the holders receive cumulative distribution amounts upon vesting equal to the actual distribution amounts per Common Unit of the underlying notional Units. In the Black-Scholes option pricing model, the expected volatilities are based primarily on the historical volatility of Provident’s units for Provident indexed units and the Alerian MLP Index for Partnership indexed units. We and our predecessor use historical data to estimate option exercises and employee terminations within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates. Due to the distribution protection provision of the plans, zero distribution yield is assumed in the pricing model; however, compensation cost is recognized based on the units adjusted for the Adjustment Ratio and for certain plans, it includes distribution amounts accumulated to the reporting date.

Founders Plan

Under the Founders Plan, participants received unit appreciation rights which provide cash compensation in relation to the appreciation in the value of a specified number of underlying notional phantom units. The value of the unit appreciation rights was determined on the basis of a valuation of the predecessor at the end of the fiscal period plus distributions during the period less the value of the predecessor at the beginning of the period. The base price and vesting terms were determined by BreitBurn Management at the time of the grant. Outstanding unit appreciation rights vest in the following manner: one-third vest three years after the grant date, one-third vest four years after the grant date and one-third vest five years after the grant date and are subject to specified service requirements.

Effective on the initial public offering date of October 10, 2006, all outstanding unit appreciation rights under the Founders Plan were adopted by BreitBurn Management and converted into three separate awards. The first award represented 2.2 million unit appreciation rights at a weighted average grant price of $0.76 per unit with respect to the operations of the properties that were not transferred to us. The value of these unit appreciation rights at year-end 2006 was determined on the basis of an assessment of the valuation of the properties at the original grant date as compared to an assessment of the valuation of the properties at the end of the fiscal period plus distributions paid. The second award represented 309,570 unit appreciation rights at a weighted average grant price of $4.70 per unit with respect to the operations of the properties that were transferred to us for the period from the original date of grant to the initial public offering date of October 10, 2006. The value of the unit appreciation rights was determined on the basis of an assessment of the valuation of the properties at the original grant date as compared to the valuation of the properties at the end of the fiscal period as determined using the initial public offering price plus distributions paid.

The third award represented 309,570 Partnership unit appreciation rights at a base price of $18.50 per unit with respect to the operations of the properties that were transferred to us for the period beginning on the initial public offering date of October 10, 2006. The award is liability-classified and is being charged to us as compensation expense over the remaining vesting schedule. The value of the outstanding Partnership unit appreciation rights is remeasured each period using a Black-Scholes option pricing model. A market prices of $7.05 was used in the model for the period ending December 31, 2008. Expected volatility ranged from 9 percent to 21 percent and had a weighted average volatility of 9.8 percent. The average risk free rate used was approximately 3.3 percent. The expected option terms ranged from one half year to two and one half years.

We recorded approximately $(0.3) million of compensation expense/(income) under the plan for the year ended December 31, 2008. The aggregate value of the vested unit appreciation rights was $0.4 million and the unvested obligation was zero at December 31, 2008.

The following table summarizes information about Appreciation Rights Units issued under the Founders Plan:


	December 31, 2008
	Number of			Weighted
	Appreciation			Average
	Rights Units			Exercise Price
Outstanding, beginning of period		214,107		$	18.50
Exercised		(91,463	)		18.50

Outstanding, end of period		122,644		$	18.50


Exercisable, end of period		—		$	—

BreitBurn Management LTIP and the Partnership LTIP

In September 2005, certain employees of the predecessor were granted restricted units (RTUs) and/or performance units (PTUs), both of which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units indexed to Provident Energy Trust Units. The grants are based on personal performance objectives. This plan replaced the Unit Appreciation Right Plan for Employees and Consultants for the period after September 2005 and subsequent years. RTUs vest one third at the end of year one, one third at end of year two and one third at the end of year three after grant. In general, cash payments equal to the value of the

underlying notional units were made on the anniversary dates of the RTU to the employees entitled to receive them. PTUs vest three years from the end of third year after grant and payout can range from zero to two hundred percent of the initial grant depending on the total return of the underlying notional units as compared to the returns of selected peer companies. The total return of the Provident Energy Trust unit is compared with the return of 25 selected Canadian trusts and funds. The Provident indexed PTUs granted in 2005 and 2006 entitle employees to receive cash payments equal to the market price of the underlying notional units. Under our LTIP, Partnership indexed PTUs were granted in 2007 and are payable in cash or may be paid in Common Units of the Partnership if elected at least 60 days prior to vesting by the grantees. The total return of the Partnership unit is compared with the return of 49 companies in the Alerian MLP Index for the payout multiplier. All of the grants are liability-classified. Underlying notional units are established based on target salary LTIP threshold for each employee. The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio. The estimated fair value associated with RTUs and PTUs is expensed in the statement of income over the vesting period.

On June 17, 2008, we entered into the BreitBurn Management Purchase agreement with Pro LP and Pro GP. The BreitBurn Management Purchase Agreement contains certain covenants of the parties relating to the allocation of responsibility for liabilities and obligations under certain pre-existing equity-based compensation plans adopted by BreitBurn Management, BEC and us. The pre-existing compensation plans include the outstanding 2005 and 2006 LTIP grants which are indexed to the Provident Trust Units. As a result, we paid $0.9 million for our share of the 2005 LTIP grants that vested in June 2008 in accordance with the agreed allocation of liability.

