10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

x    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

OR

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

For the transition period from             to             

Commission file number: 001-14837

QUICKSILVER RESOURCES INC.

(Exact name of registrant as specified in its charter)

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

777 West Rosedale St., Suite 300, Fort Worth, Texas 76104

(Address of principal executive offices) (Zip Code)

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

(Former name, former address and former fiscal year, if changed since last report)

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. Yes x No ¨

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. Yes ¨ No x

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

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. ¨

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

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

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

As of June 30, 2005, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $2,053,873,265 based on the closing sale price of $43.89 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 15, 2006
Common Stock, $0.01 par value per share	76,295,557 shares

DOCUMENTS INCORPORATED BY REFERENCE

Document	Parts Into Which Incorporated
Proxy Statement for the Annual Meeting of Stockholders to be held May 23, 2006	Part III

INDEX TO ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2005

PART I
ITEM 1.	Business	3
ITEM 1A.	Risk Factors	10
ITEM 1B.	Unresolved Staff Comments	19
ITEM 2.	Properties	19
ITEM 3.	Legal Proceedings	26
ITEM 4.	Submission of Matters to a Vote of Security Holders	27
PART II
ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
ITEM 6.	Selected Financial Data	29
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk	51
ITEM 8.	Financial Statements and Supplementary Data	52
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	92
ITEM 9A.	Controls and Procedures	92
ITEM 9B.	Other Information	95
PART III
ITEM 10.	Directors and Executive Officers of the Registrant	96
ITEM 11.	Executive Compensation	96
ITEM 12.	Security Ownership of Certain Management and Beneficial Owners and Management and Related Stockholder Matters	96
ITEM 13.	Certain Relationships and Related Transactions	96
ITEM 14.	Principal Accountant Fees and Services	96
PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	97
	Signatures	101

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.

All share and per share amounts have been adjusted to reflect a two-for-one stock split effected in the form of a stock dividend in June 2004 and a three-for-two stock split effected in the form of a stock dividend in June 2005.

Quantities of natural gas are expressed in this report in terms of thousand cubic feet (“Mcf”), million cubic feet (“MMcf”) or billion cubic feet (“Bcf”). Crude oil and natural gas liquids are quantified in terms of barrels (“Bbl”), thousands of barrels (“MBbl”) or millions of barrels (“MMBbl”). Crude oil and natural gas liquids are compared to natural gas in terms of thousands of cubic feet of natural gas equivalent (“Mcfe”), millions of cubic feet of natural gas equivalent (“MMcfe”) or billions of cubic feet of natural gas equivalent (“Bcfe”). One barrel of crude oil or natural gas liquids is the energy equivalent of six Mcf of natural gas. Natural gas volumes also may be expressed in terms of one million British thermal units (“MMBtu”), which is approximately equal to one Mcf. Daily natural gas and crude oil production is signified by the addition of the letter “d” to the end of the terms defined above. With respect to information relating to working interests in wells or acreage, “net” natural gas and crude oil wells or acreage is determined by multiplying gross wells or acreage by the working interest we own. Unless otherwise specified, all reference to wells and acres are gross.

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PART I

ITEM 1.    Business

We are a Fort Worth, Texas-based independent oil and gas company engaged in the development and production of natural gas, natural gas liquids (“NGLs”) and crude oil, which we attain through a combination of developmental drilling, exploitation and property acquisitions. Our efforts are principally focused on unconventional reservoirs, such as hydrocarbons found in fractured shales, coal seams and tight sands. We were organized as a Delaware corporation in 1997 and became a public company in 1999 through a merger with MSR Exploration Ltd. (“MSR”). Mercury Exploration Company (“Mercury”), which made significant contributions of properties to us at the time of our formation, was founded by Frank Darden in 1963 to explore for and develop conventional oil and gas properties in the United States. As of December 31, 2005, members of the Darden family, together with Mercury and another entity entirely controlled by members of the Darden family, beneficially owned approximately 35% of our outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self serve on our Board of Directors along with four independent directors. Thomas Darden is Chairman of our Board, Glenn Darden is our President and Chief Executive Officer and Anne Darden Self is our Vice President-Human Resources.

Our operations are concentrated in the Michigan, Western Canadian Sedimentary and Fort Worth Basins. At December 31, 2005, we had estimated proved reserves of 1,114 Bcfe, of which approximately 92% were natural gas and approximately 77% were proved developed. Our asset base is geographically diverse, with approximately 52% of our reserves in Michigan, 27% in Canada and 16% in Texas. Since going public in 1999, we have grown our reserves and production at a compound annual growth rate of 23% and 15%, respectively. We believe that much of our future growth will be through development, exploitation and exploration of our leasehold interests including those in coal bed methane (“CBM”) formations in Alberta, Canada, the Barnett Shale formation in the Fort Worth Basin in north Texas, and Barnett Shale and Woodford Shale formations in the Delaware Basin in west Texas. Although our Michigan operations generate significant cash flow, we believe that our future reserve and production growth will come primarily from our Canadian and Texas operations. These projects represent an extension of our significant expertise in unconventional gas reserves.

We intend to focus our capital-spending program primarily on the continued development, exploitation and exploration of our properties in Alberta and Texas. For 2006, we have established a capital budget of $566 million, of which we have allocated approximately $359 million for drilling activities, approximately $160 million for the construction of facilities to support our activities in Alberta, Texas and Michigan and approximately $47 million for acquisition of additional leasehold interests. The Canadian capital budget is approximately $123 million, which includes drilling approximately 451 (267 net) wells, the construction of gathering lines and gas processing facilities and acreage acquisition. Approximately $399 million of the U.S capital budget will be spent in Texas. We expect to drill approximately 85 (84.6 net) Barnett Shale wells, construct gas plant facilities and extend our gathering pipeline, acquire additional acreage and evaluate potential development opportunities in the Delaware Basin of west Texas by drilling four resource assessment wells. We also intend to commit approximately $39 million of the 2006 capital budget to our fractured shale interests in the Michigan Basin. The remaining $5 million of the 2006 capital expenditure budget is planned for our interests in Indiana/Kentucky and the Rocky Mountain Region.

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For the year ended December 31, 2005, we had average daily production of 140.9 MMcfed. The following table presents our December 31, 2005 reserves and our average daily production for the year ended December 31, 2005. In addition, our geographic segment information is included at note 20 of our consolidated financial statements included in Item 8 of this report.

Areas of Operations	Proved Reserves (Bcfe)	% Natural Gas		% Proved Developed		2005 Production (MMcfed)
Michigan	581.5	95	%	90	%	80.7
Alberta, Canada	304.9	100	%	66	%	40.7
Texas	183.1	74	%	48	%	10.5
Other	44.7	66	%	91	%	9.0
Total	1,114.2	92	%	77	%	140.9

We conduct our Canadian operations through our wholly owned subsidiary, MGV Energy Inc. (“MGV”). In 2000, we entered into a joint venture with EnCana Corporation (“EnCana”) to explore for CBM reserves on an area of over three million acres of land. In January 2003, MGV entered into an asset rationalization agreement with EnCana that divided the assets and rights subject to the joint venture and allowed us to pursue independent operations. Assets and rights received as a result of the agreement included an interest or an option to drill and earn in approximately 667,000 acres in Alberta. We have continued to acquire additional working interests in those areas as well as in other areas of the Western Canadian Sedimentary Basin where we held approximately 430,000 net acres as of December 31, 2005. At December 31, 2005, we had the opportunity to earn in approximately 63,000 additional net acres.

Net gas sales from our projects in Alberta averaged 40.7 MMcfd in 2005. At year-end, production from our CBM projects was approximately 49.0 MMcfd. During 2005, we drilled 483 (259.1 net) productive wells and installed eight CBM facilities for processing our natural gas production. As of December 31, 2005, we had 305 Bcf of Canadian proved reserves primarily attributable to our CBM projects. At December 31, 2005, Canada comprised 27% of our reserves, 29% of our annual production and $46.0 million, or 32%, of our cash flow from operations.

Since 2003, when we began exploration and development of the Barnett Shale formation in the Fort Worth Basin, we have drilled 44 (43.4 net) wells there. We drilled 36 (35.4 net) wells there in 2005 and anticipate drilling an additional 85 (84.6 net) wells there in 2006. At December 31, 2005, we had five drilling rigs working for us in the Fort Worth Basin and we expect to have ten rigs working for us there by the end of 2006. At December 31, 2005, we had 37 (36.6 net) operated wells and 15 (1.2 net) non-operated wells tied in to sales lines that were producing 23.0 net MMcfed. At December 31, 2005, we had 183 Bcfe of proved reserves from our interests in the Barnett Shale and a net acreage position of approximately 565,000 acres in Texas.

In the Michigan Antrim Shale, we drilled or participated in 67 (31.4 net) wells in 2005. Of our Antrim wells drilled in 2005, we reentered 10 vertical wells and drilled a horizontal leg from each existing well. As of December 31, 2005, our interests in the Antrim Shale had net production of 57.6 MMcfed, and proved reserves of 504 Bcfe. Additionally, we drilled three (3.0 net) Prairie due Chien (“PdC”) wells in our Garfield Richfield project and participated in one (0.5 net) PdC well. At December 31, 2005, net production for our Michigan non-Antrim properties was 20.9 MMcfed and total proved reserves were 78 Bcfe. In Indiana/Kentucky we drilled 26 (26 net) New Albany Shale wells in 2005. Our Indiana/Kentucky production was 5.4 MMcfd at December 31, 2005.

Business Strengths

High quality asset base with long reserve life. We had total proved reserves of 1,114 Bcfe as of December 31, 2005, of which approximately 92% were natural gas and approximately 77% were proved developed. The majority of these reserves are located in three core areas: the Michigan Basin, the Western Canadian Sedimentary Basin in Alberta, Canada and the Fort Worth Basin in Texas, which accounted for

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approximately 52%, 27% and 16%, respectively, of these reserves. Based on average daily production of 140.9 MMcfe for the year ended December 31, 2005, our implied reserve life (proved reserves divided by 2005 annual production) was 21.7 years and our implied proved developed reserve life was 16.6 years. We believe our assets are characterized by long reserve lives and predictable well production profiles. As of December 31, 2005, we were the operator of approximately 71% of our production.

Significant development and exploitation drilling inventory. As of December 31, 2005, we owned leases covering more than 1.7 million net acres in our core areas of operation, of which 71% were undeveloped. This drilling inventory should provide us with more than 4,000 identified drilling locations which we expect to exploit over the next eight to ten years. Our drilling success rate has averaged 99% over the past three years. We use 3D seismic data to enhance our ongoing drilling and development efforts as well as to identify new targets in both new and existing fields. For 2006, we have budgeted approximately $359 million for drilling projects.

Proven track record of organic reserve and production growth. Over the last three years, we have added approximately 470 Bcfe to our reserves, virtually all of which was achieved organically. This growth was the result of our ability to acquire attractive undeveloped acreage and apply our technical expertise to find and develop reserves and was accompanied by a significant increase in our overall production. In recent years, we have demonstrated this ability particularly in the Horseshoe Canyon formation in Alberta and the Barnett Shale formation in the Fort Worth Basin. We believe our current acreage position will enable us to continue our reserve and production growth.

Experienced management and technical teams. Our CEO, Glenn Darden, and our Chairman, Thomas Darden, have held executive positions at Quicksilver since it was formed and spent 18 and 22 years, respectively, with Mercury. Since then, they have successfully implemented a disciplined growth strategy with a primary focus on net asset value growth through the development of unconventional reserves. Our executive management is supported by a core team of technical and operating managers who have significant industry experience, including experience in unconventional reservoirs.

Business Strategy

Our business strategy is designed to achieve our principal objectives of growth in reserves, production and cash flow. Key elements of our business strategy include:

Focus on core areas of operation. We intend to continue to focus on exploiting our significant development inventory in our Canadian CBM properties and our Barnett Shale properties in the Fort Worth Basin. We plan to drill approximately 350 net development wells in these formations in 2006. We also plan to evaluate potential development opportunities in the Delaware Basin in west Texas and Mannville CBM in Canada by drilling resource assessment wells. We also plan to optimize our production in Michigan through horizontal recompletions and other infill drilling opportunities. We believe that operating in concentrated areas allows us to more efficiently deploy our resources and manage costs. In addition we can further leverage our base of technical expertise in these regions.

Pursue disciplined organic growth strategy. Through our activities in each of the Michigan, Western Canadian Sedimentary and Fort Worth Basins, we have developed significant expertise in developing and operating reservoirs found in fractured shales, coal seams and tight sands. We have focused on identifying and evaluating opportunities that allow us to apply this expertise and experience to the development and operation of other unconventional reservoirs. Our Horseshoe Canyon CBM play in Canada and our Barnett Shale play in Texas are the most significant examples of this strategy. The Delaware Basin in Texas and Mannville CBM in Canada represent our most recent opportunities to apply this strategy.

Enhance profitability through control and marketing of our equity natural gas and crude oil. We seek to maximize profitability by exercising control over the delivery of natural gas and crude oil from the field to central distribution pipelines and optimizing the markets to which we sell our production. We seek to achieve this

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by continuing to improve upon and add to our processing and distribution infrastructure. We believe this allows us to better manage the physical movement of our production and the costs of our operations by decreasing dependency on third party providers. We also monitor on a daily basis the spot markets and seek to sell our uncommitted production into the most attractive markets.

Maintain conservative financial profile. We believe that maintaining a conservative financial structure will position us to capitalize on opportunities to limit our financial risk. We have also established return thresholds for new projects. Finally, to help ensure a level of predictability in the prices we receive for our natural gas and crude oil production, we have entered into natural gas sales contracts with price floors and natural gas and crude oil financial hedges.

Marketing

We sell natural gas, NGLs and crude oil to a variety of customers, including utilities, major oil and gas companies or their affiliates, industrial companies, large trading and energy marketing companies and other users of petroleum products. Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. Accordingly, the loss of a single purchaser in the areas in which we sell our products would not materially affect our sales. During 2005, the largest purchaser of our products was DTE Energy Trading Inc., which accounted for approximately 10% of our total natural gas, NGL and crude oil sales.

Competition

We encounter substantial competition in acquiring oil and gas leases and properties, marketing natural gas and crude oil, securing personnel and conducting our drilling and field operations. Our competitors in development, exploitation, exploration, acquisitions and production include the major oil and gas companies as well as numerous independents and individual proprietors. See “Item 1A. Risk Factors.”

Governmental Regulation

Our operations are affected from time to time in varying degrees by political developments and U.S. and Canadian federal, state, provincial and local laws and regulations. In particular, natural gas and crude oil production and related operations are, or have been, subject to price controls, taxes and other laws and regulations relating to the industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the industry increases our cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted so we are unable to predict the future cost or impact of complying with such laws and regulations.

Environmental Matters

Our natural gas and crude oil exploration, development, production and pipeline gathering operations are subject to stringent U.S. and Canadian federal, state, provincial and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations to implement and enforce such laws, and compliance is often difficult and costly. Failure to comply may result in substantial costs and expenses, including possible civil and criminal penalties. These laws and regulations may:

• require the acquisition of a permit before drilling commences;

• restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production, processing and pipeline gathering activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, frontier and other protected areas;

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• require remedial action to prevent pollution from former operations such as plugging abandoned wells; and

• impose substantial liabilities for pollution resulting from operations.

In addition, these laws, rules and regulations may restrict the rate of natural gas and crude oil production below the rate that would otherwise exist. The regulatory burden on the industry increases the cost of doing business and consequently affects our profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, disposal or clean-up requirements could adversely affect our financial position, results of operations and cash flows. While we believe that we are in substantial compliance with current applicable environmental laws and regulations, and we have not experienced any materially adverse effect from compliance with these environmental requirements, we cannot assure you that this will continue in the future.

The U.S. Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the present or past owners or operators of the disposal site or sites where the release occurred and the companies that transported or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment. Furthermore, although petroleum, including natural gas and crude oil, is exempt from CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as “hazardous substances” under CERCLA and thus such wastes may become subject to liability and regulation under CERCLA. State initiatives to further regulate the disposal of crude oil and natural gas wastes are also pending in certain states, and these various initiatives could have adverse impacts on us.

Stricter standards in environmental legislation may be imposed on the industry in the future. For instance, legislation has been proposed in the U.S. Congress from time to time that would reclassify certain exploration and production wastes as “hazardous wastes” and make the reclassified wastes subject to more stringent handling, disposal and clean-up restrictions. Compliance with environmental requirements generally could have a materially adverse effect upon our financial position, results of operations and cash flows. Although we have not experienced any materially adverse effect from compliance with environmental requirements, we cannot assure you that this will continue in the future.

The U.S. Federal Water Pollution Control Act (“FWPCA”) imposes restrictions and strict controls regarding the discharge of produced waters and other petroleum wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of crude oil and other hazardous substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Federal effluent limitations guidelines prohibit the discharge of produced water and sand, and some other substances related to the natural gas and crude oil industry, into coastal waters. Although the costs to comply with zero discharge mandated under federal or state law may be significant, the entire industry will experience similar costs and we believe that these costs will not have a materially adverse impact on our financial condition and results of operations. Some oil and gas exploration and production facilities are required to obtain permits for their storm water discharges. Costs may be incurred in connection with treatment of wastewater or developing storm water pollution prevention plans.

The U.S. Resource Conservation and Recovery Act (“RCRA”), generally does not regulate most wastes generated by the exploration and production of natural gas and crude oil. RCRA specifically excludes from the

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definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy.” However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing solid hazardous waste may be significant, we do not expect to experience more burdensome costs than would be borne by similarly situated companies in the industry.

In addition, the U.S. Oil Pollution Act (“OPA”) requires owners and operators of facilities that could be the source of an oil spill into “waters of the United States,” a term defined to include rivers, creeks, wetlands and coastal waters, to adopt and implement plans and procedures to prevent any spill of oil into any waters of the United States. OPA also requires affected facility owners and operators to demonstrate that they have at least $35 million in financial resources to pay for the costs of cleaning up an oil spill and compensating any parties damaged by an oil spill. Substantial civil and criminal fines and penalties can be imposed for violations of OPA and other environmental statutes.

In Canada, the oil and gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be constructed, abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in substantial cash expenses, including possible fines and penalties.

In Alberta, environmental compliance has been governed by the Alberta Environmental Protection and Enhancement Act (“AEPEA”) since September 1, 1993. AEPEA imposes environmental responsibilities on oil and gas operators in Alberta and also imposes penalties for violations.

Employees

As of February 15, 2006, we had 384 full time employees and 16 part time employees. There are no collective bargaining agreements.

Executive Officers

The following information is provided with respect to our executive officers as of February 15, 2006.

Name	Age	Position(s)
Thomas F. Darden	52	Director and Chairman of the Board
Glenn Darden	50	Director, President and Chief Executive Officer
Anne Darden Self	48	Director and Vice President – Human Resources
Jeff Cook	49	Executive Vice President – Operations
John C. Cirone	56	Senior Vice President, General Counsel and Secretary
Philip W. Cook	44	Senior Vice President – Chief Financial Officer
D. Wayne Blair	49	Vice President, Controller and Chief Accounting Officer
William S. Buckler	44	Vice President – U.S. Operations
Robert N. Wagner	42	Vice President – Reservoir Engineering

The following biographies describe the business experience of our executive officers.

THOMAS F. DARDEN has served on our board of directors since December 1997. He also served at that time as President of Mercury Exploration Company (“Mercury”). During his term as President of Mercury, Mercury developed and acquired interests in over 1,200 producing wells in Michigan, Indiana, Kentucky, Wyoming, Montana, New Mexico and Texas. Prior to joining us, Mr. Darden was employed by Mercury or its

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parent corporation, Mercury Production Company, for 22 years. He became a director and the President of MSR on March 7, 1997. On January 1, 1998, he was named Chairman of the Board and Chief Executive Officer of MSR. He was elected our President when we were formed and then Chairman of the Board and Chief Executive Officer on March 4, 1999, the date of our acquisition of MSR. He served as our Chief Executive Officer until November 1999.

GLENN DARDEN has served on our board of directors since December 1997. Prior to that time, he served with Mercury for 18 years, and for the last five of those 18 years was the Executive Vice President of Mercury. Prior to working for Mercury, Mr. Darden worked as a geologist for Mitchell Energy Company LP (subsequently merged with Devon Energy). Mr. Darden became a director and Vice President of MSR on March 7, 1997, and was named President and Chief Operating Officer of MSR on January 1, 1998. He served as our Vice President until he was elected President and Chief Operating Officer on March 4, 1999. Mr. Darden became our Chief Executive Officer in November 1999.

ANNE DARDEN SELF has served on our board of directors since September 1999, and became our Vice President – Human Resources in July 2000. She is also currently President of Mercury, where she has worked since 1992. From 1988 to 1991, she was with Banc PLUS Savings Association in Houston, Texas. She was employed as Marketing Director and then spent three years as Vice President of Human Resources. She worked from 1987 to 1988 as an Account Executive for NW Ayer Advertising Agency. Prior to 1987, she spent several years in real estate management.

JEFF COOK became our Executive Vice President – Operations in January 2006, after serving as our Senior Vice President – Operations since July 2000. From 1979 to 1981, he held the position of Operations Supervisor with Western Company of North America. In 1981, he became a District Production Superintendent for Mercury and became Vice President of Operations in 1991 and Executive Vice President in 1998 of Mercury before joining us.

JOHN C. CIRONE was named as our Senior Vice President, General Counsel and Secretary in January 2006, after serving as our Vice President, General Counsel and Secretary since July 2002. He was employed by Union Pacific Resources from 1978 to 2000. During that time, he served in various positions in the Law Department and from 1997 to 2000 he was the Manager of Land and Negotiations. In 2000, he was promoted to the position of Assistant General Counsel of Union Pacific Resources. After leaving Union Pacific Resources in August 2000, Mr. Cirone was engaged in the private practice of law prior to joining us in July 2002.

PHILIP W. COOK became our Senior Vice President – Chief Financial Officer in October 2005. From October 2004 until October 2005, Mr. Cook served as President, Chief Financial Officer and Director of EcoProduct Solutions, a Houston-based chemical company. From August 2001 until September 2004, he served as Vice President and Chief Financial Officer of PPI Technology Services, an oilfield service company. From August 1993 to July 2001, he served in various capacities, including Vice President and Controller, Vice President and Chief Information Officer and Vice President of Audit, of Burlington Resources Inc., an independent oil and gas company engaged in exploration, development, production and marketing.

D. WAYNE BLAIR became our Vice President, Controller and Chief Accounting Officer in 2002, after serving as our Vice President – Controller since July 2000. He is a Certified Public Accountant with over 25 years of experience in the oil and gas industry. He was employed by Sabine Corporation from 1980 through 1988 where he held the position of Assistant Controller. From 1988 through 1994, he served as Controller for a group of private businesses involved in the oil and gas industry. Prior to joining us in April 2000 as Vice President – Controller, he served as Controller for Mercury since 1996.

WILLIAM S. BUCKLER became our Vice President – U.S. Operations in August 2005. He joined us in September 2003 as an Engineering Manager. Prior to that, he was an Operations/Engineering Supervisor with Mitchell Energy Company LP (subsequently merged with Devon Energy) from January 2002 until August 2003, and held various other positions with Mitchell Energy, including Region Engineer, from July 1997 until January 2002.

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ROBERT N. WAGNER became our Vice President – Reservoir Engineering in December 2002. He had served as our Vice President – Engineering since July 1999. From January 1999 to July 1999, he was our manager of eastern region field operations. From November 1995 to January 1999, Mr. Wagner held the position of District Engineer with Mercury. Prior to 1995, he was with Mesa, Inc. for over eight years and served as both drilling engineer and production engineer.

ITEM 1A.    Risk Factors

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. In evaluating us, you should consider carefully, among other things, the factors and the specific risks set forth below, and in documents we incorporate by reference. This annual report contains forward-looking statements that involve risks and uncertainties.

Because we have a limited operating history in certain of our operating areas, our future operating results are difficult to forecast, and our failure to sustain profitability in the future could adversely affect the market price of our common stock.

We cannot assure you that we will maintain the current level of revenues, natural gas and crude oil reserves or production we now attribute to the properties contributed to us when we were formed and those developed and acquired since our formation. Any future growth of our natural gas and crude oil reserves, production and operations could place significant demands on our financial, operational and administrative resources. Our failure to sustain profitability in the future could adversely affect the market price of our common stock.

Natural gas and crude oil prices fluctuate widely, and low prices could have a material adverse impact on our business.

Our revenues, profitability and future growth depend in part on prevailing natural gas and crude oil prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our senior secured credit facilities is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas 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. For example, the closing New York Mercantile Exchange (“NYMEX”) wholesale price of natural gas was at a six-year low of approximately $1.83 per Mcf for October of 2001, reached an all-time high of approximately $13.91 per Mcf for October of 2005 and subsequently declined to $8.40 per Mcf for February of 2006. 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;

• political conditions in oil and 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 affect natural gas and crude oil prices, we cannot predict whether prices will remain at current levels, increase or decrease in the future.

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If natural gas or crude oil prices decrease or our exploration and development efforts are unsuccessful, we may be required to take writedowns.

Our financial statements are prepared in accordance with generally accepted accounting principles. The reported financial results and disclosures were developed using certain significant accounting policies, practices and estimates, which are discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in this annual report. We employ the full cost method of accounting 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 and crude oil reserves. A write down of these capitalized costs could be required if natural gas and/or crude oil prices were to drop precipitously at a reporting period end. Future price declines or increased operating and capitalized costs without incremental increases in natural gas and crude oil reserves could also require us to record a write down.

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 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 this annual report.

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 and crude oil reserves are inherently imprecise.

Actual future production, natural gas and crude oil prices and revenues, 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 natural gas and crude oil prices and other factors, many of which are beyond our control.

At December 31, 2005, approximately 23% of our estimated proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our natural gas and crude oil reserves and the costs associated with these reserves in accordance with industry standards and SEC requirements, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that actual results will be as estimated.

You should not assume that the present value of future net revenues disclosed in this annual report is the current market value of our estimated natural gas and crude oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. 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 and crude oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the

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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 accurate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the accuracy of the 10% discount factor.

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

Approximately 57% of our 2005 production was from Michigan, approximately 29% was from Alberta, Canada and approximately 7% was from Texas. 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.

If our production levels were significantly reduced to levels below those for which we have entered into contractual delivery commitments, we would be required to purchase natural gas at market prices to fulfill our obligation under certain long-term contracts. This could adversely affect our cash flow to the extent any such shortfall related to our sales contracts with floor pricing.

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

We conduct our Canadian operations through MGV. At December 31, 2005, our proved Canadian reserves were estimated to be 305 Bcf. Capital expenditures relating to MGV’s operations are budgeted to be approximately $123 million in 2006, constituting approximately 22% of our total 2006 budgeted capital expenditures.

If our revenues decrease as a result of lower natural gas or crude oil prices or otherwise, we may have limited ability to maintain this level of capital expenditures. While our results to date indicate that net recoverable reserves on CBM lands could be substantial, we can offer you no assurance that development will occur as scheduled or that actual results will be in accordance with estimates.

Other risks of our operations in Canada include, among other things, 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 and expect to continue to experience substantial capital expenditure and working capital needs, particularly as a result of increases in our property acquisition and drilling activities. In the future, we will likely require additional financing in addition to cash generated from our operations to fund our planned growth. If revenues decrease as a result of lower natural gas or crude oil 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 acquisition, development drilling and other 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 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”,

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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 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 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, the payment of which could reduce or eliminate funds available for exploration, development or acquisitions. 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.

We may be unable to make additional acquisitions of producing properties or successfully integrate them into our operations.

A portion of our growth in recent years has been due to acquisitions of producing properties. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers to be favorable to us. We cannot assure you that we will be able to identify suitable acquisitions in the future, or that we will be able to finance these acquisitions on favorable terms or at all. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will be successful in the acquisition of any material producing property interests. Further, we cannot assure you that any future acquisitions that we make will be integrated successfully into our operations or will achieve desired profitability objectives.

The successful acquisition of producing properties requires an assessment of recoverable reserves, exploration potential, future natural gas and crude oil prices, operating costs, potential environmental and other liabilities and other factors beyond our control. These assessments are inexact and their accuracy inherently uncertain and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.

In addition, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geological characteristics or geographic location than existing properties. While our current operations are located primarily in Michigan, Alberta, Canada, Texas, Indiana/Kentucky and the Rocky Mountains, we cannot assure you that we will not pursue acquisitions of properties in other locations.

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 natural gas and crude oil reserves that are economically recoverable. Our proved reserves, a majority of which are in the mature Michigan Basin, will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. 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, production and cash flow through development and exploration of our existing properties and acquisitions of producing properties. We cannot assure you, however, that our planned exploration and

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development projects and acquisition activities will result in significant additional reserves or that we will have continuing success drilling productive wells. Furthermore, while our revenues may increase if prevailing natural gas and crude oil prices increase significantly, our finding costs for additional reserves also could increase.

We cannot control the activities on properties that we do not operate.

As of December 31, 2005, other companies operated properties that included approximately 29% of our proved reserves. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. As a result, the success and timing of our drilling and development activities on properties operated by others depend upon a number of factors that are outside of our control, including:

• timing and amount of capital expenditures;

• the operator’s expertise and financial resources;

• approval of other participants in drilling wells; and

• selection of technology.

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

At December 31, 2005, other companies owned processing plants and pipelines that delivered approximately 64% of our natural gas production to market in Michigan. Our Canadian production is delivered to market primarily by either the TransCanada or ATCO systems. We have no influence over the operation of these facilities and must depend upon the owners of these facilities to minimize any loss of processing and transportation capacity. This risk was highlighted in 2003 by the shutdown of CMS Energy Inc.’s and Michigan Consolidated Gas Co.’s processing plants in Michigan that resulted in an approximate 725 MMcf decrease in our 2003 production.

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 Chairman, our Chief Executive Officer and our other executive officers and key technical personnel. We cannot assure you that the services of these individuals will be available to us in the future. Because competition for experienced personnel in the oil and gas industry is intense, we cannot assure you that we would be able to find acceptable replacements with comparable skills and experience in the oil and gas industry. Accordingly, the loss of the services of one or more of these individuals could have a detrimental effect on us.

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

We compete with major and independent oil and gas companies for property acquisitions. We also compete for the equipment and labor required to develop and operate these 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 gas industry competes with other industries in supplying the energy and fuel needs of industrial, commercial, and other consumers.

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Several companies have entered into purchase contracts with us for a significant portion of our production and if they default on these contracts, we could be materially and adversely affected.

Our long-term natural gas contracts, which extend through March 2009, accounted for the sale of approximately 30% of our natural gas production and for a significant portion of our total revenues in 2005. We cannot assure you that the other parties to these contracts will continue to perform under the contracts. If the other parties were to default after taking delivery of our natural gas, it could have a material adverse effect on our cash flows for the period in which the default occurred. A default by the other parties prior to taking delivery of our natural gas could also have a material adverse effect on our cash flows for the period in which the default occurred depending on the prevailing market prices of natural gas at the time compared to the contractual prices.

Hedging our production may result in losses.

To reduce our exposure to fluctuations in the prices of natural gas and crude oil, we have entered into natural gas and crude oil hedging arrangements. These hedging arrangements tend to limit the benefit we would receive from increases in the prices of natural gas and crude oil. 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 and crude oil market prices exceeding our swap prices requires us to make payment for the settlement of our hedge derivatives on the fifth day of the production month for natural gas hedges and the fifth day after the production month for crude oil hedges. We do not receive market price cash payments from our customers until 25 to 60 days after the end of the production month. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.

If we choose not to engage in hedging arrangements in the future, we may be more adversely affected by changes in natural gas 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.

Due to the recent record high oil and gas prices, there is currently a high demend for and a general shortage of drilling equipment and supplies. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. We believe that these shortages could continue. In addition, the costs and delivery times of equipment and supplies are substantially greater now than in prior periods. Accordingly, we cannot assure you that we will be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services in the future. 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 and crude oil operations are subject to various U.S. and Canadian federal, state, provincial and local government laws and regulations that may be changed from time to time in response to economic or political conditions. Matters that are typically regulated include:

• discharge permits for drilling operations;

• drilling permits and bonds;

• reports concerning operations;

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• spacing of 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 natural gas and crude oil 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.

We have a substantial amount of debt and the cost of servicing that debt could adversely affect our business; and such risk could increase if we incur more debt.