In September 2008, BreitBurn Management made an offer to holders of the 2006 LTIP grants to cash out their Provident-indexed units at $10.32 per share before the normal vesting date of December 31, 2008. By the end of September 2008, the offer was accepted by all employees who had outstanding 2006 LTIP grants. Consequently, compensation expense was recognized for the full amount of the remaining unvested liability during 2008. BreitBurn Management paid employees $0.6 million in 2008 for its share of the 2006 LTIP grants in accordance with the agreed allocation of liability.

Under our LTIP, Partnership-indexed restricted units (RTUs) and/or performance units (PTUs) were granted in 2007 and are payable in cash or in Common Units of the Partnership if elected by the grantee at least 60 days prior to the vesting date. For PTUs, a performance multiplier is applied and is determined by comparing our total return to the returns of 49 companies in the Alerian MLP Index. All of the grants are liability-classified. Underlying notional units are established based on target salary LTIP threshold for each employee. The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio. The estimated fair value associated with RTUs and PTUs is expensed in the statement of income over the vesting period.

We recognized $(0.5) of compensation expense/(income) for the year ended December 31, 2008. Our share of the aggregate liability under the BreitBurn Management LTIP was $0.8 million at December 31, 2008. The aggregate value of the vested and unvested units under the plan was $0.6 million and $0.2 million respectively, at December 31, 2008.

The following table summarizes information at December 31, 2008 about the restricted/performance units granted in 2005 and 2006:


				Weighted
	Number of			Average
	Units			Grant Price
Outstanding, beginning of period		267,702		$	10.77
Granted		—			—
Exercised		(267,351	)		10.77
Cancelled		(351	)		10.73

Outstanding, end of period		—		$	10.77


Exercisable, end of period		—		$	—

The following table summarizes information about the restricted/performance units granted in 2007. A market price of $7.05 was used in the model for the period ending December 31, 2008. Expected volatility ranged from 9

percent to 15 percent and had a weighted average volatility of 9.8 percent. The average risk free rate ranged from 2 to 3.3 percent. The expected option terms ranged from one year to two years.


	PTUs and RTUs
	December 31, 2008
				Weighted
	Number of			Average
	Units			Grant Price
Outstanding, beginning of period		108,717		$	23.64
Granted		—			—
Exercised		(20,645	)		20.39
Cancelled		(1,080	)		24.10

Outstanding, end of period		86,992		$	24.10


Exercisable, end of period		—		$	—

Unit Appreciation Right Plan

In 2004, the predecessor adopted the Unit Appreciation Right Plan for Employees and Consultants (the “UAR Plan”). Under the UAR Plan, certain employees of the predecessor were granted unit appreciation rights (“UARs”). The UARs entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units of Provident (“Phantom Units”). The exercise price and the vesting terms of the UARs were determined at the sole discretion of the Plan Administrator at the time of the grant. The UAR Plan was replaced with the BreitBurn Management LTIP at the end of September 2005. The grants issued prior to the replacement of the UAR Plan fully vested in 2008.

UARs vest one third at the end of year one, one third at the end of year two and one third at the end of year three after grant. Upon vesting, the employee is entitled to receive a cash payment equal to the excess of the market price of Provident Energy Trust’s units (PVE units) over the exercise price of the Phantom Units at the grant date, adjusted for an additional amount equal to any Excess Distributions, as defined in the plan. The predecessor settles rights earned under the plan in cash.

The total compensation expense for the UAR plan is allocated between us and our predecessor. Our share of expense was an immaterial amount in 2008 under the UAR Plan. Our share of the aggregate liability under the UAR Plan was approximately $0.1 million at December 31, 2008. The liability primarily represents accrued expense related to unpaid distributions on the fully vested UARs. In the Black-Scholes option pricing model for this plan, the expected volatility used was 29 percent and the risk rate was 3.3 percent. The expected option term is less than one half year.

The following table summarizes the information about UARs:


	BreitBurn Management Company
	PVE indexed units
	December 31, 2008
	Number of			Weighted
	Appreciation			Average
	Rights			Exercise Price
Outstanding, beginning of period		154,323		$	9.16
Exercised		(69,994	)		9.18
Cancelled		—			—

Outstanding, end of period		84,329		$	9.96


Exercisable, end of period		84,329		$	9.96

Director Performance Units

Effective with the initial public offering, we also made grants of Restricted Phantom Units in the Partnership to the non-employee directors of our General Partner. Each phantom unit is accompanied by a distribution equivalent unit right entitling the holder to an additional number of

phantom units with a value equal to the amount of distributions paid on each of our Common Units until settlement. Upon vesting, the majority of the phantom units will be paid in Common Units, except for certain directors’ awards which will be settled in cash. The unit-settled awards are classified as equity and the cash-settled awards are classified as liabilities. The estimated fair value associated with these phantom units is expensed in the statement of income over the vesting period. The accumulated compensation expense for unit-settled awards is reported in equity and for cash-settled grants, it is reflected as a liability on the consolidated balance sheet.

We recorded compensation expense for the director’s phantom units of approximately $0.1 million in 2008. Our aggregate liability under the outstanding grants was $0.8 million at December 31, 2008 of which $0.4 million represents the unvested portion.