We have a substantial amount of indebtedness. At December 31, 2005, we had total consolidated debt of $576.5 million, including $70.5 million in current liabilities. Subject to the limits contained in the loan agreements governing our senior secured revolving credit facilities and our second lien mortgage notes, we may incur additional debt. Our ability to borrow under our senior secured revolving credit facilities is subject to the quantity of proved reserves attributable to our natural gas and crude oil properties. One of our senior secured revolving credit facilities enables us to borrow significant amounts in Canadian dollars to fund and support our operations in Canada. Such indebtedness exposes us to currency exchange risk associated with the Canadian dollar. If we incur additional indebtedness or fail to increase the quantity of proved reserves attributable to our natural gas and crude oil properties, 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 on our indebtedness, including, among others, operating expenses and interest and principal payments under our senior secured revolving credit facilities, our second lien mortgage notes and our convertible subordinated debentures. Our level of indebtedness relative to our proved reserves and these significant demands on our cash resources could have important effects on our business and on your investment in Quicksilver. 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 under our senior secured revolving credit facilities if the quantity of proved reserves attributable to our natural gas and crude oil properties are insufficient to support our level of borrowings under such credit facilities;

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

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

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

• increase our interest expense if interest rates increase, because certain of our borrowings are at variable rates of interest;

• increase our vulnerability to foreign exchange risk associated with Canadian dollar denominated indebtedness and international operations in Canada;

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

• result in an event of default upon a failure to comply with financial covenants contained in our senior secured revolving credit facilities or second lien mortgage notes which, if not cured or waived, could have a material adverse effect on our business, financial condition or results of operations.

Our ability to pay principal and interest on our long-term debt and to satisfy our other liabilities will depend upon our future performance and our ability to refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital markets conditions, our financial condition, results of operations and prospects and other factors, many of which are beyond our control.

If we are unable to service our indebtedness and fund our operating costs, 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; or

• restructuring or refinancing debt.

There can be no assurance that any such strategies could be implemented on satisfactory terms, if at all.

Our senior secured revolving credit facilities and second lien mortgage notes restrict our ability and the ability of some of our subsidiaries to engage in certain activities.

The loan agreements governing our senior secured revolving credit facilities and second line mortgage notes 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 to exist certain liens;

• enter into 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.

The loan agreements for our senior secured revolving credit facilities and second lien mortgage notes contain certain covenants, which, among other things, require the maintenance of a minimum current ratio, a minimum collateral coverage ratio, a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio, and a minimum earnings (before interest, taxes, depreciation, depletion, accretion and amortization, non-cash income and expense and exploration costs) to fixed charges ratio. Our ability to borrow under our senior secured revolving credit facilities is dependent upon the quantity of proved reserves attributable to our natural gas and crude oil properties. Our ability to meet these covenants or requirements may be affected by events beyond our control, and we cannot assure you that we will satisfy such covenants and requirements.

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The covenants contained in the agreements governing our debt may affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a breach of the restrictive covenants in our loan agreements, any instrument governing our future indebtedness or our inability to maintain the financial ratios described above could result in an event of default under the applicable instrument. Upon the occurrence of such an event of default, the applicable creditors could, subject to the terms and conditions of the applicable instrument, elect to declare the outstanding principle 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 that would be triggered by such default or acceleration would also be subject to acceleration upon the occurrence of such default or acceleration. If we were unable to repay amounts due under our senior secured revolving credit facilities, the creditors could proceed against the collateral granted to them to secure such indebtedness. If the payment of our indebtedness is accelerated, there can be no assurance that our assets would be sufficient to repay in full such indebtedness and our other indebtedness that would become due as a result of any acceleration. The above restrictions could limit our ability to obtain future financing and may prevent us from taking advantage of attractive business opportunities.

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

Members of the Darden family, together with Mercury and Quicksilver Energy, L.P., entities primarily owned by members of the Darden family, beneficially own on the date of this annual report approximately 35% of our common stock. As a result, these entities and individuals will generally be able to control 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 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 doing well.

Our shares that are eligible for future sale may have an adverse effect on the price of our common stock. There were 76,079,041 shares of our common stock outstanding at December 31, 2005. Approximately 48,611,279 of these shares are freely tradable without substantial restriction or the requirement of future registration under the Securities Act. In addition, at December 31, 2005 we had the following options outstanding to purchase shares of our common stock:

• Options to purchase 45,903 shares at $3.27 per share;

• Options to purchase 72,915 shares at $5.35 per share;

• Options to purchase 1,698 shares at $5.50 per share;

• Options to purchase 55,753 shares at $5.67 per share;

• Options to purchase 65,052 shares at $7.36 per share;

• Options to purchase 48,504 shares at $8.03 per share;

• Options to purchase 656,962 shares at $11.01 per share;

• Options to purchase 22,595 shares at $15.83 per share;

• Options to purchase 1,775,135 shares at $20.85 per share;

• Options to purchase 11,085 shares at $23.42 per share;

• Options to purchase 82,637 shares at $23.83 per share; and

• Options to purchase 2,456 shares at $33.09 per share.

Sales of substantial amounts of common stock, or a perception that such sales could occur, and the existence of options to purchase 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.

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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, such as:

• 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. The provisions, described above and the stockholder rights plan could impede a merger, consolidation, takeover or other business combination involving us or discourage a potential acquirer from making a tender offer or otherwise attempting to take control of 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.

Internet Website

We file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission, or SEC. Our SEC filings are available to the public over the Internet at the SEC’s web site at www.sec.gov or from our website at www.qrinc.com. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operations of the public reference room. In addition, we make available free of charge through our Internet website at http://www.qrinc.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

Additionally, charters for the committees of our Board of Directors and our Corporate Governance Guidelines and Code of Business Conduct and Ethics can be found on our Internet website at http://www.qrinc.com under the heading “Corporate Governance.” Stockholders may request copies of these documents by writing to the Investor Relations Department at 777 West Rosedale Street, Suite 300, Fort Worth, Texas 76104.

ITEM 1B.    Unresolved Staff Comments

None.

ITEM 2.      Properties

We own significant natural gas and crude oil production interests in the following geographic areas:

Michigan

Producing Formation	Proved Reserves (Bcfe)	% Gas		% Proved Developed		2005 Production (MMcfed)
Antrim Shale	503.5	100	%	92	%	59.7
Non-Antrim	78.0	62	%	82	%	21.0
All Formations	581.5	95	%	90	%	80.7

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Michigan has favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas and currently imports approximately 75% of its demand. This supply/demand situation generally allows Michigan producers to sell their natural gas at a slight premium to typical industry benchmark prices.

The Antrim Shale underlies a large percentage of our Michigan acreage and is fairly homogeneous in terms of reservoir quality; wells tend to produce relatively predictable amounts of natural gas. Subsurface fracturing can increase reserves and production attributable to any particular well. On average, Antrim Shale wells have a total productive life of more than 20 years. As new wells produce and the de-watering process takes place, they tend to reach a maximum production level in six to 12 months, remaining at these levels for one to two years, and then declining at 8% to 10% per year thereafter. The wells tend to produce the best economic results when drilled in large numbers in a fairly concentrated area. This well concentration provides for a more rapid de-watering of a specific area, which decreases the time to natural gas production and increases the amount of natural gas production. It also enables us to maximize the use of existing production infrastructure, which decreases per unit operating costs. Since reserve quantities and production levels over a large number of wells are fairly predictable, maximizing per well recoveries and minimizing per unit production costs through a sizeable well-engineered drilling program are the keys to profitable Antrim development.

At December 31, 2005, we owned working interests in 4,661 producing Antrim wells. Since 1998, we have drilled 543 Antrim wells and successfully completed 537 for a success rate of 99%. In 2005, we drilled and successfully completed or participated in a total of 67 (31.4 net) Antrim wells including 11 horizontal reentry wells. For 2006, we have budgeted for the drilling of 107 (60.8 net) Antrim wells, including 20 horizontal reentry wells.

Our non-Antrim interests are located in several reservoirs including the Prairie du Chien (“PdC”), Richfield, Detroit River Zone III (“DRZ3”) and Niagaran pinnacle reefs. Our PdC wells produce from several Ordovician age reservoirs with the majority being in the 1,000 feet to 1,200 feet thick PdC Group that has three major sands: the Lower PdC, Middle PdC and Upper PdC. Depending upon the area and the particular zone, the PdC will produce dry gas, gas and condensate or oil with associated gas. Our PdC production is well established, and four development wells were drilled from 2003 through 2005 to increase production from existing fields. At year-end we had 42 gross (24.3 net) PdC wells producing. There are numerous proved non-producing zones in existing well bores that provide recompletion opportunities, allowing us to maintain or, in some cases, increase production from our PdC wells as currently producing reservoirs deplete.

Our Richfield/Detroit River wells are located in Kalkaska and Crawford counties in the Garfield and Beaver Creek fields. The Richfield zone consists of seven dolomite reservoirs spread over a 200-foot interval. The Garfield Richfield has seven wells producing under primary solution gas drive. Potential exploitation of the Garfield Richfield either by secondary waterflood and/or improved oil recovery with CO2 injection is under evaluation and has not been included in our booked reserves. We had 89 producing wells producing from the Richfield zone at December 31, 2005.

The DRZ3 at Beaver Creek lies approximately 200 feet above the Richfield. The DRZ3 is a six-foot dolomite zone that covers approximately 10,000 acres on the Beaver Creek structure. We had 27 producing wells as of December 31, 2005. While there is the opportunity for improving production and proved reserve quantities, we have determined that our resources are better allocated to continued development, exploitation and exploration of our many unconventional gas projects.

Our Niagaran wells produce from numerous Silurian-age Niagaran pinnacle reefs located in nine counties in northern Michigan. The depth of these wells ranges from 3,400 feet to 7,800 feet with reservoir thickness from 300 feet to 600 feet. Depending upon the location of the specific reef in the pinnacle reef belt of the northern shelf area, the Niagaran reefs will produce dry gas, gas and condensate or oil with associated gas. At December 31, 2005, we had 67 (29.3 net) producing Niagaran wells.

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Canada

In 2000, we began to focus on the potential of Canadian CBM through MGV. In late 2000, we entered into a joint venture with EnCana to explore for and develop CBM reserves initially in the West Palliser block in Alberta. By January 2003, the joint venture had drilled 175 exploratory, pilot and development wells. In January 2003, we entered into an asset rationalization agreement with EnCana that divided the assets and rights subject to the joint venture and allowed us to pursue independent operations.

During 2006, we expect to drill 451 (267 net) wells and install three new CBM processing facilities. Each plant will be capable of processing five to ten MMcfd of natural gas production. Approximately $70 million will be committed to CBM drilling including testing of the Mannville coals.

Including its interests in other conventional natural gas properties located in southern Alberta, MGV held interests in 1,685 (778.2 net) productive wells at December 31, 2005. Our total Canadian proved reserves at December 31, 2005 were estimated to be 305 Bcf. Our average daily production in Canada for 2005 was 40.7 MMcfd. At December 31, 2005, however, our Canadian production was approximately 49.0 MMcfd.

Texas

During 2005, we drilled 36 (35.4 net) wells in the Fort Worth Basin Barnett Shale and completed construction of the first phase of our Cowtown Pipeline. At December 31, 2005, we had drilled a total of 44 (43.4 net) wells in the Barnett Shale and our production exit rate was approximately 23.0 MMcfd from 52 (37.8 net) producing wells. In June of 2005, we began processing our Barnett Shale natural gas through an interim gas processing facility. Our interests are spread over an area stretching from northwest Johnson County to southeastern Hood County, approximately 20 miles in a north-south direction. At December 31, 2005, we held approximately 255,000 net acres in the Fort Worth Basin Barnett Shale play. Our plans for 2006 include increasing our pace of development and we anticipate drilling approximately 85 (84.6 net) wells in the Fort Worth Basin Barnett Shale over the course of the year and expect our gas processing plant to begin operations during the first quarter. We have also planned to extend our gathering pipeline and construct additional gathering lines and gas processing facilities.

Also during 2005, we acquired approximately 310,000 net acres in a contiguous block of west Texas. We plan to drill four resource assessment wells on that acreage to evaluate the Barnett and Woodford Shales in the Delaware Basin.

Indiana/Kentucky

We began our operations in the New Albany Shale of southern Indiana and north Kentucky in 2000 with the acquisition of 36 producing wells and the eight-mile 12-inch GTG gas pipeline that runs from southern Indiana to northern Kentucky. During 2005, we drilled 26 wells, gross and net. At December 31, 2005, we had approximately 219 producing wells in Indiana/Kentucky. Our New Albany production is transported through an extension of the GTG gas pipeline that we constructed in 2003 and connects to the Texas Gas Pipeline in northern Kentucky. At year-end, natural gas sales from our properties in the area averaged 5.4 MMcfd.

Rocky Mountain Region

Our Rocky Mountain properties are located in Montana and Wyoming. Production from those properties is primarily crude oil from well-established producing formations at depths ranging from 1,000 feet to 17,000 feet. At December 31, 2005, our Rocky Mountain proved reserves were 2.4 MMBbls of crude oil and 2.0 Bcfe of natural gas and NGLs for total equivalent reserves of 16.7 Bcfe. Our daily production averaged 3.2 MMcfed for 2005.

Oil and Gas Reserves

The following reserve quantity and future net cash flow information concerns our proved reserves that are located in the United States and Canada. Independent petroleum engineers with Schlumberger Data and

21

Consulting Services, LaRoche Petroleum Consultants, Ltd. and Netherland, Sewell & Associates, Inc. prepared our reserve estimates. Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10(a) 2(i), 2(ii), 2(iii), (3) and (4), are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided by contractual arrangements, but not of escalations based upon expected future conditions. Prices do not include the effect of derivative instruments we have entered into. Future production and development costs include production and property taxes.

Proved developed oil and gas reserves are reserves that are expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for re-completion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

The reserve data set forth in this document represents only estimates and is subject to inherent uncertainties. The determination of oil and gas reserves is based on estimates that are highly complex and interpretive. Reserve engineering is a subjective process that is dependent on the quality of available data and on engineering and geological interpretation and judgment. Although we believe the reserve estimates contained in this document are reasonable, reserve estimates are imprecise and are expected to change as additional information becomes available.

The following table summarizes our proved reserves and the standardized measure of discounted future net cash flows attributable to them at December 31, 2005, 2004 and 2003.

	Years Ended December 31,			Years Ended December 31,
	Total Proved Reserves			Proved Developed Reserves
	2005	2004	2003	2005	2004	2003
Natural gas (MMcf)
United States	716,043	627,676	643,520	593,630	556,999	569,979
Canada	304,910	261,077	146,632	199,859	149,453	83,698
Total	1,020,953	888,753	790,152	793,489	706,452	653,677
Crude oil (MBbl)
United States	5,915	9,067	13,173	4,986	4,587	8,734
Canada	—	—	—	—	—	—
Total	5,915	9,067	13,173	4,986	4,587	8,734
NGL (MBbl)
United States	9,623	4,187	1,918	5,153	2,464	1,405
Canada	—	—	—	—	—	—
Total	9,623	4,187	1,918	5,153	2,464	1,405
Total (MMcfe)	1,114,181	968,276	880,696	854,326	748,762	714,511

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	Year ended December 31,
	2005		2004		2003
Representative natural gas and crude oil prices: (1)
Natural gas—Henry Hub Spot	$	10.08	$	6.18	$	5.97
Natural gas—AECO		8.41		5.18		5.32
Crude oil—WTI Cushing		61.06		43.36		32.55
Present values (in thousands): (2)
Standardized measure of discounted future net cash flows, after income tax	$	1,824,132	$	970,731	$	848,741

(1) The natural gas and crude oil prices as of each respective year-end were based, respectively, on NYMEX Henry Hub prices per MMBtu and NYMEX prices per Bbl, as adjusted to reflect local differentials.

(2) Determined based on year-end unescalated prices and costs in accordance with the guidelines of the SEC, discounted at 10% per annum.

Volumes, Sales Prices and Oil and Gas Production Expense

The following table sets forth certain information regarding production, average unit prices and costs for the periods indicated:

	Years Ended December 31,
	2005		2004		2003
Production:
Natural gas (MMcf)
United States		31,944		30,644		31,612
Canada		14,825		8,707		2,924
Total natural gas		46,769		39,351		34,536
Crude oil (MBbl)
United States		553		689		807
Canada		—		—		1
Total crude oil		553		689		808
NGL (MBbl)
United States		220		128		133
Canada		3		1		2
Total NGL		223		129		135
Total production (MMcfe)		51,427		44,257		40,192
Average Prices (including impact of hedges):
Natural gas—per Mcf
United States	$	5.42	$	3.52	$	3.32
Canada		6.50		4.92		3.98
Consolidated		5.76		3.83		3.38
Crude oil—per Bbl
United States	$	50.50	$	33.07	$	24.23
Canada		—		—		24.46
Consolidated		50.50		33.07		24.23
NGL—per Bbl
United States	$	38.88	$	28.55	$	21.45
Canada		53.91		22.18		26.01
Consolidated		39.08		28.52		21.50

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	Years Ended December 31,
	2005		2004		2003
Average Prices (excluding impact of hedges):
Natural gas—per Mcf
United States	$	6.44	$	4.86	$	4.50
Canada		7.05		4.98		4.15
Consolidated		6.63		4.89		4.47
Crude oil—per Bbl
United States	$	52.76	$	36.53	$	26.69
Canada		—		—		24.46
Consolidated		52.76		36.53		26.69
NGL—per Bbl
United States	$	38.88	$	28.55	$	21.45
Canada		53.91		22.18		26.01
Consolidated		39.08		28.52		21.50
Production cost (per Mcfe) (1)
United States	$	1.90	$	1.56	$	1.30
Canada		1.12		1.19		1.35
Consolidated		1.68		1.48		1.31

(1) Includes production taxes.

Drilling Activity

During the periods indicated, the Company drilled or participated in the drilling of the following exploratory and development wells:

	Years Ended December 31,
	2005		2004		2003
	Gross	Net	Gross	Net	Gross	Net
Development:
United States
Productive	43.0	28.4	73.0	55.5	102.0	74.3
Non-productive	—	—	—	—	—	—
Canada
Productive	243.0	134.7	356.0	110.1	32.0	32.0
Non-productive	—	—	—	—	—	—
Total	286.0	163.1	429.0	165.6	134.0	106.3
Exploratory:
United States
Productive	97.0	66.7	38.0	34.2	76.0	73.3
Non-productive	5.0	5.0	1.0	1.0	1.0	1.0
Canada
Productive	240.0	124.4	274.0	209.7	152.0	116.5
Non-productive	—	—	10.0	9.8	1.0	0.4
Total	342.0	196.1	323.0	254.7	230.0	191.2
Total:
Productive	623.0	354.2	741.0	409.5	362.0	296.1
Non-productive	5.0	5.0	11.0	10.8	2.0	1.4
Total	628.0	359.2	752.0	420.3	364.0	297.5

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Acquisition, Exploration and Development Capital Expenditures

	United States		Canada		Consolidated
	(in thousands)
2005
Proved acreage	$	821	$	1,620	$	2,441
Unproved acreage		48,419		3,784		52,203
Development costs		24,007		82,388		106,395
Exploration costs		109,148		9,829		118,977
Total	$	182,395	$	97,621	$	280,016
2004
Proved acreage	$	11,907	$	2,942	$	14,849
Unproved acreage		31,857		7,144		39,001
Development costs		45,213		71,094		116,307
Exploration costs		25,673		22,631		48,304
Total	$	114,650	$	103,811	$	218,461
2003
Proved acreage	$	3,215	$	3,388	$	6,603
Unproved acreage		24,063		6,739		30,802
Development costs		37,682		41,820		79,502
Exploration costs		9,411		17,066		26,477
Total	$	74,371	$	69,013	$	143,384

Productive Oil and Gas Wells

The following table summarizes productive oil and gas wells attributable to our direct interests as of December 31, 2005:

	As of December 31, 2005 Productive Wells
	Natural Gas		Crude Oil
	Gross	Net	Gross	Net
United States	5,060	1,813.0	391	353.9
Canada	1,683	778.2	2	0.1
Total	6,740	2,591.2	393	354.0

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Oil and Gas Acreage

Our principal natural gas and crude oil properties consist of non-producing and producing natural gas and crude oil leases, including reserves of natural gas and crude oil in place. The following table indicates our interest in developed and undeveloped acreage held directly by us. Developed acres are defined as acreage spaced or allocated to wells that are producing or capable of producing. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether or not such acreage contains proved reserves. Gross acres are the total number of acres in which we have a working interest. Net acres are the sum of our fractional interests owned in the gross acres.

	As of December 31, 2005
	Developed Acreage		Undeveloped Acreage
	Gross	Net	Gross	Net
Michigan	502,542	213,966	133,361	77,062
Indiana/Kentucky	34,425	34,185	216,524	213,717
Texas	6,991	6,946	695,099	565,841
Rockies & other	81,110	77,774	167,616	119,722
United States	625,068	332,871	1,212,600	976,342
Canada	258,650	164,669	350,206	265,087
Total	883,718	497,540	1,562,806	1,241,429

ITEM 3. Legal Proceedings

In August 2001, a group of royalty owners, Athel E. Williams et al., brought suit against us and three of our subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd, one of our subsidiaries, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who have yet to be determined. The pleadings of the plaintiffs seek damages in an unspecified amount and injunctive relief against future underpayments. The court heard arguments on class certification on November 8, 2002, and on December 6, 2002 the court issued a memorandum opinion granting class certification in part and denying it in part. On December 20, 2002, we filed a motion for clarification and reconsideration of the court’s order. That motion was denied on March 9, 2003. After an extended delay resulting from the retention of new counsel by the plaintiffs and the initiation of settlement discussions, on January 21, 2005, the Circuit Court issued an order certifying certain claims to proceed on behalf of a class. The Circuit Court also entered a scheduling order setting trial for January 2007, and denied Defendants’ request to stay proceedings in that court pending an appeal of the certification order.

Defendants sought leave to appeal the certification order by filing an Application for Leave to Appeal on February 11, 2005 with the Michigan Court of Appeals. Defendants also requested that the Court of Appeals stay proceedings in the Circuit Court pending the consideration of its appeal, and requested that the Court of Appeals consider all matters in an expedited manner. On April 22, 2005, the Court of Appeals vacated the certification order and remanded the case to the trial court with instructions to address several particular issues by way of a new order. After limited discovery relating to those issues, the trial court held a follow-up certification hearing on June 1, 2005.

In late July of 2005, it was announced that the trial court judge, Judge Alton Davis, had been appointed to a seat on the Michigan Court of Appeals. The parties have not been advised as to who will be the new trial court judge over the case.

On August 18, 2005, shortly before ascending to the appellate court, Judge Davis entered new findings and conclusions again favoring certification. Defendants sought leave in the Court of Appeals Court to file a supplemental response to the trial courts’ new findings and conclusions. On January 20, 2006, the Court of

26

Appeals entered an order granting the application for leave to appeal and expediting appellate proceedings. The request to supplement the original appellate filings was denied, but a new briefing schedule was put into place. Defendants’ appellate brief is due by February 24, 2006, and Plaintiffs’ brief is due within 28 days after the filing of the Company’s brief. The case (discovery and trial court proceedings) remains stayed pending the resolution of the appeal.

Based on information currently available to us, we believe that the final resolution of this matter will not have a material effect on our financial condition, results of operations, or cash flows.

ITEM 4. Submission of Matters to a Vote of Security Holders

There were no matters submitted to a stockholder vote during the fourth quarter of 2005.

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PART II.

ITEM 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities

Market Information

Our common stock is traded on the New York Stock Exchange under the symbol “KWK.”

The following table sets forth the quarterly high and low sales prices of our common stock for the periods indicated below.

	HIGH		LOW
2005 (1)
Fourth Quarter	$	50.20	$	32.94
Third Quarter		48.51		38.23
Second Quarter		43.89		31.45
First Quarter		34.53		22.29
2004 (1)
Fourth Quarter	$	25.25	$	19.31
Third Quarter		24.08		16.86
Second Quarter		22.47		12.49
First Quarter		14.23		10.69

(1) Stock prices been have adjusted to reflect a two-for-one stock split effected in the form of a stock dividend in June 2004 and a three-for-two stock split effected in the form of a stock dividend in June 2005.

As of February 15, 2006, there were approximately 584 common stockholders of record.

We have not paid dividends on our common stock and intend to retain our cash flow from operations for the future operation and development of our business. In addition, our senior secured credit facility prohibits payments of dividends on our common stock.

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ITEM 6. Selected Financial Data

The following tables set forth, as of the dates and for the periods indicated, our selected financial information. Our financial information is derived from our audited consolidated financial statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes thereto contained in this document. The following information is not necessarily indicative of our future results.

Selected Financial Data

(in thousands, except for per share data)

	Years Ended December 31,
	2005			2004			2003			2002			2001
Consolidated Statements of Income Data:
Total revenues	$	310,448		$	179,729		$	140,949		$	121,979		$	141,963
Income before income taxes		127,974			45,446			28,502			21,333			30,110
Income from continuing operations		87,272			31,272			18,505			13,835			19,310
Income before cumulative effect of change in accounting principle		87,434			31,272			18,505			13,835			19,310
Net income		87,434			31,272			16,208			13,835			19,310
Net income from continuing operations—per share (1)
Basic	$	1.15		$	0.42		$	0.28		$	0.23		$	0.34
Diluted		1.08			0.41			0.27			0.23			0.33
Net income before accounting change—per share (1)
Basic	$	1.15		$	0.42		$	0.28		$	0.23		$	0.34
Diluted		1.08			0.41			0.27			0.23			0.33
Net income—per share (1)
Basic	$	1.15		$	0.42		$	0.24		$	0.23		$	0.34
Diluted		1.08			0.41			0.24			0.23			0.33
Consolidated Statements of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	144,468		$	84,847		$	49,602		$	41,650		$	51,624
Investing activities		(319,269	)		(205,898	)		(137,744	)		(81,111	)		(60,930	)
Financing activities		172,426			134,389			79,369			40,050			5,199
Capital expenditures	$	329,495		$	215,106		$	137,895		$	86,417		$	61,112
Consolidated Balance Sheets Data:
Working capital (deficit) (2)	$	(98,606	)	$	(17,255	)	$	(30,803	)	$	(23,678	)	$	(19,141	)
Properties—net		1,112,002			802,610			604,576			470,078			412,455
Total assets		1,243,094			888,334			666,934			529,538			471,884
Long-term debt		506,039			399,134			249,097			248,493			248,425
Stockholders’ equity		383,615			304,276			241,816			128,905			94,387

(1) Per share amounts have been adjusted to reflect a two-for-one stock split effect in the form of a stock dividend in June 2004 and a three-for-two stock split effected in the form of a stock dividend in June 2005.

(2) Working capital consists of current assets and current liabilities, which include derivative contracts at estimated fair value.

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following Management’s Discussion and Analysis (“MD&A”) is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Annual Report on Form 10-K, including: “Item 1. Business,” “Item 2. Properties,” “Item 6. Selected Financial Data,” and “Item 8. Financial Statements and Supplementary Data.” Our MD&A includes the following sections:

• Overview—a general description of our business; the value drivers of our business; measurements; and opportunities, challenges and risks.

• Financial Risk Management—information about debt financing and financial risk management.

• Application of Critical Accounting Policies—a discussion of accounting policies that represent choices between acceptable alternatives and/or require critical judgments and estimates.

• Results of Operations—an analysis of our consolidated results of operations for the three years presented in our financial statements. We operate in one business – exploration, development and production of natural gas, NGLs and crude oil. Except to the extent that differences between our geographic operating segments are material to an understanding of our business as a whole, we present this MD&A on a consolidated basis.

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

• Forward-Looking Statements—cautionary information about forward-looking statements and a description of certain risks and uncertainties that could cause our actual results to differ materially from our historical results or our current expectations or projections.

OVERVIEW

We are a Fort Worth, Texas-based independent oil and gas company engaged in the development, exploitation, exploration, acquisition, and production of natural gas, NGLs, and crude oil primarily from unconventional reservoirs where hydrocarbons are found in challenging geological conditions such as fractured shales, coal beds and tight sands. We generate revenue, income and cash flows by producing and selling natural gas, NGLs, and crude oil. We produce these products in quantities and at prices that, in addition to generating operating income, allow us to conduct development, exploitation, exploration and acquisition activities to replace the reserves that have been produced.

At December 31, 2005, approximately 92% of our proved reserves were natural gas and approximately 52% of our proved reserves were located in Michigan. Our activities in the Michigan Basin Antrim shale have allowed us to develop a technical and operational expertise in the development, exploitation, exploration, acquisition and production of unconventional natural gas reserves. Consistent with one of our business strategies, we have applied the expertise gained in our Michigan activities to our Canadian projects in Alberta, Canada and our Barnett Shale interests in the Fort Worth Basin in Texas. Our Alberta and Texas reserves made up about 27% and 16%, respectively of our proved reserves at December 31, 2005. The Delaware Basin in west Texas and the Mannville CBM in Alberta represent our most recent opportunities to apply this expertise.

For 2006, we plan to continue our focus on the continued development, exploitation and exploration of our properties in Alberta and Texas. We have established a capital budget of $566 million for 2006. Approximately $123 million is allocated to our Canadian CBM projects and approximately $399 million is allocated to our Barnett Shale position in the Fort Worth Basin in Texas. We also plan to evaluate our development opportunities in the Delaware Basin in Texas, where we plan to drill four resource assessment wells during 2006. Approximately $39 million of the 2006 capital expenditure budget has been dedicated to our fractured shale projects in the Michigan Basin, with the remaining $5 million planned for our projects in Indiana/Kentucky and the Rockies.

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Our Company focuses on three key value drivers:

• reserve growth;

• production growth; and

• improving the Company’s cash flows.

The Company’s reserve growth is dependent upon our ability to apply the Company’s technical and operational expertise in our core operating areas to development, exploitation and exploration of unconventional natural gas reservoirs. We strive to increase reserves and production through aggressive management of operations and relatively low-risk development and exploitation drilling. We will also continue to identify high potential exploratory projects with higher levels of financial risk. Both our lower-risk development programs and higher-risk exploratory projects are aimed at providing the Company with opportunities to develop and exploit unconventional natural gas reservoirs to which our technical and operational expertise is well suited.

Our principal properties are well suited for production increases through development and exploitation drilling. We perform workover and infrastructure projects to reduce operating costs and increase current and future production. We regularly review operations on operated properties to determine if steps can be taken to profitably increase reserves and production.

As these elements are implemented, our results are measured through these key measurements: earnings; cash flow from operating activities; production and overhead costs per unit of production; production volumes; reserve growth; and finding costs per unit of reserve addition.

	Years Ended December 31,
	2005		2004		2003
	(in thousands, except costs per Mcfe and production)
Operating income	$	149,129	$	60,693	$	48,498
Cash flow from operations		144,468		84,847		49,602
Production cost per Mcfe (1)	$	1.44	$	1.25	$	1.09
General and administrative cost per Mcfe		0.37		0.29		0.20
Production (MMcfe)		51,427		44,257		40,192

(1) Excludes production taxes.

The possibility of decreasing prices received for production is among the several risks that we face. We seek to manage this risk by entering into natural gas sales contracts with price floors and natural gas and crude oil financial hedges. Our use of pricing collars and, to a lesser degree, fixed price swaps for both natural gas and crude oil helps to ensure a predictable base level of cash flow while allowing us to participate in a portion of any favorable price increases. This commodity price strategy enhances our ability to execute our development, exploitation and exploration programs, meet debt service requirements and pursue acquisition opportunities despite price fluctuations. If our revenues were to decrease significantly as a result of presently unexpected declines in natural gas prices or otherwise, we could be forced to curtail our drilling and acquisition activities. We might also be forced to sell some of our assets on an untimely or unfavorable basis.

Prices for natural gas and crude oil fluctuate widely. For example, the closing NYMEX wholesale price of natural gas was at a six-year low of approximately $1.83 per Mcf for October 2001, reached an all-time high of approximately $13.91 per Mcf for October 2005 and then declined to $8.40 per Mcf for February 2006. Assuming these prices remain at relatively favorable levels, we expect to fund more of our capital expenditures with cash flow from operations; however, we do not expect our cash flow from operations to be sufficient to satisfy our total budgeted capital expenditures. We plan to use cash flows from operations, credit facility utilization, possible sales of assets and issuance of debt or equity securities to fund our total budgeted capital expenditures in 2006.

31

FINANCIAL RISK MANAGEMENT

We have established policies and procedures for managing risk within our organization, including internal controls. The level of risk assumed by us is based on our objectives and capacity to manage risk.