The following table summarizes information about the Director Performance Units:


	December 31, 2008
	Number of			Weighted
	Performance			Average
	Units			Grant Price
Outstanding, beginning of period		37,473		$	21.11
Granted		20,146			27.35
Exercised		(22,190	)		23.05

Outstanding, end of period		35,429		$	23.44


Exercisable, end of period		—		$	—

Restricted Phantom Units and Convertible Phantom Units

In connection with the changes to BreitBurn Management’s executive compensation program, the board of directors of our General Partner has approved two new types of awards under our LTIP, namely, Restricted Phantom Units (RPUs) and Convertible Phantom Units (CPUs). In December 2007, seven executives of our General Partner received 188,545 units of RPUs and 681,500 units of CPUs at a grant price of $30.29 per Common Unit. Each of the awards has the vesting commencement date of January 1, 2008. In November 2007, the Co-Chief Executive Officers also received 184,400 of Restricted Phantom Units (RPUs) at a grant price of $31.68 per Common Unit under our Long-Term Incentive Plan. Those executive officers received CPU grants because they are in the best position to influence our operating results and, therefore, the amount of distributions we make to holders of our Common Units. As discussed below, payments under CPUs are significantly tied to the amount of distributions we make to holders of our Common Units. As discussed further below, the number of CPUs ultimately awarded to each of these senior executives is based upon the level of distributions to common unitholders achieved during the term of the CPUs. The CPU grants vest over a longer-term period of up to five years. Therefore, these grants will not be made on an annual basis. New grants could be made at the board’s discretion at a future date after the present CPU grants have vested. A holder of an RPU is entitled to receive payments equal to quarterly distributions in cash at the time they are made. As a result, we believe that RPUs better incentivize holders of these awards to grow stable distributions for our common unitholders than do performance units. In 2008, the board of directors of the General Partner granted 245,290 RPUs to employees at a weighted average price of $20.44.

Restricted Phantom Units (RPUs).RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events. RPUs generally vest in three equal, annual installments on each anniversary of the vesting commencement date of the award. In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment.

Convertible Phantom Units (CPUs).CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the holder’s employment agreement, if applicable). Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management.

Prior to vesting, a holder of a CPU is entitled to receive payments equal to the amount of distributions made by us with respect to each of the Common Units multiplied by the number of Common Unit equivalents underlying the CPUs at the time of the distribution. Initially, one Common Unit equivalent underlies each CPU at the time it was awarded to the grantee. However, the number of Common Unit equivalents underlying the CPUs increase at a compounded rate of 25 percent upon the achievement of each 5 percent compounded increase in the distributions paid by us to our common unitholders. Conversely, the number of Common Unit equivalents underlying the CPUs decrease at a compounded rate of 25 percent if the distributions paid by us to our common unitholders decreases at a compounded rate of 5 percent.

In the event that the CPUs vest on January 1, 2013 or because the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than $3.10 per Common Unit, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time (calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters).

In the event that CPUs vest due to the death or disability of the grantee or his or her termination without cause or good reason, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time, pro-rated based on when the death or disability occurred. First, the number of Common Unit equivalents would be calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters or, if such calculation would provide for a greater number of Common Unit equivalents, the most recently announced quarterly distribution level by us on an annualized basis. Then, this number would be pro rated by multiplying it by a percentage equal to:

	•		if such termination occurs on or before December 31, 2008, a percentage equal to 40 percent;

	•		if such termination occurs on or before December 31, 2009, a percentage equal to 60 percent;

	•		if such termination occurs on or before December 31, 2010, a percentage equal to 80 percent; and

	•		if such termination occurs on or after January 1, 2011, a percentage equal to 100 percent.

In 2008, we recognized compensation expense of $7.5 million related to its CPUs and RPUs.

The following table summarizes information about the CPUs and RPUs for the year ended December 31, 2008:


	Number of			Weighted
	RPU			Average
	Units			Grant Price
Outstanding, beginning of period (a)		372,945		$	30.98
Granted		245,290			20.44
Cancelled		(10,972	)		20.83

Outstanding, end of period		607,263		$	26.91


Exercisable, end of period		—		$	—

16. Commitments and Contingencies

Lease Rental Obligations

We had operating leases for office space and other property and equipment having initial or remaining noncancelable lease terms in excess of one year. Our future minimum rental payments for operating leases at December 31, 2008 are presented below:


	Payments Due by Year
*Thousands of dollars*	2009		2010		2011		2012		2013		after 2013		Total
Operating leases	$	2,232	$	2,126	$	1,989	$	1,656	$	1,272	$	2,143	$	11,418

BreitBurn Management, our wholly owned subsidiary, has office, vehicle (primarily work vehicles used in our field operations) and office equipment leases. Net rental payments made under non-cancelable operating leases were $2.88 million in 2008.

Surety Bonds and Letters of Credit

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At December 31, 2008, we had $10.1 million in surety bonds and we had $0.3 million in letters of credit outstanding.

Other

On October 31, 2008, Quicksilver, an owner of more than five percent of our Common Units, instituted a lawsuit in the District Court of Tarrant County, Texas naming us as a defendant along with BreitBurn GP, BOLP, BOGP, Randall H. Breitenbach, Halbert S. Washburn, Gregory J. Moroney, Charles S. Weiss, Randall J. Findlay, Thomas W. Buchanan, Grant D. Billing and Provident. On December 12, 2008, Quicksilver filed an Amended Petition and asserted twelve different counts against the various defendants. The primary claims are as follows: Quicksilver alleges that BOLP breached the Contribution Agreement with Quicksilver, dated September 11, 2007, based on allegations that we made false and misleading statements relating to its relationship with Provident. Quicksilver also alleges common law and statutory fraud claims against all of the defendants by contending that the defendants made false and misleading statements to induce Quicksilver to acquire Common Units in us. Finally, Quicksilver alleges claims for breach of the Partnership’s First Amended and Restated Agreement of Limited Partnership, dated as of October 10, 2006 (“Partnership Agreement”), and other common law claims relating to certain transactions and an amendment to the Partnership Agreement that occurred in June 2008. Quicksilver seeks a temporary and permanent injunction, a declaratory judgment relating primarily to the interpretation of the Partnership Agreement and the voting rights in that agreement, indemnification, punitive or exemplary damages, avoidance of BreitBurn GP’s assignment to us of all of its economic interest in us, attorneys’ fees and costs, pre- and post-judgment interest, and monetary damages. The parties to the lawsuit are engaged in discovery pursuant to an agreed scheduling order. On February 17, 2009, we filed a motion for summary judgment which is scheduled to be heard on March 26, 2009. A hearing on Quicksilver’s request for a temporary injunction is scheduled for April 6, 2009.

We are defending ourselves vigorously in connection with the allegations in the lawsuit. Because this lawsuit still is at an early stage, we cannot predict the manner and timing of the resolution of the lawsuit or its outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in the lawsuit.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings other than as mentioned above. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject.

17. Retirement Plan

BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. BreitBurn Management has a defined contribution retirement plan, which covers substantially all of its employees who have completed at least three months of service. The plan provides for BreitBurn Management to make regular contributions based on employee contributions as provided for in the plan agreement. Employees fully vest in BreitBurn Management’s contributions after five years of service. BEC is charged for a portion of the matching contributions made by BreitBurn Management. For the year ended December 31, 2008, the matching contribution paid by us was $0.4 million.

18. Significant Customers

We sell oil, natural gas and natural gas liquids primarily to large domestic refiners. For the year ended December 31, 2008, our purchasers which accounted for 10 percent or more of net sales were ConocoPhillips which accounted for 25 percent of net sales and Marathon Oil Company which accounted for 13 percent of net sales.

19. Minority Interest

On May 25, 2007, BOLP entered into a Purchase and Sale Agreement with TIFD X-III LLC (“TIFD”), pursuant to which it acquired TIFD’s 99 percent limited partner interest in BreitBurn Energy Partners I, L.P. (“BEPI”) for a total purchase price of approximately $82 million (the “BEPI Acquisition”). As such, we are fully consolidating the results of BEPI and thus are recognizing a minority interest liability representing the book value of the general partner’s interests. At December 31, 2008, the amount of this minority interest liability was $0.5 million. The general partner of BEPI holds a 35 percent reversionary interest under the existing limited partnership agreement applicable to the properties. Based on year end price and cost projections, the reversionary interest payout is not expected to occur.

20. Subsequent Events

On January 22, 2009, we terminated a portion of our 2011 and 2012 crude oil swaps (1,939 Bbls/d at $90.00 per Bbl) and replaced them with new contracts with the same counterparty for the same volumes at market prices ($63.30 per Bbl). We realized $32.3 million from this termination. On January 26, 2009, we terminated a portion of our 2011 and 2012 natural gas swaps and replaced them with new contracts with the same counterparty for the same volumes at market prices. We realized $13.3 million from this termination. Proceeds from these contracts were used to pay down debt.

On February 13, 2009, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on February 9, 2009. The distribution that was paid to unitholders was $0.52 per Common Unit. In February 2009 we also made payments equivalent to the distribution made to unitholders of $0.7 million on Restricted Phantom Units and Convertible Phantom Units issued under our Long-Term Incentive Plans.

On February 19, 2009, 134,377 Common Units were issued to employees under our 2006 Long-Term Incentive Plan, increasing our outstanding Common Units to 52,770,011. See Note 15 for information regarding our unit based compensation plans.

21. Oil and Natural Gas Activities (Unaudited)

Costs incurred

Our oil and natural gas activities are conducted in the United States. The following table summarizes the costs incurred by us for the year ended December 31, 2008:


*Thousands of dollars*
Property acquisition costs
Proved	$	—
Unproved		—
Development costs		129,503
Asset retirement costs		1,363
Pipelines and processing facilities		—

Total	$	130,866

Capitalized costs

The following table presents the aggregate capitalized costs subject to depreciation, depletion and amortization relating to oil and gas activities, and the aggregate related accumulated allowance for the year ended December 31, 2008.



*Thousands of dollars*
Proved properties and related producing assets	$	1,734,932
Pipelines and processing facilities		112,726
Unproved properties		209,873
Accumulated depreciation, depletion and amortization		(223,575	)

	$	1,833,956

The average DD&A rate per equivalent unit of production for the year ended December 31, 2008 was $26.42 per Boe.