Our primary risk exposure is related to natural gas and crude oil commodity prices. We have mitigated the downside risk of adverse price movements through the use of long-term sales contracts, swaps and collars; however, in doing so, we have also limited future gains from favorable price movements.

Commodity Price Risk

We sell approximately 10 MMcfd and 25 MMcfd of natural gas under long-term contracts with floor prices of $2.47 per Mcf and $2.49 per Mcf, respectively through March 2009. Approximately 4.3 MMcfd sold under these contracts in 2005 were third party volumes controlled by us. We also enter into financial contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas and crude oil production. These contracts have included price floors, no-cost collars and fixed price swaps.

Natural gas price collars have been put in place to hedge 2006 U.S. production of approximately 38 MMcfd and Canadian production of approximately 23 MMcfd. Additionally, the Company has used price collar agreements to hedge approximately 500 Bbld of its crude oil production through the first half of 2006. U.S. and Canadian natural gas production of approximately 20 MMcfd and 10 MMcfd, respectively, has also been hedged for the first quarter of 2007 using price collars. As a result of these various contracts, we believe the Company will have more predictability of its natural gas and crude oil revenues.

The following table summarizes our open financial derivative positions as of December 31, 2005 related to natural gas and crude oil production.

Product	Type	Contract Period	Volume	Weighted Avg Price Per Mcf or Bbl	Fair Value
					(in thousands)
Gas	Collar	Jan 2006-Mar 2006	10,000 Mcfd	6.50-11.20	$	(812	)
Gas	Collar	Jan 2006-Mar 2006	10,000 Mcfd	6.50-11.20		(812	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.00-10.00		(964	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.00-10.00		(964	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.00-10.10		(949	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.00-10.17		(879	)
Gas	Collar	Jan 2006-Mar 2006	10,000 Mcfd	7.50-9.55		(2,372	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.50-9.55		(1,186	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.50-9.60		(1,160	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.50-10.55		(767	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.50-10.60		(747	)
Gas	Collar	Jan 2006-Mar 2006	10,000 Mcfd	9.50-12.01		(302	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	5.50-8.10		(2,695	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	5.50-8.25		(2,513	)
Gas	Collar	Apr 2006-Oct 2006	10,000 Mcfd	6.50-8.25		(5,044	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	6.50-8.25		(2,522	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	7.00-8.35		(2,394	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	7.00-8.35		(2,394	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	7.00-8.35		(2,394	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	8.00-10.10		(1,131	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	8.00-10.10		(1,131	)
Gas	Collar	Apr 2006-Oct 2006	10,000 Mcfd	8.00-10.20		(1,085	)
Gas	Collar	Apr 2006-Oct 2006	10,000 Mcfd	8.00-10.20		(1,085	)
Gas	Collar	Nov 2006-Mar 2007	10,000 Mcfd	7.50-9.65		(3,749	)
Gas	Collar	Nov 2006-Mar 2007	10,000 Mcfd	8.50-11.35		(2,254	)
Gas	Collar	Nov 2006-Mar 2007	10,000 Mcfd	8.50-11.50		(2,175	)
Oil	Collar	Jan 2006-Jun 2006	500 Bbld	47.00-62.20		(320	)
			Net open positions		$	(44,800	)

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Utilization of our financial hedging program may result in realization of natural gas and crude oil prices that vary from the actual prices that we receive from the sale of natural gas and crude oil. As a result of the hedging programs, revenues from production were lower than if the hedging programs had not been in effect by $41.8 million in 2005, $43.9 million in 2004 and $39.8 million in 2003.

Commodity price fluctuations affect our remaining natural gas and crude oil volumes as well as our NGL volumes. Up to 4.5 MMcfd of natural gas is committed at market price through May 2006. Additional natural gas volumes of 16.5 MMcfd are committed at market price through September 2008. During 2005, approximately 7.2 MMcfd of our natural gas production was sold under these contracts. The remaining contractual volumes were third-party volumes controlled by us.

Based on our 2005 average production and long-term natural gas sales contracts with floor prices of $2.47 per Mcf and $2.49 per Mcf, each $1.00 per Mcf increase/decrease in the price of natural gas would increase/decrease our revenue by approximately $35.6 million. Should natural gas prices exceed our highest collar cap price of $12.01 per Mcf, approximately $21.9 million would be required for settlement of our financial derivative contracts for each $1.00 per Mcf increase.

We have entered into various financial contracts to hedge exposure to commodity price risk associated with future contractual natural gas sales. These contracts include either fixed price sales to, or purchases from, third parties. As a result of our firm sale and purchase commitments, the associated financial price swaps qualified as fair value hedges for accounting purposes. Marketing revenues were higher by $0.1 million, $0.5 million and $0.3 million as a result of our hedging activities in 2005, 2004 and 2003, respectively. Hedge ineffectiveness resulted in $0.1 million of net gains, $0.1 million of net losses and $0.2 million of net gains recorded to other revenue for 2005, 2004 and 2003, respectively.

The following table summarizes our open financial swap positions and hedged firm commitments as of December 31, 2005 related to natural gas marketing.

Contract Period	Volume	Weighted Avg Price per Mcf		Fair Value
				(in thousands)
Natural Gas Sales Contracts
Jan 2006	6,000 Mcf	$	13.37	$	17
Jan 2006-Feb 2006	10,000 Mcf	$	7.27		(35	)
Jan 2006-Feb 2006	16,000 Mcf	$	12.21		22
Jan 2006-Feb 2006	54,500 Mcf	$	13.09		131
Jan 2006-Mar 2006	240,000 Mcf	$	12.90		461
Feb 2006-Mar 2006	16,350 Mcf	$	11.63		7
				$	603
Natural Gas Financial Derivatives
Jan 2006	10,000 Mcf		Floating Price	$	(5	)
Jan 2006	10,000 Mcf		Floating Price		(22	)
Jan 2006	20,000 Mcf		Floating Price		(19	)
Jan 2006	20,000 Mcf		Floating Price		(55	)
Feb 2006	10,000 Mcf		Floating Price		(8	)
Feb 2006	20,000 Mcf		Floating Price		(22	)
Jan 2006-Mar 2006	120,000 Mcf		Floating Price		(74	)
Jan 2006-Mar 2006	120,000 Mcf		Floating Price		(257	)
Feb 2006-Mar 2006	20,000 Mcf		Floating Price		(1	)
					(463	)
	Total-net			$	140

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The fair value of natural gas and crude oil derivatives and associated firm commitments as of December 31, 2005 was estimated based on published market prices of natural gas and crude oil for the periods covered by the contracts. The net differential between the prices in each derivative and commitment and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. As a result, the fair value of our derivatives and commitments does not necessarily represent the value a third party would pay or require payment of to assume our contract positions.

Interest Rate Risk

At December 31, 2005, we had no interest rate derivatives in effect. On September 10, 2003, we entered into an interest rate swap to hedge the $40.0 million of fixed-rate second lien notes issued on June 27, 2003. The swap converted the debt’s 7.5% fixed-rate debt to a floating six-month LIBOR base. In January 2004, the swap position was cancelled, and we received a cash settlement of $0.3 million that is being recognized over the original term for the swap, which was scheduled to expire on December 31, 2006. A deferred gain of $0.1 million remains at December 31, 2005.

Interest expense for the years ended December 31, 2005, 2004 and 2003 was $0.3 million lower, and $0.8 million higher and $1.4 million higher, respectively, as a result of the interest rate swaps.

If interest rates on our variable interest-rate debt of $387.8 million, as of December 31, 2005, increase or decrease by one percentage point, our annual pretax income will decrease or increase by $3.9 million.

Credit Risk

Credit risk is the risk of loss as a result of non-performance by counterparties of their contractual obligations. We sell a portion of our natural gas production directly under long-term contracts with the remainder of our natural gas and crude oil production sold at spot or short-term contract prices. All our natural gas and crude oil production is sold to large trading companies and energy marketing companies, refineries and other users of petroleum products. We also enter into hedge derivatives with financial counterparties. We monitor exposure to counterparties by reviewing credit ratings, financial statements and credit service reports. Exposure levels are limited and parental guarantees and collateral to support the obligations of our counterparty are required according to our established policy. Each customer and/or counterparty is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. In this manner, we reduce credit risk.

While we follow our credit policies at the time we enter into sales contracts, the credit worthiness of counterparties could change over time. The credit ratings of the parent companies of the two counterparties to our long-term gas contracts were downgraded in early 2003 and remain below the credit ratings required for the extension of credit to new customers. Please see “Item 1A. Risk Factors.”

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. We manage performance risk through management of credit risk. Each customer and/or counterparty is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter.

Foreign Currency Risk

Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange

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rate risk. In the fourth quarter of 2005, a foreign currency transaction loss of $0.1 million was recorded as a result of a loss in the Canadian-$ value of U.S.-$ bank balances. During October and November 2004, Quicksilver loaned MGV approximately $11.4 million. To reduce its exposure to exchange rate risk, MGV entered into a forward contract that fixed the Canadian-to-US exchange rate. The balance of the loan was repaid at the end of November 2004 and upon settlement of the forward contract, a gain of $0.2 million was recognized.

While cross-currency transactions are minimized, the result of a ten percent change in the Canadian-U.S. exchange rate would increase or decrease stockholders’ equity by approximately $9.1 million at December 31, 2005.

APPLICATION OF CRITICAL ACCOUNTING POLICIES

Management discusses with our Audit Committee the development, selection and disclosure of our critical accounting policies and estimates and the application of these policies and estimates. Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States. We believe our accounting policies are appropriately selected and applied.

Use of Estimates

In preparing the financial statements, our management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including asset retirement obligations, litigation, income taxes and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Oil and Gas Properties

We employ the full cost method of accounting 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. Effective with the adoption of SFAS No. 143 in 2003, the carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The application of the full cost method of accounting for oil and gas properties generally results in higher capitalized costs and higher depletion rates compared to the successful efforts method of accounting for oil and gas properties. 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 proved oil and gas reserves as determined by independent petroleum engineers.

Net capitalized costs are limited to the lower of unamortized cost net of related deferred tax or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge our oil and gas revenue and asset retirement obligations; (ii) the cost of properties not being amortized; and (iii) the lower of cost or market value of unproved properties included in the costs being amortized less (iv) income tax effects related to differences between the book and tax basis of the oil and gas properties. Such limitations are imposed separately for the U.S. and Canadian cost centers.

Oil and Gas Reserves

Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10(a) 2(i), 2(ii), 2(iii), (3) and (4), are the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate

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with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, which do not include financial derivatives that hedge our oil and gas revenue.

The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates, made by the Company’s engineers, are reviewed annually and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits sooner. A material change in the estimated volumes of reserves could have an impact on the depletion rate calculation and the financial statements.

Ceiling Test

Companies that use the full cost method of accounting for oil and gas properties are required to perform the ceiling test each quarter. The ceiling is an impairment test performed on a country-by-country basis as prescribed by SEC Regulation S-X Rule 4-10. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after-tax value of the future net cash flows from proved natural gas and crude oil reserves, including the effect of cash flow hedges, discounted at ten percent per annum. This ceiling is compared to the net book value of the oil and gas properties reduced by the related net deferred income tax liability and asset retirement obligations. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the ceiling, an impairment or noncash write down is required. A charge to income for impairment can give the Company a significant loss for a particular period; however, future depletion expense would be reduced.

The ceiling test is affected by a decrease in net cash flow from reserves due to higher operating or capital costs or reduction in market prices for natural gas and crude oil. These changes can reduce the amount of economically producible reserves. At December 31, 2005, our capitalized costs, inclusive of future development costs, for U.S. and Canadian reserves were $0.89 per Mcfe and $1.34 per Mcfe, respectively.

Derivative Instruments

We enter into financial derivative instruments to hedge risk associated with the prices received from natural gas and crude oil production and marketing. We also utilize financial derivative instruments to hedge the risk associated with interest rates on our debt outstanding. We account for our derivative instruments under the provisions of Statement of Financial Accounts Standard (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities. Under this statement, derivative instruments, other than those that meet the normal purchases and sales exception, are recorded on our balance sheet as either assets or liabilities measured at fair value determined by reference to published future market prices and interest rates. The cash settlement of all derivative instruments is recognized as income or expense in the period in which the hedged transaction is recognized. Gains or losses on derivative instruments terminated prior to their original expiration date are deferred and recognized as income or expense in the period in which the hedged transaction is recognized. The ineffective portion of hedges is recognized currently in earnings.

At December 31, 2005, portions of our hedge derivatives were classified as current based upon the maturity of the derivative instruments. Based upon the estimated fair values of those hedge derivatives as of December 31, 2005, our revenues for 2006 will decrease approximately $40.0 million. Net income, after income taxes, will be negatively affected by approximately $25.4 million. These amounts will be reclassified from accumulated other comprehensive income in 2006.

Asset Retirement Obligations

We have significant obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells

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and associated production facilities. We adopted Statement of Financial Accounting Standard (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. Under SFAS No. 143, the estimated fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets is recorded in the periods in which it is incurred. When the liability is recorded, we increase the carrying amount of the related long-lived asset. The liability is accreted to the fair value at the time of the settlement over the useful life of the asset, and the capitalized cost is depleted or depreciated over the useful life of the related asset.

The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflation of these costs, the productive life of the asset and our risk adjusted costs to settle such obligations discounted using our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates.

Income Taxes

Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that will be in effect in years in which the temporary differences are expected to reverse. MGV, the Company’s Canadian subsidiary, computes taxes at rates in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested by MGV and thus are not considered available for distribution to the parent Company.

Included in our net deferred tax liability are $86.2 million of future tax benefits from prior unused tax losses. Realization of these tax assets depends on sufficient future taxable income before the benefits expire. We believe we will have sufficient future taxable income to utilize the loss carry forward benefits before they expire; however, if not, we could be required to recognize a loss for some or all of these tax assets. Net operating loss carry forwards and other deferred tax assets are reviewed annually for recoverability and are recorded net of a valuation allowance, if necessary.

Off-Balance Sheet Arrangements

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

RESULTS OF OPERATIONS

Summary Financial Data

Years Ended December 31, 2005, 2004 and 2003

	Years Ended December 31,
	2005		2004		2003
	(in thousands)
Total operating revenues	$	310,448	$	179,729	$	140,949
Total operating expenses		162,233		120,214		93,782
Operating income		149,129		60,693		48,498
Income from continuing operations		87,272		31,272		18,505
Income before accounting change		87,434		31,272		18,505
Net income		87,434		31,272		16,208

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Net income for the years ending December 31, 2005, 2004 and 2003 was $87.4 million ($1.08 per diluted share), $31.3 million ($0.41 per diluted share), and $16.2 million ($0.24 per diluted share), respectively. Net income for 2005 included a gain of $0.2 million from the operation and sale of drilling rigs purchased and sold during the year. Included in 2003 was a $2.3 million charge ($0.03 per diluted share), net of tax, for the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003. The 2003 period also included a $3.8 million pre-tax charge ($2.5 million after tax) to interest expense as a result of our early redemption of $53 million in principal amount of our subordinated notes payable.

Operating Revenues

Total revenues for 2005 were $310.4 million, a $130.7 million increase from the $179.7 million reported in 2004. Higher realized prices and additional sales volumes increased revenue $129.0 million. The increase was primarily the result of sales volumes added from new wells placed into production in our Canadian CBM and Texas Barnett Shale development projects and a 49% increase in realized sales prices.

Our 2004 revenues were $179.7 million as compared to $141.0 million for 2003, primarily as a result of additional Canadian revenue in 2004. The additional Canadian revenue was due to a 5,776,000 net Mcfe increase in Canadian production from CBM projects and a 24% increase in realized prices. U.S. production revenue increased by approximately 5% over 2003 revenue with an 11% increase in realized prices being partially offset by a decrease in production of 1,711,000 Mcfe.