Results of operations for oil and gas producing activities

The results of operations from oil and gas producing activities below exclude non-oil and gas revenues and expenses, general and administrative expenses, interest expenses and interest income for the year ended December 31, 2008.




*Thousands of dollars*
Oil, natural gas and NGL sales	$	467,381
Realized loss on derivative instruments		(55,946	)
Unrealized gain on derivative instruments		388,048
Operating costs		(149,681	)
Depreciation, depletion, and amortization		(178,657	)
Pre-tax Income		471,145
Income tax expense		1,939

Results of producing operations	$	469,206

Supplemental reserve information

The following information summarizes our estimated proved reserves of oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the year ended December 31, 2008. The following reserve information is based upon reports by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services, independent petroleum engineering firms. The estimates are prepared in accordance with SEC regulations.

Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of the estimated proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are

ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure of discounted net future cash flows shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Decreases in the prices of oil and natural gas and increases in operating expenses have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and revenues, profitability and cash flow.

The following table sets forth certain data pertaining to our estimated proved and proved developed reserves for the year ended December 31, 2008.


	Oil			Gas
*In Thousands*	(MBbl)			(MMcf)
Proved Reserves
Beginning balance		58,095			505,069
Revision of previous estimates^(a)		(29,106	)		(16,251	)
Production		(3,079	)		(22,384	)


Ending balance		25,910			466,434

Proved Developed Reserves

Beginning balance		52,103			457,444
Ending balance		23,346			433,780


(a)		Additions due to infill drilling are classified in Revisions and were approximately 741 MBbl for oil and 35,834 MMcf for natural gas in 2008.

Standardized measure of discounted future net cash flows

The Standardized Measure of discounted future net cash flows relating to our estimated proved crude oil and natural gas reserves as of December 31, 2008 is presented below:


*Thousands of dollars*
Future cash inflows		3,523,524
Future development costs		(212,951	)
Future production expense		(1,843,986	)

Future net cash flows		1,466,587
Discounted at 10% per year		(874,327	)

Standardized measure of discounted future net cash flows	$	592,260

The standardized measure of discounted future net cash flows discounted at ten percent from production of proved reserves was developed as follows:

	1.		An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

	2.		In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our estimated proved properties and the present value thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. We have entered into various arrangements to fix or limit the prices relating to a portion of our oil and gas production. Arrangements in effect at December 31, 2008 are discussed in Note 14. Such risk management arrangements are not reflected in the reserve reports. Representative market prices at the as-of date for the reserve reports as of December 31, 2008 were $44.60 ($20.12 for Wyoming), per barrel of oil, and $5.71, per MMBTU of gas.

	3.		The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. Future net cash flows assume no future income tax expense as we are essentially a non-taxable entity except for two tax paying corporations whose future income tax liabilities on a discounted basis are insignificant.

The principal sources of changes in the Standardized Measure of the future net cash flows for the year ended December 31, 2008 is presented below:


*Thousands of dollars*
*Beginning balance*	$	1,912,467
Sales, net of production expense		(317,700	)
Net change in sales and transfer prices, net of production expense		(1,306,752	)
Previously estimated development costs incurred during year		57,694
Changes in estimated future development costs		(98,064	)
Extensions, discoveries and improved recovery, net of costs		—
Purchase of reserves in place		—
Revision of quantity estimates and timing of estimated production		153,368
Accretion of discount		191,247

*Ending balance*	$	592,260

22. Quarterly Financial Data (Unaudited)


	Year Ended December 31, 2008
	First			Second			Third		Fourth
*Thousands of dollars*	Quarter			Quarter			Quarter		Quarter
Oil, natural gas and natural gas liquid sales	$	115,849		$	139,962		$	130,249	$	81,321
Gains (losses) on derivative instruments		(83,387	)		(353,282	)		407,441		361,330
Other revenue, net		875			643			806		596

Total revenue	$	33,337		$	(212,677	)	$	538,496	$	443,247

Operating income (loss) (1)		(34,455	)		(282,267	)		468,625		277,451

Net income (loss) (1)		(41,140	)		(286,240	)		454,454		251,162


	Year Ended December 31, 2008
	First			Second			Third		Fourth
*Thousands of dollars*	Quarter			Quarter			Quarter		Quarter
Limited Partners’ interest in loss (1)		(40,867	)		(284,494	)		454,454		251,162


Basic net loss per limited partner unit (2)		(0.61	)		(4.39	)		8.63		4.77
Diluted net loss per limited partner unit (2)		(0.61	)		(4.39	)		8.41		4.65


Basic units outstanding		67,020,641			64,807,563			52,635,634		52,635,634
Diluted units outstanding		67,020,641			64,807,563			54,062,291		54,019,830


(1)		Fourth quarter 2008 includes $86.4 million for total impairments and price related adjustments and depreciation expense.

(2)		Due to changes in the number of weighted average common units outstanding that may occur each quarter, the earnings per unit amounts for certain quarters may not be additive.


Exhibits


Exhibit No.			Sequential Description

	**2	.1	Contribution Agreement, dated September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference.)
	**2	.2	Purchase and Sale Agreement, dated as of July 3, 2008, among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus Development, L.P., and Perot Investment Partners, Ltd., as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.1 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
	**2	.3	Purchase and Sale Agreement, dated as of July 3, 2008, among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P., Chief Resources, LP, Hillwood Alliance Operating Company, L.P., Chief Resources Alliance Pipeline LLC, Chief Oil & Gas LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark Rollins, as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.2 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
	3	.1	Amended and Restated Certificate of Incorporation of Quicksilver Resources Inc. filed with the Secretary of State of the State of Delaware on May 21, 2008 (filed as Exhibit 4.1 to the Company’s Form S-3, File No. 333-151847, filed June 23, 2008 and included herein by reference).
	3	.2	Amended and Restated Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc. (filed as Exhibit 3.3 to the Company’s Form 10-Q filed May 6, 2006 and included herein by reference).
	3	.3	Amended and Restated Bylaws of Quicksilver Resources Inc. (filed as Exhibit 3.1 to the Company’s Form 8-K filed November 16, 2007 and included herein by reference).
	4	.1	Indenture Agreement for 1.875% Convertible Subordinated Debentures Due 2024, dated as of November 1, 2004, between Quicksilver Resources Inc., as Issuer, and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed November 1, 2004 and included herein by reference).
	4	.2	Indenture, dated as of December 22, 2005, between Quicksilver Resources Inc. and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.7 to the Company’s Form S-3, File No. 333-130597, filed December 22, 2005 and included herein by reference).
	4	.3	First Supplemental Indenture, dated as of March 16, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed March 21, 2006 and included herein by reference).
	4	.4	Third Supplemental Indenture, dated as of September 26, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 10-Q filed November 7, 2006 and included herein by reference).
	4	.5	Fifth Supplemental Indenture, dated as of June 27, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed June 30, 2008 and included herein by reference).
	4	.6	Sixth Supplemental Indenture, dated as of July 10, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed July 10, 2008 and included herein by reference).


Exhibit No.			Sequential Description

	4	.7	Amended and Restated Rights Agreement, dated as of December 20, 2005, between Quicksilver Resources Inc. and Mellon Investor Services LLC, as Rights Agent (filed as Exhibit 4.1 to the Company’s Form 8-A/A (Amendment No. 1) filed December 21, 2005 and included herein by reference).
	10	.1	Master Gas Purchase and Sale Agreement, dated March 1, 1999, between Quicksilver Resources Inc. and Reliant Energy Services, Inc. (filed as Exhibit 10.10 to the Company’s Form S-1, File No. 333-89229, filed November 1, 2004 and included herein by reference).
	10	.2	Wells Agreement dated as of December 15, 1970, between Union Oil Company of California and Montana Power Company (filed as Exhibit 10.5 to the Company’s Predecessor, MSR Exploration Ltd.’s Form S-4/A, File No. 333-29769, filed August 21, 1997 and included herein by reference).]
	+ 10	.3	Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.4	Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.5	Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.6	Form of Retention Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
	+ 10	.7	Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
	+ 10	.8	Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
	+ 10	.9	Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.10	Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 18, 2005 and included herein by reference).
	+ 10	.11	Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.12	Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.13	Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.14	Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Cash Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.15	Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Stock Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).


Exhibit No.			Sequential Description

	+ 10	.16	Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.5 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.17	Form of Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.18	Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.8 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.19	Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.5 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.20	Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.7 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.21	Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
	+ 10	.22	Description of Non-Employee Director Compensation for Quicksilver Resources Inc. (filed as Exhibit 10.11 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.23	Quicksilver Resources Inc. 2007 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 16, 2007 and included herein by reference).
	+ 10	.24	Description of 2007 Cash Bonus (filed as Exhibit 10.3 to the Company’s Form 10-Q filed May 9, 2007 and included herein by reference).
	+ 10	.25	Quicksilver Resources Inc. 2008 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 14, 2007 and included herein by reference).
	+ 10	.26	Quicksilver Resources Inc. 2009 Executive Bonus Plan (filed as Exhibit 10.10 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.27	Quicksilver Resources Inc. Amended and Restated Change in Control Retention Incentive Plan (filed as Exhibit 10.9 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.28	Quicksilver Resources Inc. Second Amended and Restated Key Employee Change in Control Retention Incentive Plan (filed as Exhibit 10.8 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.29	Quicksilver Resources Inc. Amended and Restated Executive Change in Control Retention Incentive Plan (filed as Exhibit 10.7 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.30	Form of Director and Officer Indemnification Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 26, 2005 and included herein by reference).
	10	.31	Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Inc. and the lenders identified therein (filed as Exhibit 10.1 to the Company’sForm 8-K filed February 12, 2007 and included herein by reference).
	10	.32	Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Canada Inc. and the lenders and/or agents identified therein (filed as Exhibit 10.2 to the Company’s Form 8-K filed February 12, 2007 and included herein by reference).