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Gas, Oil and NGL Sales

Our sales volumes, revenues and average prices for the years ended December 31, 2005, 2004 and 2003 are as follows:

	Years Ended December 31,
	2005		2004		2003
Average daily sales volume
Natural gas—Mcfd
United States		87,518		83,727		86,608
Canada		40,617		23,789		8,011
Total		128,135		107,516		94,619
Crude oil—Bbld
United States		1,516		1,882		2,212
Canada		—		—		1
Total		1,516		1,882		2,213
NGL—Bbld
United States		603		351		365
Canada		8		1		4
Total		611		352		369
Total sales—Mcfed
United States		100,223		97,120		102,073
Canada		40,672		23,802		8,042
Total		140,895		120,922		110,115
Natural gas, oil and NGL revenue (in thousands)
United States	$	209,715	$	134,268	$	127,339
Canada		96,489		42,905		11,698
Total natural gas, oil and NGL revenue	$	306,204	$	177,173	$	139,037
Product revenue (in thousands)
Natural gas sales	$	269,547	$	150,716	$	116,563
Crude oil sales		27,947		22,782		19,576
NGL sales		8,710		3,675		2,898
Total product sale revenue	$	306,204	$	177,173	$	139,037
Unit prices—including impact of hedges
Natural gas—per Mcf
United States	$	5.42	$	3.52	$	3.32
Canada		6.50		4.92		3.98
Consolidated		5.76		3.83		3.38
Crude oil—per Bbl
United States	$	50.50	$	33.07	$	24.23
Canada		—		—		24.46
Consolidated		50.50		33.07		24.23
NGL—per Bbl
United States	$	38.88	$	28.55	$	21.45
Canada		53.91		22.18		26.01
Consolidated		39.08		28.52		21.50

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Natural gas sales for 2005 were $269.5 million and increased $118.8 million from 2004 natural gas revenue of $150.7 million. Higher natural gas prices in 2005 increased revenue $76.1 million. Realized natural gas prices (including contracts with price floors of $2.48 and settlements for natural gas price hedges) rose 54% and 32%, respectively, for U.S. and Canadian natural gas. Our natural gas production in 2005 increased nearly 7,420,000 Mcf from 2004 to almost 46,770,000 Mcf. Continued drilling on our Horseshoe Canyon and other Canadian interests increased production 8,790,000 Mcf, partially offset by natural declines in production rates for existing Canadian wells. U.S. sales volumes for 2005 were approximately 5% higher than 2004. Our drilling program in the Barnett Shale of the Fort Worth Basin resulted in a production increase of over 3,000,000 Mcf from Barnett Shale wells drilled and placed into production in the latter half of 2004 and all of 2005. Wells placed into production in the Antrim and New Albany Shales increased production approximately 610,000 Mcf and 775,000 Mcf for 2005. Wells placed into production on our Michigan non-Antrim interests, as well as other work performed on existing wells, increased production 250,000 Mcf for 2005. Natural production rate declines partially offset these increases.

Revenue from crude oil in 2005 increased $5.1 million despite a decrease of 150,000 Bbl resulting primarily from the sale of Wyoming crude oil properties in the third quarter of 2004 to Meritage Partners LLC. Price increases of approximately 53% from 2004 realized prices resulted in an average 2005 realized price of $50.50.

NGL revenue for 2005 was $8.7 million as compared of $3.7 million for 2004. NGL volumes for 2005 increased approximately 94,000 barrels primarily as a result of natural gas processing in the Barnett Shale that began in the second quarter of 2005. These additional volumes increased revenue approximately $3.7 million from 2004 while a 37% increase in realized prices provided $1.3 million of additional revenue in 2005.

Our natural gas sales for 2004 were $150.7 million and increased $34.1 million from 2003 natural gas sales of $116.6 million. Our realized gas prices in the U.S. and Canada increased 6% and 24%, respectively. Increased prices contributed $23.8 million of the increase in 2004 sales. Natural gas sales volumes showed a net increase of 4,815,000 Mcf for 2004. Canadian 2004 sales volumes were nearly 5,760,000 Mcf over 2003 production of 2,935,000 Mcf; an increase of almost 200%. U.S. sales volumes were increased by production from new wells drilled in the New Albany Shale in Indiana and Kentucky, 1,380,000 Mcf; the Michigan Antrim Shale, 975,000 Mcf; the Michigan Prairie du Chien formation, 185,000 Mcf; and our initial production from the Barnett Shale in north Texas, 130,000 Mcf. Declining production rates on existing wells were the primary factor in production decreases that offset the production from new wells.

Our 2004 revenue from crude oil was $22.8 million and $3.2 million higher than 2003 crude oil revenue of $19.6 million. A 36% increase in realized crude oil prices from $24.23 to $33.07 per barrel boosted revenue $7.1 million. Lower volumes partially offset the increase due to prices by $3.9 million. The sale of Wyoming crude oil properties lowered volumes by approximately 53,200 barrels. The remainder of the decrease was primarily due to natural declines from existing wells.

Sales of NGLs increased $0.8 million for 2004 to $3.7 million. The additional revenue was primarily the result of a 33% increase in realized NGL prices to $28.52 per barrel for 2004. A decrease in NGL volumes of approximately 6,000 barrels partially offset the increase from higher prices. Property dispositions in the third quarter of 2004 caused approximately 1,100 barrels of the volume decrease.

Other Revenues

Other revenue, consisting primarily of revenue from the processing, transportation and marketing of natural gas, was $4.2 million for 2005. The $1.6 million increase from 2004 was primarily the result of revenue earned from the sale of NGLs earned from gas processed through our interim processing facility in the Barnett Shale. This revenue is not expected to recur for 2006 as the final gas processing agreements do not provide for the facility to earn a portion of the NGLs produced from the plant. Other revenue for 2004 was $2.6 million and about $0.6 million higher than other revenue for 2003. Other revenue in 2003 was reduced by $0.5 million as a result of the repurchase of Section 29 tax credit properties.

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Operating Expenses

Operating expenses for 2005 were $162.2 million, a $41.9 million increase from 2004 operating expense. Nearly half of the increase was due to higher sales volumes and new wells placed into production in Canada and Texas as well as an increase in maintenance and repairs for our Michigan properties. Depletion expense for 2005 increased as a result of higher sales volumes and depletion rates. Depreciation also increased as a result of transportation and processing facilities added in Canada and Texas during 2005. There was also a $6.0 million increase in general and administrative costs for 2005 when compared to 2004.

Our operating expenses for 2004 were $120.2 million, or $26.4 million higher than operating expenses for 2003. This increase was primarily the result of higher sales volumes and producing well counts in Canada and Indiana, higher depletion rates and added depreciation on facilities and pipelines placed into service since mid-2003, and an increase in U.S. compressor overhauls performed in 2004 as compared to 2003. General and administrative costs also increased by $4.8 million in 2004.

Oil and Gas Production Expense

	Years Ended December 31,
	2005		2004		2003
	(in thousands, except per unit amounts)
Production expenses
United States	$	69,609	$	55,223	$	48,572
Canada		16,663		10,403		3,952
	$	86,272	$	65,626	$	52,524
Production expenses—per Mcfe
United States	$	1.90	$	1.54	$	1.30
Canada		1.12		1.19		1.35
Consolidated		1.68		1.48		1.31

Oil and gas production expense for 2005 was $86.3 million and $20.7 million higher than 2004 production expense. U.S. production tax expense increased $2.5 million from 2004 to 2005 due primarily to higher natural gas and crude oil prices and an increase in U.S. sales volumes. We also recorded expense of $0.7 million for vesting of restricted stock grants made to all employees early in 2005.

U.S. production expense increased $11.4 million, excluding increases for production tax and stock-based compensation expense, when compared to 2004 production expense. U.S. production expense for 2005 is also net of a $2.4 million reduction in Wyoming production expense as a result of the sale of most of our Wyoming properties in the third quarter of 2004. Operating expense for our Barnett Shale projects in the Fort Worth Basin increased nearly $7.9 million from 2004 to 2005. We had 36.6 net operated wells in operation at the end of 2005 compared to 3 net operated wells at the end of 2004. The growth of our operations increased lease operating expenses $4.7 million, which included $2.9 million for contract labor, equipment rentals and salt water disposal. Initial operating expenses for these items are typically greater when production begins as initial production includes high water production from the fracture stimulations. Operating costs for each well tend to decrease following the period of initial production; however, as we expect to drill 85 net wells in the Fort Worth Basin Barnett Shale, these expenses will remain high for 2006. Expense for the transportation and processing of our Barnett Shale natural gas production increased $3.2 million. Compressor rental expense of approximately $0.7 million will be reduced when the Cowtown Gas Plant becomes operational in the first quarter of 2006. Production expense for our Michigan projects increased $5.4 million from 2004 production expense. Approximately $3.2 million of the increase for 2005 resulted from efforts to perform preventive equipment maintenance and repairs. Michigan environmental compliance and remediation expense increased almost $1.4 million for 2005. Salary and wages expense increased almost $0.6 million for personnel in Michigan, Indiana and Kentucky as a result of annual raises, the hiring of additional personnel and a small increase in 2005 bonuses

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compared to 2004. Generally, we have seen increased demand for equipment, services and supplies in our U.S. operating areas. The higher demand for oilfield equipment, services and supplies has resulted in shortages and increased costs for such items. We expect that these shortages and higher costs could continue in 2006.

Canadian production expense for 2005 increased $6.0 million from 2004 production expense, exclusive of stock-based compensation expense. We drilled 483 (259.1 net) wells during 2005 and net natural gas production increased 6.1 MMcf. Canadian production expense on a Mcfe-basis decreased $0.07/Mcfe. The decrease reflected additional improvement in the economies of scale for our Canadian operations.

Costs for the production of oil and gas were $65.6 million and $13.1 million higher in 2004 as compared to 2003. Higher oil and gas prices, as well as higher Canadian sales volumes for 2004, increased production tax expense $1.5 million. U.S. production expense increased $6.0 million in 2004, excluding production tax increases of $0.6 million. Initial operating expenses associated with new Indiana and Kentucky wells and production increased production expense approximately $2.2 million. The increase included approximately $0.9 million for salt-water disposal and equipment rentals. These expenses were the result of inadequate salt-water disposal capacity and delays in completing electricity connections at each well. During 2004, 35 new wells and 22 non-producing wells acquired in 2003 began production, in addition to 47 wells that began production in the fourth quarter of 2003. Operating costs began to decrease as initial production containing high concentrations of water was followed by natural gas production increases. Production overhead in Indiana increased approximately $0.8 million as a result of personnel added to operate and maintain these properties. Michigan and Indiana operating expenses increased approximately $1.5 million and $0.2 million, respectively, as a result of the routine periodic overhaul of several compressors. Similar overhaul expenses were not incurred during 2003. These items increased U.S. production expenses by $0.14 per Mcfe for 2004 compared to 2003. Remaining production expense increases were attributable to modest price increases across a broad range of expense categories.

Canadian production expenses in 2004, excluding a production tax increase of $0.9 million, increased $5.5 million for 2004. A net increase in Canadian production of approximately 5,780,000 Mcf and higher well counts were the primary factors for the increase. Total Canadian production expense, including production taxes, continued to reflect improving economies of scale as production expense decreased on a Mcfe-basis to $1.19 per Mcfe.

Depletion, Depreciation and Accretion

	Years Ended December 31,
	2005		2004		2003
	(in thousands, except per unit amounts)
Depletion	$	46,615	$	34,530	$	27,379
Depreciation of other fixed assets		7,599		5,179		3,949
Accretion		999		982		739
Total depletion, depreciation and accretion	$	55,213	$	40,691	$	32,067
Average depletion cost per Mcfe	$	0.91	$	0.78	$	0.68

Higher production volumes and an increase in our depletion rate for 2005 increased depletion expense $12.1 million from 2004 depletion expense. The $0.13 per Mcfe increase in our consolidated depletion rate was the result of a higher percentage increase for estimated future development costs as compared to proved reserve increases for 2005 as compared to 2004. Depreciation expense for 2005 increased $2.4 million when compared to 2004 expense. The increase is primarily the result additional gas processing facilities in Canada and the U.S. as well as a full year’s operation of the Cowtown Pipeline in the Barnett Shale.

Depletion expense for 2004 was $34.5 million, as compared to 2003 depletion expense of $27.4 million. Additional sales volumes of approximately 4,070,000 Mcfe and a $0.10 per Mcfe increase in the consolidated

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depletion rate added $7.2 million of depletion expense from 2003 to 2004. The $0.10 per Mcfe higher consolidated depletion rate was the result of additional increases in future development costs as compared to increases in proved reserves when comparing engineering estimates of proved reserves for December 31, 2004 and 2003. The $1.2 million increase in 2004 depreciation was primarily the result of the addition of compression and transportation assets and overhead assets.

General and Administrative Expense

For 2005, general and administrative expense was $19.0 million. The total was $6.0 million higher than 2004 general and administrative expense. During 2005, employee compensation expense increased approximately $5.6 million including nearly $1.0 million of expense for restricted stock granted to executives and employees during 2005. Additional management and administrative personnel increased compensation expense approximately $1.7 million. Bonuses paid to employees for 2005 were $1.9 million higher than 2004 and included $0.6 million for retention and hiring of key personnel. Annual raises and other compensation expenses, including the Company’s contribution to employees’ retirement accounts for 2005, increased general and administrative expense approximately $1.0 million while outside directors’ compensation increased over $0.2 million including almost $0.1 million for vesting of restricted stock granted during 2005. Legal fees were $0.9 million higher due largely to work performed by outside attorneys on various corporate matters and litigation. These increases were partially offset by a $0.4 million decrease in contract labor expense and small decreases in various other expenses from 2004.

General and administrative expense was $12.9 million for 2004. Of the $4.8 million increase from 2003, additional expense of $2.3 million was primarily the result of an increase in management and administrative personnel from August 2003 through March 2004. Contract labor, legal and accounting fees increased approximately $1.0 million for 2004 due largely to Sarbanes-Oxley and corporate governance requirements. Engineering and other professional fees increased approximately $0.4 million from 2003 due primarily to additional fees for preparation of required outside engineering reserve reports. Various other expenses including outside directors’ fees, charitable donations, insurance, investor relations and stock exchange fees increased a total of $0.6 million from 2003 expense amounts.

Interest Expense

Interest expense for 2005 was $21.7 million after interest capitalization of $1.1 million. The $6.1 million increase from 2004 was the result of higher debt balances that resulted from capital expenditures for our 2005 development, exploitation and exploration programs in Canada and Texas and was partially offset by a decrease in the average interest paid on our total debt balance. The decrease in our average interest rate was primarily the result of the 1.875% interest rate borne by our $150.0 million contingently convertible debentures issued in November 2004. Capitalized interest recorded in 2005 was associated with the construction of transportation and processing facilities in the Fort Worth Basin of Texas and in Canada.

For 2004, interest expense was $15.7 million and $4.5 million less than 2003 interest expense. Interest expense in 2003 included a charge of $3.8 million as a result of the early redemption of $53.0 million in principal amount of our subordinated notes payable, which included a $3.2 million prepayment penalty and the write-off of $1.5 million of remaining deferred financing costs, partially offset by a deferred hedging gain of $0.9 million. Ongoing interest expense decreased approximately $0.7 million due to a decrease in LIBOR interest rates and the 2003 issuance of our second mortgage notes, which accrue interest at a substantially lower rate than the subordinated notes payable that were retired in mid-2003, partially offset by an increase in our average debt outstanding during 2004 as compared to 2003.

Income Taxes

	Years Ended December 31,
	2005			2004			2003
Income tax provision (in thousands)	$	40,702		$	14,174		$	9,997
Effective tax rate		31.8	%		31.2	%		35.1	%

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For 2005, our income tax provision was $40.7 million. Our U.S. income tax provision of $26.3 million was established using the statutory U.S. federal rate of 35%. The Canadian tax provision of approximately $14.3 million was accrued at a Canadian combined federal and provincial statutory rate of 33.6% and included a current tax provision of $0.5 million.

Our income tax provision for 2004 was $14.2 million. Our U.S. income tax provision was established using the statutory U.S. federal tax rate of 35.0%. In addition to the deferred tax provision of approximately $8.8 million, a current U.S. tax provision of $0.8 million was accrued for U.S. federal income tax due on a dividend distribution of approximately $86.5 million made to us by MGV in 2004 and consisted of estimated earnings and profits of $15.5 million. We have reinvested the dividend to fund the Barnett Shale development program under a qualified domestic reinvestment plan as defined under Internal Revenue Code Section 965(a)(1), which allows 85% of the dividend to be excluded from U.S. taxable income for the year. The Canadian income tax provision consisted of a deferred tax provision of approximately $5.9 million accrued at a Canadian combined federal and provincial statutory rate of 33.6% and a current tax provision of $0.3 million. The 2004 Canadian deferred tax provision was reduced by a scientific, research and experimental development tax credit of $1.7 million. This credit was granted by Revenue Canada to MGV in 2004 for expenditures incurred in 2001.