Exhibit No.			Sequential Description

	10	.33	Fourth Amendment to Combined Credit Agreements, dated as of June 20, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 25, 2008 and included herein by reference).
	10	.34	Fifth Amendment to Combined Credit Agreements, dated as of August 4, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 5, 2008 and included herein by reference).
	10	.35	Credit Agreement, dated as of August 8, 2008, among Quicksilver Resources Inc., the lenders party thereto and Credit Suisse, Cayman Islands Branch, as administrative agent (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 8, 2008 and included herein by reference).
	10	.36	Registration Rights Agreement, dated as of November 1, 2007, between Quicksilver Resources Inc. and BreitBurn Energy L.P. (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference).
	+10	.37	2007 Equity Plan (filed as Exhibit 99.1 to Quicksilver Gas Services LP’s Form S-8,File No. 333-145326, filed August 10, 2007 and included herein by reference).
	+10	.38	Form of Phantom Unit Award Agreement for Non-Directors (Cash) (filed as Exhibit 10.10 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
	+10	.39	Form of Phantom Unit Award Agreement for Non-Directors (Units) (filed as Exhibit 10.11 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 25, 2007 and included herein by reference).
	+10	.40	Quicksilver Gas Services LP Annual Bonus Plan (filed as Exhibit 10.1 to Quicksilver Gas Services LP’s Form 8-K, File No. 001-33631, filed December 13, 2007 and included herein by reference).
	+10	.41	Form of Indemnification Agreement by and between Quicksilver Gas Services GP LLC and its officers and directors (filed as Exhibit 10.7 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
	*** 21	.1	List of subsidiaries of Quicksilver Resources Inc.
	* 23	.1	Consent of Deloitte & Touche LLP.
	* 23	.2	Consent of Schlumberger Data and Consulting Services.
	* 23	.3	Consent of LaRoche Petroleum Consultants, Ltd.
	* 23	.4	Consent of Schlumberger Data and Consulting Services.
	* 23	.5	Consent of Netherland, Sewell & Associates, Inc.
	* 23	.6	Consent of PricewaterhouseCoopers LLP
	* 23	.7	Consent of Deloitte & Touche LLP.
	* 23	.8	Consent of Deloitte & Touche LLP.
	* 23	.9	Consent of Deloitte & Touche LLP.
	*** 24	.1	Power of Attorney.
	* 31	.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	* 31	.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	* 32	.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith.

**		Excludes schedules and exhibits we agree to furnish supplementally to the SEC upon request.

***		Filed with the Company’s original Annual Report on Form 10-K filed on March 3, 2009.

+		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.


		By: /s/ Philip Cook
Dated: June 16, 2009		Philip Cook Senior Vice President — Chief Financial Officer

Exhibit Index


Exhibit No.			Sequential Description

	**2	.1	Contribution Agreement, dated September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference.)
	**2	.2	Purchase and Sale Agreement, dated as of July 3, 2008, among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus Development, L.P., and Perot Investment Partners, Ltd., as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.1 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
	**2	.3	Purchase and Sale Agreement, dated as of July 3, 2008, among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P., Chief Resources, LP, Hillwood Alliance Operating Company, L.P., Chief Resources Alliance Pipeline LLC, Chief Oil & Gas LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark Rollins, as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.2 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
	3	.1	Amended and Restated Certificate of Incorporation of Quicksilver Resources Inc. filed with the Secretary of State of the State of Delaware on May 21, 2008 (filed as Exhibit 4.1 to the Company’s Form S-3, File No. 333-151847, filed June 23, 2008 and included herein by reference).
	3	.2	Amended and Restated Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc. (filed as Exhibit 3.3 to the Company’s Form 10-Q filed May 6, 2006 and included herein by reference).
	3	.3	Amended and Restated Bylaws of Quicksilver Resources Inc. (filed as Exhibit 3.1 to the Company’s Form 8-K filed November 16, 2007 and included herein by reference).
	4	.1	Indenture Agreement for 1.875% Convertible Subordinated Debentures Due 2024, dated as of November 1, 2004, between Quicksilver Resources Inc., as Issuer, and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed November 1, 2004 and included herein by reference).
	4	.2	Indenture, dated as of December 22, 2005, between Quicksilver Resources Inc. and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.7 to the Company’s Form S-3, File No. 333-130597, filed December 22, 2005 and included herein by reference).
	4	.3	First Supplemental Indenture, dated as of March 16, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed March 21, 2006 and included herein by reference).
	4	.4	Third Supplemental Indenture, dated as of September 26, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 10-Q filed November 7, 2006 and included herein by reference).
	4	.5	Fifth Supplemental Indenture, dated as of June 27, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed June 530, 2008 and included herein by reference).
	4	.6	Sixth Supplemental Indenture, dated as of July 10, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed July 10, 2008 and included herein by reference).

	4	.7	Amended and Restated Rights Agreement, dated as of December 20, 2005, between Quicksilver Resources Inc. and Mellon Investor Services LLC, as Rights Agent (filed as Exhibit 4.1 to the Company’s Form 8-A/A (Amendment No. 1) filed December 21, 2005 and included herein by reference).


Exhibit No.			Sequential Description
	10	.1	Master Gas Purchase and Sale Agreement, dated March 1, 1999, between Quicksilver Resources Inc. and Reliant Energy Services, Inc. (filed as Exhibit 10.10 to the Company’s Form S-1, File No. 333-89229, filed November 1, 2004 and included herein by reference).
	10	.2	Wells Agreement dated as of December 15, 1970, between Union Oil Company of California and Montana Power Company (filed as Exhibit 10.5 to the Company’s Predecessor, MSR Exploration Ltd.’s Form S-4/A, File No. 333-29769, filed August 21, 1997 and included herein by reference).]
	+ 10	.3	Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.4	Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.5	Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.6	Form of Retention Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
	+ 10	.7	Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
	+ 10	.8	Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
	+ 10	.9	Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.10	Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 18, 2005 and included herein by reference).
	+ 10	.11	Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.12	Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.13	Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.14	Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Cash Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.15	Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Stock Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.16	Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.5 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).


Exhibit No.			Sequential Description

	+ 10	.17	Form of Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.18	Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.8 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.19	Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.5 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.20	Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.7 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.21	Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
	+ 10	.22	Description of Non-Employee Director Compensation for Quicksilver Resources Inc. (filed as Exhibit 10.11 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.23	Quicksilver Resources Inc. 2007 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 16, 2007 and included herein by reference).
	+ 10	.24	Description of 2007 Cash Bonus (filed as Exhibit 10.3 to the Company’s Form 10-Q filed May 9, 2007 and included herein by reference).
	+ 10	.25	Quicksilver Resources Inc. 2008 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 14, 2007 and included herein by reference).
	+ 10	.26	Quicksilver Resources Inc. 2009 Executive Bonus Plan (filed as Exhibit 10.10 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.27	Quicksilver Resources Inc. Amended and Restated Change in Control Retention Incentive Plan (filed as Exhibit 10.9 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.28	Quicksilver Resources Inc. Second Amended and Restated Key Employee Change in Control Retention Incentive Plan (filed as Exhibit 10.8 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.29	Quicksilver Resources Inc. Amended and Restated Executive Change in Control Retention Incentive Plan (filed as Exhibit 10.7 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.30	Form of Director and Officer Indemnification Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 26, 2005 and included herein by reference).
	10	.31	Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Inc. and the lenders identified therein (filed as Exhibit 10.1 to the Company’sForm 8-K filed February 12, 2007 and included herein by reference).
	10	.32	Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Canada Inc. and the lenders and/or agents identified therein (filed as Exhibit 10.2 to the Company’s Form 8-K filed February 12, 2007 and included herein by reference).

	10	.33	Fourth Amendment to Combined Credit Agreements, dated as of June 20, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 25, 2008 and included herein by reference).


Exhibit No.			Sequential Description

	10	.34	Fifth Amendment to Combined Credit Agreements, dated as of August 4, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 5, 2008 and included herein by reference).
	10	.35	Credit Agreement, dated as of August 8, 2008, among Quicksilver Resources Inc., the lenders party thereto and Credit Suisse, Cayman Islands Branch, as administrative agent (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 8, 2008 and included herein by reference).
	10	.36	Registration Rights Agreement, dated as of November 1, 2007, between Quicksilver Resources Inc. and BreitBurn Energy L.P. (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference).
	+10	.37	2007 Equity Plan (filed as Exhibit 99.1 to Quicksilver Gas Services LP’s Form S-8,File No. 333-145326, filed August 10, 2007 and included herein by reference).
	+10	.38	Form of Phantom Unit Award Agreement for Non-Directors (Cash) (filed as Exhibit 10.10 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
	+10	.39	Form of Phantom Unit Award Agreement for Non-Directors (Units) (filed as Exhibit 10.11 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 25, 2007 and included herein by reference).
	+10	.40	Quicksilver Gas Services LP Annual Bonus Plan (filed as Exhibit 10.1 to Quicksilver Gas Services LP’s Form 8-K, File No. 001-33631, filed December 13, 2007 and included herein by reference).
	+10	.41	Form of Indemnification Agreement by and between Quicksilver Gas Services GP LLC and its officers and directors (filed as Exhibit 10.7 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
	*** 21	.1	List of subsidiaries of Quicksilver Resources Inc.
	* 23	.1	Consent of Deloitte & Touche LLP.
	* 23	.2	Consent of Schlumberger Data and Consulting Services.
	* 23	.3	Consent of LaRoche Petroleum Consultants, Ltd.
	* 23	.4	Consent of Schlumberger Data and Consulting Services.
	* 23	.5	Consent of Netherland, Sewell & Associates, Inc.
	* 23	.6	Consent of PricewaterhouseCoopers LLP.
	* 23	.7	Consent of Deloitte & Touche LLP.
	* 23	.8	Consent of Deloitte & Touche LLP.
	* 23	.9	Consent of Deloitte & Touche LLP.
	*** 24	.1	Power of Attorney.
	* 31	.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	* 31	.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	* 32	.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith.

**		Excludes schedules and exhibits we agree to furnish supplementally to the SEC upon request.

***		Filed with the Company’s original Annual Report on Form 10-K filed on March 3, 2009.

+		Identifies management contracts and compensatory plans or arrangements.



PART I
	ITEM 1A.	Risk Factors

PART II
	ITEM 6.	Selected Financial Data
	ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	ITEM 8.	Financial Statements and Supplementary Data
	ITEM 9A.	Controls and Procedures
PART IV
	ITEM 15.	Exhibits and Financial Statement Schedules
		Signatures

EX-23.1
EX-23.2
EX-23.3
EX-23.4
EX-23.5
EX-23.6
EX-23.7
EX-23.8
EX-23.9
EX-31.1
EX-31.2
EX-32.1

Quicksilver Resources (KWK) Inactive 10-K/A2008 FY Annual report (amended)