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

Our statements of cash flows are summarized as follows:

	Year ended December 31,
	2005		2004		2003
	(in thousands)
Net cash flow provided by operating activities	$	144,468	$	84,847	$	49,602

Operating activities in 2005 generated $144.5 million of cash flows, or a 70% increase from 2004 operating cash flows. The primary factor in our increased operating cash flow was a $56.2 million increase in 2005 net income that reflected a 49% increase in our realized product prices and a 16% increase in 2005 production volumes.

Cash flows from operating activities increased $35.2 million, or 71%, for 2004 compared to 2003. The principal factor in the increase was a $12.2 million increase in operating income for 2004, together with increases in accounts receivable and payable, accrued liabilities and depletion, depreciation and amortization. In addition, 2003 income included a $3.2 million prepayment premium incurred when the $53 million of subordinated notes were redeemed. Operating cash flows were also higher because of MGV’s use of cash calls on other working interest owners prior to incurring capital expenditures on various CBM exploration and development projects. A reduction in our third party marketing activities further increased operating cash flows approximately $2.0 million.

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Our principal operating sources of cash include sales of natural gas, crude oil and NGLs and revenues from natural gas processing and transportation. We sold approximately 64%, 74% and 85% of our 2005, 2004 and 2003 natural gas and crude oil production, respectively, under long-term contracts with price floors and financial hedges. As a result, we benefit from significant predictability of our natural gas and crude oil revenues. However, when natural gas and crude oil market prices exceed our financial hedge collar cap or fixed-price swap prices, we are required to make payments for the settlement of our hedge derivatives on the fifth day of the production month for natural gas hedges and the fifth day after the production month for crude oil hedges. We do not receive market price cash payment from our customers until 25 to 60 days after the month of production. Additionally, in the event of a significant production curtailment, we are required contractually to fulfill our commitments under our long-term sales contracts by purchasing natural gas volumes at market prices.

	Year ended December 31,
	2005			2004			2003
	(in thousands)
Cash flow used in investing activities:
Purchases of property, plant and equipment	$	(329,495	)	$	(215,106	)	$	(138,579	)
Return of investment from equity affiliates		533			48			734
Proceeds from sale of properties and equipment		9,693			9,160			101
Net cash used in investing activities:	$	(319,269	)	$	(205,898	)	$	(137,744	)
Net working capital changes related to acquisition of property and equipment	$	(31,475	)	$	(16,651	)	$	(10,593	)

Purchases of property, plant and equipment accounted for the most significant cash outlays for investing activities in each of the three years ended December 31, 2005. We currently estimate that our spending for property, plant and equipment in 2006 will be approximately $566 million. Total property, plant and equipment costs incurred (purchases of property, plant and equipment plus net working capital changes related to acquisition of property, plant and equipment) by geographic segment for 2005, 2004 and 2003 are as follows:

Property and equipment costs incurred

	United States		Canada		Consolidated
	(in thousands)
2005
Proved acreage	$	821	$	1,620	$	2,441
Unproved acreage		48,419		3,784		52,203
Development costs		24,007		82,388		106,395
Exploration costs		109,148		9,829		118,977
Gas processing, transportation and administrative		59,894		21,059		80,953
Total	$	242,289	$	118,680	$	360,969
2004
Proved acreage	$	11,907	$	2,942	$	14,849
Unproved acreage		31,857		7,144		39,001
Development costs		45,213		71,094		116,307
Exploration costs		25,673		22,631		48,304
Gas processing, transportation and administrative		12,527		769		13,296
Total	$	127,177	$	104,580	$	231,757
2003
Proved acreage	$	3,215	$	3,388	$	6,603
Unproved acreage		24,063		6,739		30,802
Development costs		37,682		41,820		79,502
Exploration costs		9,411		17,066		26,477
Gas processing, transportation and administrative		4,820		284		5,104
Total	$	79,191	$	69,297	$	148,488

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Capital expenditures for our 2005 development, exploitation and exploration activities were focused in two areas. Canadian development and exploration costs were $97.6 million. Our 2005 expenditures in Canada were focused on the development and exploitation of our ongoing CBM projects as well as exploration of additional CBM acreage. Canadian expenditures for gas processing facilities were $20.4 million. Our U.S. capital expenditures were primarily spent on development, exploitation and development of the Barnett Shale in the Fort Worth Basin. Total expenditures for our Texas projects were $153.6 million, including approximately $51.7 million for acreage in the Fort Worth and Delaware Basins. Expenditures for completion of the first phase of our Cowtown Pipeline and construction of our Cowtown Gas Processing Plant in the Fort Worth Basin were over $49.2 million.

Our 2004 capital expenditures for development, exploitation and exploration activities were focused in four areas. Expenditures for Canadian development, exploitation and exploration projects were approximately $104.6 million. Those expenditures continued exploration and development of our initial CBM projects as well as exploration of several additional CBM projects. Included in the $104.6 million of Canadian expenditures was $7.1 million for acquisition of additional acreage in several areas of Alberta. Expenditures for Texas development, exploitation and exploration activities were approximately $55.1 million, including approximately $29.3 million for additional acreage in north Texas. An additional $6.0 million was expended for the first phase of the Cowtown Pipeline. We spent approximately $31.5 million for continued development of our Michigan properties and an additional $2.1 million was spent on transportation and processing infrastructure. New wells and associated infrastructure in southern Indiana and northern Kentucky accounted for approximately $20.6 million of our expenditures for exploration and development activities. An additional $1.1 million was expended for the construction of plant and pipeline infrastructure in the Indiana/Kentucky area.

Capital costs incurred in 2003 of $148.5 million included $69.0 million for development and exploration of our Canadian CBM projects and acreage. We spent $31.8 million for further development of our Indiana/Kentucky properties and additional acreage positions. Our pipeline in the area, Cardinal Pipeline, accounted for $4.0 million of our capital expenditures. Michigan capital expenditures of $24.6 million focused on continued development and exploitation of the Antrim Shale. A significant acreage position in the Fort Worth Basin of Texas was acquired for approximately $12.6 million in 2003.

	Year ended December 31,
	2005			2004			2003
	(in thousands)
Cash flow provided by financing activities:
Issuance of debt	$	183,469		$	511,091		$	114,000
Repayment of debt		(13,079	)		(371,178	)		(113,116	)
Issuance of common stock, net of issuance costs		2,894			2,499			79,926
Purchase of treasury stock		(95	)		—			—
Payment for fractional shares		(18	)		—			—
Debt issuance costs		(745	)		(8,023	)		(1,441	)
Net cash provided by financing activities:	$	172,426		$	134,389		$	79,369

On July 28, 2004, we extended our senior secured credit facility to July 28, 2009 and to provide for revolving credit loans and letters of credit from time to time in an aggregate amount not to exceed the lesser of the borrowing base or $600 million. At December 31, 2005, the current borrowing base was $600 million. The borrowing base is subject to annual redeterminations and certain other redeterminations, based upon several factors. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. funds being available for borrowing by Quicksilver and Canadian funds being available for borrowing by the our Canadian subsidiary, MGV Energy Inc. Our interest rate options under the facility include rates based on LIBOR and specified bank rates. As borrowings increase, LIBOR margins increase in specified increments from 1.125% to a maximum of 1.75%. U.S. borrowings under the facility are guaranteed by most of our domestic subsidiaries and are secured by Quicksilver’s and its subsidiaries’ oil and gas properties. Canadian borrowing

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under the facility is secured by MGV’s oil and gas properties. The lenders annually re-determine the global borrowing base under the facility in accordance with their customary practices for oil and gas loans based upon the estimated value of the our year-end proved reserves. The loan agreements for the credit facility prohibit the declaration or payment of dividends by us and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio. We were in compliance with all such covenants at December 31, 2005. The senior credit facility is also used to issue letters of credit. At December 31, 2005, there were $1.0 million in letters of credit and $242.2 million available under the senior revolving credit facility

At December 31, 2005, we had outstanding $150 million of 1.875% convertible subordinated debentures due in 2024. Holders of the debentures may require us to repurchase all or a portion of their debentures on November 1, 2011, 2014 or 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into Quicksilver common stock at a rate of 32.7209 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events, holders of the debentures are not entitled to exercise their conversion rights unless the closing price of our stock price 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 is $36.67 (120% of the conversion price per share). Upon conversion, we have the option to deliver in lieu of our common stock, cash or a combination of cash and our common stock. At December 31, 2005, the debentures were convertible into 4,908,128 shares of Quicksilver common stock.

On December 31, 2005, we had outstanding $70 million of Second Lien Mortgage Notes due 2006, of which $40 million bore interest at a fixed rate of 7.5% and $30 million bore interest at a variable rate based upon three-month LIBOR plus 5.48%. The Second Lien Mortgage Notes contain restrictive covenants that, among other things, require maintenance of a minimum current ratio of at least 1.0 to 1.0, a ratio of net present value of proved reserves to total debt of at least 1.8 to 1.0; and a ratio of earnings before interest, taxes, depreciation and amortization and non-cash income and expense to interest expense of at least 1.25 to 1.0 (calculated in each case in accordance with the provisions of the Second Mortgage Notes). At December 31, 2005, we were in compliance with such covenants.

As of December 31, 2005, 2004 and 2003, our total capitalization was as follows:

	Year ended December 31,
	2005		2004		2003
	(in thousands)
Long-term and short-term debt:
Senior secured credit facility	$	357,788	$	180,422	$	178,000
Convertible subordinated debentures		147,881		147,769		—
Second lien mortgage notes payable		70,000		70,000		70,000
Various loans		746		1,073		1,386
Deferred gain – fair value interest hedge		117		226		—
Fair value interest hedge		—		—		50
Total debt		576,532		399,490		249,436
Stockholders’ equity		383,615		304,276		241,816
Total capitalization	$	960,147	$	703,766	$	491,252

We believe that our capital resources are adequate to meet the requirements of our existing business. We anticipate that our 2006 capital expenditure budget of approximately $566 million will be funded by cash flow from operations, credit facility utilization, the possible sale of assets and the possible issuance of debt or equity securities.

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Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or other securities, or other possible capital markets transactions, 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 assets and businesses. 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 two or more of those sources.

Financial Position

The following impacted our balance sheet as of December 31, 2005, as compared to our balance sheet as of December 31, 2004:

• A $177.0 million increase in our debt used to finance the development, exploitation and exploration of our oil and gas properties in 2005.

• A $364.4 million increase in our net property, plant and equipment balances before 2005 depletion and depreciation resulting from capital expenditures for development, exploitation and exploration of our oil and gas properties.

• Our current portion of long-term debt has increased by approximately $70.0 million. Our second lien mortgage notes are due December 31, 2006. We expect to refinance these notes through the issuance of debt or other securities or drawing upon our senior secured credit facility.

• A $27.8 million and $4.6 million increase in our current and deferred derivative obligations, respectively, reflecting the relative increase in natural gas prices as compared to the price caps for our natural gas collars at December 31, 2005.

Contractual Obligations and Commercial Commitments

Information regarding our contractual obligations (within the scope of Item 303(a)(5) of Regulations S-K) as of December 31, 2005 is set forth in the following table. Other long-term liabilities constituting contractual obligations reflected on our balance sheet at December 31, 2005 consisted of derivative obligations and asset retirement obligations.

	Payments Due by Period
Contractual Obligations	Total		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
	(in thousands)
Long-Term Debt	$	578,534	$	70,493	$	358,041	$	—	$	150,000
Scheduled Interest Obligations		109,559		9,190		16,728		11,152		72,489
Derivative Obligations		45,263		40,632		4,631		—		—
Purchase Obligations		6,894		6,894		—		—		—
Asset Retirement Obligations		20,965		73		173		115		20,604
Operating Lease Obligations		8,132		2,819		5,313		—		—
Total Obligations	$	769,347	$	130,101	$	384,886	$	11,267	$	243,093

• Long-Term Debt—As of December 31, 2005, we had $357.8 million outstanding under our senior secured credit facility, $150 million of contingently convertible debentures (before discount), $70 million of second lien mortgage notes and $0.7 million of other debt. Based upon our debt outstanding and interest rates in effect at December 31, 2005, we anticipate interest payments to be approximately $27.7 million in 2006. We expect to increase borrowings under our senior secured credit facility to fund our capital spending program throughout 2006. For each additional $10 million in borrowings, annual interest payments will increase by approximately $0.5 million. If the borrowing base under our senior secured credit facility were to be fully utilized by year-end 2006 at interest rates in

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effect at December 31, 2005, we estimate that interest payments would increase by approximately $6.5 million. If interest rates on our December 31, 2005 variable debt balance of $387.8 million increase or decrease by one percentage point, our annual pretax income will decrease or increase by $3.9 million.

• Scheduled Interest Obligations—As of December 31, 2005, we had scheduled interest payments in place for $5.6 million annually on our $150 million of contingently convertible debentures due November 1, 2024 and $2.8 million annually on our $70 million of second lien mortgage notes due December 31, 2006.

• Derivative Obligations—We utilize financial derivatives to manage price risk associated with our natural gas and crude oil product revenue. We also manage interest rate risk associated with our long-term debt. The recorded assets and liabilities associated with our derivative obligations were estimated based on published market prices of natural gas and crude oil for the periods covered by the contracts. Estimates of the liability associated with our interest rate derivative obligations are based upon estimates prepared by our counterparties. These amounts do not necessarily reflect what payments will be made to settle these obligations.

• Purchase Obligations—At December 31, 2005, we were under contract to purchase goods and services for completion of our gas processing plant in Texas. Total remaining obligations for construction and completion of the gas processing plant were $6.9 million including liabilities of $2.8 million recorded at December 31, 2005 for goods received and work performed.

• Asset Retirement Obligations—Our liabilities include the fair value, $21.0 million, of asset retirement obligations that result from the acquisition, construction or development and the normal operation of our long-lived assets.

• Operating Leases—We lease office buildings and other property under operating leases. Our operating lease obligations include $3.8 million of future lease payments to an affiliate of Mercury, which is owned by members of the Darden family.

We have the following commercial commitments as of December 31, 2005.

	Amounts of Commitments Expiration per Period
	Total Committed		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
	(in thousands)
Commercial Commitments
Drilling Rig Commitment	$	4,448	$	4,448	$	—	$	—	$	—
Standby letters of credit		997		420		557		—		—
Total Commitments	$	5,445	$	4,868	$	557	$	—	$	—

• Drilling Rig Commitment—We lease drilling rigs from third parties for use in our development and exploration programs. At December 31, 2005, we had a commitment for the use of one drilling rig at a rate of $15,500 per day through October 14, 2006.

• Standby letters Of Credit—Our letters of credit have been issued to fulfill contractual or regulatory requirements. The majority of these letters of credit were issued under our senior credit facility. All letters have an annual renewal option.

Forward-Looking Information

Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,”

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“predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

• changes in general economic conditions;

• fluctuations in natural gas and crude oil prices;

• failure or delays in achieving expected production from natural gas and crude oil exploration and development projects;

• uncertainties inherent in estimates of natural gas and crude oil reserves and predicting natural gas and crude oil reservoir performance;

• effects of hedging natural gas and crude oil prices;

• competitive conditions in our industry;

• actions taken by third-party operators, processors and transporters;

• changes in the availability and cost of capital;

• delays in obtaining oil field equipment and increases in drilling and other service costs;

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

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

• the effects of existing or future litigation; and

• certain factors discussed elsewhere in this annual report.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

Recently Issued Accounting Standards

In December 2004, the Financial Accounting Standards Boards (“FASB”) issued SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123(R)”). This statement requires the cost resulting from all share-based payment transactions be recognized in the financial statements at their fair value on the grant date. We adopted SFAS No. 123(R) on January 1, 2006 using the modified prospective application method described in the statement. Under the modified prospective application method, we will apply the standard to new awards and to awards modified, repurchased, or cancelled after the required effective date. Additionally, compensation cost for the unvested portion of awards outstanding as of January 1, 2006 will be recognized as compensation expense as the requisite service is rendered after the required effective date. The compensation cost for unvested awards granted prior to January 1, 2006 shall be attributed to periods beginning January 1, 2006 using the attribution method that was used under SFAS No. 123. Our management estimates that adoption of this accounting standard will result in the recognition of compensation expense of $0.6 million and deferred tax benefits of $0.1 million in 2006.

In March 2005, the SEC released SAB No. 107. SAB No. 107 provides the SEC staff position regarding the application of SFAS No. 123(R) and certain SEC rules and regulations, as well as the staff’s views regarding the

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valuation of share-based payment arrangements for public companies. Additionally, SAB No. 107 highlights the importance of disclosures made related to the accounting for share-based payment transactions. Our management does not expect the adoption of SAB No. 107 to have a material impact on its financial position or results of operations.

The FASB issued FASB Interpretation No. 47 (“FIN 47”), Accounting for Conditional Asset Retirement Obligations, in March 2005. FIN 47 clarifies that the term ‘conditional asset retirement obligation’ as used in SFAS No. 143, Accounting for Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Under FIN 47, the fair value of a liability for a conditional asset retirement obligation should be recognized when incurred. SFAS No. 143 notes that in some cases, sufficient information may not be available to reasonably estimate the fair value of the asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. There was no significant impact on our financial position, results of operations or cash flows.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS No. 154”). SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 will become effective for the Company’s fiscal year beginning January 1, 2006. The impact of SFAS No. 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS No. 154 to have a material impact on our financial position, results of operations or cash flows.

The FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 and 140, in February 2006. SFAS No. 155 addresses accounting for beneficial interests in securitized financial instruments. The guidance allows fair value remeasurement for any hybrid financial instrument containing an embedded derivative that would otherwise require bifurcation and clarifies which interest-only and principal-only strips are not subject to SFAS No. 133. SFAS No. 155 also established a requirement to evaluate interests in securitized financial assets to identify any interests that are either freestanding derivatives or contain an embedded derivative requiring bifurcation. The statement is effective for all financial instruments issued or acquired after the beginning of the first fiscal year that begins after September 15, 2006. Management does not expect this statement will have a material impact on our financial position, results of operations or cash flows.

ITEM 7A.    Quantitative and Qualitative Disclosures About Market Risk

The information called for by this Item is incorporated herein by reference to the information in Item 7 of this report under the heading “Financial Risk Management”.

51

ITEM 8. Financial Statements and Supplementary Data

QUICKSILVER RESOURCES INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Management’s Statement of Responsibilities	53
Report of Independent Registered Public Accounting Firm	55
Consolidated Balance Sheets as of December 31, 2005 and 2004	56
Consolidated Statements of Income and Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003	57
Consolidated Statements of Stockholders’ Equity for the Years ended December 31, 2005, 2004 and 2003	58
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003	59
Notes to Consolidated Financial Statements for the Years Ended December 31, 2005, 2004 and 2003	60

52

MANAGEMENT’S STATEMENT OF RESPONSIBILITIES

To the Stockholders of Quicksilver Resources Inc.:

Management of Quicksilver Resources Inc. is responsible for the preparation, integrity and fair presentation of its published consolidated financial statements. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles and, as such, include amounts based on judgments and estimates made by management. The Company also prepared the other information included in the annual report and is responsible for its accuracy and consistency with the consolidated financial statements.

Management is also responsible for establishing and maintaining effective internal control over financial reporting. The Company’s internal control over financial reporting includes those policies and procedures that pertain to the Company’s ability to record, process, summarize and report reliable financial data. The Company maintains a system of internal control over financial reporting, which is designed to provide reasonable assurance to the Company’s management and board of directors regarding the preparation of reliable published financial statements and safeguarding of the Company’s assets. The system includes a documented organizational structure and division of responsibility, established policies and procedures, including a code of conduct to foster a strong ethical climate, which are communicated throughout the Company, and the careful selection, training and development of our people.

The Board of Directors, acting through its Audit Committee, is responsible for the oversight of the Company’s accounting policies, financial reporting and internal control. The Audit Committee of the Board of Directors is comprised entirely of outside directors who are independent of management. The Audit Committee is responsible for the appointment and compensation of the independent registered public accounting firm. It meets periodically with management, the independent registered public accounting firm and the internal auditors to ensure that they are carrying out their responsibilities. The Audit Committee is also responsible for performing an oversight role by reviewing and monitoring the financial, accounting and auditing procedures of the Company in addition to reviewing the Company’s financial reports. Internal auditors monitor the operation of the internal control system and report findings and recommendations to management and the Audit Committee. Corrective actions are taken to address control deficiencies and other opportunities for improving the system as they are identified. The independent registered public accounting firm and the internal auditors have full and unlimited access to the Audit Committee, with or without management, to discuss the adequacy of internal control over financial reporting, and any other matters which they believe should be brought to the attention of the Audit Committee.

Management recognizes that there are inherent limitations in the effectiveness of any system of internal control over financial reporting, including the possibility of human error and the circumvention or overriding of internal control. Accordingly, even effective internal control over financial reporting can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect misstatements. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.

Management assessed the Company’s internal control system as of December 31, 2005 in relation to criteria for effective internal control over financial reporting described in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the Company has determined that, as of December 31, 2005, the Company’s system of internal control over financial reporting was effective.

53

The consolidated financial statements have been audited by the independent registered public accounting firm, Deloitte & Touche LLP, which was given unrestricted access to all financial records and related data, including minutes of all meetings of stockholders, the Board of Directors and committees of the Board. Reports of the independent registered public accounting firm, which includes the independent registered public accounting firm’s attestation of management’s assessment of internal controls, are also presented within this document.

/s/    Glenn Darden

President and Chief Executive Officer

/s/    Philip W. Cook

Senior Vice President—Chief Executive Officer

Forth Worth, Texas

March 1, 2006

54

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, 2005 and 2004 and the related consolidated statements of income and comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Quicksilver Resources Inc. and subsidiaries as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 12 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/     Deloitte & Touche LLP

Fort Worth, Texas

March 1, 2006

55

QUICKSILVER RESOURCES INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2005 AND 2004

In thousands, except for share data

	2005			2004(1)
ASSETS
Current assets
Cash and cash equivalents	$	14,318		$	15,947
Accounts receivable, net of allowance of $425 and $314		76,121			38,037
Current deferred income taxes		14,614			3,523
Other current assets		8,531			8,689
Total current assets		113,584			66,196
Investments in and advances to equity affiliates		8,353			8,254
Property, plant and equipment
Oil and gas properties, full-cost method
Subject to depletion		1,079,662			838,134
Unevaluated costs		132,090			97,168
Pipelines and processing facilities		157,396			70,851
General properties		14,086			12,597
Accumulated depletion and depreciation		(271,232	)		(216,140	)
Property, plant and equipment – net		1,112,002			802,610
Other assets		9,155			11,274
	$	1,243,094		$	888,334
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	70,493		$	356
Accounts payable		48,409			28,407
Accrued derivative obligations		40,632			12,784
Accrued liabilities		52,656			41,904
Total current liabilities		212,190			83,451
Long-term debt		506,039			399,134
Deferred derivative obligations		4,631			—
Asset retirement obligations		20,891			17,967
Deferred income taxes		115,728			83,506
Commitments and contingencies (Note 13)		—			—
Stockholders’ equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 1 share issued as of December 31, 2005 and 2004		—			—
Common stock, $0.01 par value, 100,000,000 and 80,000,000 shares authorized, and 78,650,110 and 77,752,151 shares issued as of
December 31, 2005 and 2004, respectively		787			778
Paid in capital in excess of par value		215,175			200,690
Deferred compensation		(3,332	)		—
Treasury stock of 2,571,069 and 2,568,611 shares as of
December 31, 2005 and 2004, respectively		(10,353	)		(10,258	)
Accumulated other comprehensive income (loss)		(12,382	)		6,762
Retained earnings		193,720			106,304
Total stockholders’ equity		383,615			304,276
	$	1,243,094		$	888,334

(1) Share and 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. The split did not affect treasury shares.

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

56

QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

In thousands, except for per share data

	2005			2004(1)			2003(1)
Revenues
Natural gas, NGL and crude oil sales	$	306,204		$	177,173		$	139,037
Other revenue		4,244			2,556			1,912
Total revenues		310,448			179,729			140,949
Expenses
Oil and gas production costs		86,272			65,626			52,524
Other operating costs		1,661			810			971
Depletion, depreciation and amortization		55,213			40,691			32,067
Provision for doubtful accounts		108			153			87
General and administrative		18,979			12,934			8,133
Total expenses		162,233			120,214			93,782
Income from equity affiliates		914			1,178			1,331
Operating income		149,129			60,693			48,498
Other income-net		(585	)		(415	)		(186	)
Interest expense		21,740			15,662			20,182
Income from continuing operations before income taxes		127,974			45,446			28,502
Income tax expense		40,702			14,174			9,997
Income from continuing operations		87,272			31,272			18,505
Discontinued operations—gain from discontinued drilling operations net of income tax of $86		162			—			—
Income before cumulative effect of change in accounting principle		87,434			31,272			18,505
Cumulative effect of change in accounting principle, net of tax		—			—			2,297
Net income	$	87,434		$	31,272		$	16,208
Other comprehensive income—net of taxes
Net derivative settlements		26,892			26,875			27,037
Net change in derivative fair value		(49,743	)		(5,174	)		(20,939	)
Foreign currency translation adjustment		3,707			2,744			10,389
Comprehensive income	$	68,290		$	55,717		$	32,695
Basic net income per common share:
Income before cumulative effect of change in accounting principle	$	1.15		$	0.42		$	0.28
Discontinued operations		—			—			—
Cumulative effect of change in accounting principle, net of tax		—			—			(0.04	)
Net income	$	1.15		$	0.42		$	0.24
Diluted net income per common share:
Income before cumulative effect of change in accounting principle	$	1.08		$	0.41		$	0.27
Discontinued operations		—			—			—
Cumulative effect of change in accounting principle, net of tax		—			—			(0.03	)
Net income	$	1.08		$	0.41		$	0.24
Basic weighted average shares outstanding		75,716			74,654			67,183
Diluted weighted average shares outstanding		82,455			77,015			68,534

(1) Share and 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. The split did not affect treasury shares.

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

57

QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

In thousands, except for share data

	2005			2004(1)			2003(1)
Preferred stock, $0.01 par value, 10,000,000 shares authorized
Balance at end of year: 1 share issued at December 31, 2005, 2004 and 2003	$	—		$	—		$	—
Common stock, $0.01 par value, 100,000,000 shares authorized
Balance at beginning of year		778			768			658
Issuance of common stock		9			10			110
Balance at end of year: 78,650,110, 77,752,151 and 76,779,137 shares issued at December 31, 2005, 2004 and 2003, respectively		787			778			768
Paid in capital in excess of par value
Balance at beginning of year		200,690			193,998			113,692
Acquisition of Voyager Compression Services assets		—			—			(515	)
Treasury stock reissued		—			147			—
Issuance of common stock		—			—			79,170
Stock options exercised		2,885			2,302			1,011
Issuance of restricted stock		5,064			—			—
Tax benefit related to stock options exercised		6,536			4,243			739
Stock issuance costs		—			—			(99	)
Balance at end of year		215,175			200,690			193,998
Deferred compensation
Balance at beginning of year		—			—			—
Issuance of restricted stock		(5,064	)		—			—
Compensation expense recognized		1,732			—			—
Balance at end of year		(3,332	)		—			—
Treasury stock, at cost
Balance at beginning of year		(10,258	)		(10,299	)		(10,099	)
(Acquisition) reissuance of treasury stock, net		(95	)		41			(200	)
Balance at end of year: 2,571,069, 2,568,611 and 2,578,904 shares at December 31, 2005, 2004, and 2003, respectively		(10,353	)		(10,258	)		(10,299	)
Accumulated other comprehensive loss
Deferred losses on hedge derivatives
Balance at beginning of year		(5,658	)		(27,359	)		(33,457	)
Net change during the year related to cash flow hedges		(22,851	)		21,701			6,098
Balance at end of year		(28,509	)		(5,658	)		(27,359	)
Deferred foreign exchange adjustment
Balance at beginning of year		12,420			9,676			(713	)
Foreign currency translation adjustment		3,707			2,744			10,389
Balance at end of year		16,127			12,420			9,676
Total accumulated other comprehensive income (loss)		(12,382	)		6,762			(17,683	)
Retained earnings
Balance at beginning of year		106,304			75,032			58,824
Payment for fractional shares		(18	)		—			—
Net income		87,434			31,272			16,208
Balance at end of year		193,720			106,304			75,032
Total stockholders’ equity	$	383,615		$	304,276		$	241,816

(1) Share and 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. The split did not affect treasury shares.

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

58

QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS END DECEMBER 31, 2005, 2004 AND 2003

In thousands

	2005			2004			2003
Operating activities:
Net income	$	87,434		$	31,272		$	16,208
Charges and credits to net income not affecting cash
Cumulative effect of accounting change, net of tax		—			—			2,297
Depletion, depreciation and amortization		55,213			40,691			32,067
Deferred income taxes		40,298			12,989			9,736
Non-cash compensation		1,732			—			—
Amortization of deferred loan costs		1,429			1,249			2,637
Recognition of unearned revenues		—			—			507
Income from equity affiliates		(914	)		(1,178	)		(1,331	)
Non-cash gain from hedging activities		(462	)		(786	)		(678	)
Other		265			91			455
Changes in assets and liabilities
Accounts receivable		(38,192	)		(11,562	)		(5,259	)
Inventory, prepaid expenses and other assets		(1,919	)		4,413			(3	)
Accounts payable		1,963			2,220			1,246
Accrued and other liabilities		(2,379	)		5,448			(8,280	)
Net cash provided by operating activities		144,468			84,847			49,602
Investing activities:
Purchases of property, plant and equipment		(329,495	)		(215,106	)		(137,895	)
Acquisition of Voyager Compression Service assets		—			—			(684	)
Return of investment from equity affiliates		533			48			734
Proceeds from sale of properties		9,693			9,160			101
Net cash used for investing activities		(319,269	)		(205,898	)		(137,744	)
Financing activities:
Issuance of debt		183,469			511,091			114,000
Repayments of debt		(13,079	)		(371,178	)		(113,116	)
Proceeds from issuance of common stock, net of issuance costs		—			—			79,176
Proceeds from exercise of stock options		2,894			2,499			750
Purchase of treasury stock		(95	)		—			—
Payment for fractional shares		(18	)		—			—
Debt issuance costs		(745	)		(8,023	)		(1,441	)
Net cash provided by financing activities		172,426			134,389			79,369
Effect of exchange rates on cash		746			(1,507	)		3,773
Net increase (decrease) in cash and equivalents		(1,629	)		11,831			(5,000	)
Cash and equivalents at beginning of period		15,947			4,116			9,116
Cash and equivalents at end of period	$	14,318		$	15,947		$	4,116

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

59

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

1.    NATURE OF OPERATIONS

Quicksilver Resources Inc. (“Quicksilver”) is an independent oil and gas company incorporated in the state of Delaware and headquartered in Fort Worth, Texas. Quicksilver engages in the development, exploitation, exploration, acquisition and production and sale of natural gas, NGLs and crude oil as well as the marketing, processing and transmission of natural gas. Substantial portions of Quicksilver’s reserves are located in Michigan, Texas, Indiana, Kentucky, the Rocky Mountains and Alberta, Canada. Quicksilver has U.S. offices in Gaylord, Michigan; Corydon, Indiana; Cut Bank, Montana; Granbury, Texas and a Canadian subsidiary, MGV Energy Inc. (“MGV”) located in Calgary, Alberta.

Quicksilver’s results of operations are largely dependent on the difference between the prices received for its natural gas and crude oil products and the cost to find, develop, produce and market such resources. Natural gas and crude oil prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond Quicksilver’s control. These factors include worldwide political instability, quantities of natural gas in storage, foreign supply of natural gas and crude oil, the price of foreign imports, the level of consumer demand and the price of available alternative fuels. Quicksilver manages a portion of the operating risk relating to natural gas and crude oil price volatility through hedging and fixed price contracts.

2.    SIGNIFICANT ACCOUNTING POLICIES

Stock Split

On June 1, 2005, Quicksilver announced that its Board of Directors declared a three-for-two stock split of Quicksilver’s outstanding common stock effected in the form of a stock dividend. The stock dividend was payable on June 30, 2005, to holders of record at the close of business on June 15, 2005. The split did not affect treasury shares.

On June 1, 2004, 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 June 30, 2004, to holders of record at the close of business on June 15, 2004. The split did not affect treasury shares.

The capital accounts, all share data and earnings per share data included in the accompanying Consolidated Financial Statements for all years presented have been adjusted to retroactively reflect the June 2005 stock split.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of Quicksilver and its subsidiaries (collectively, the “Company”). The Company accounts for its ownership in unincorporated partnerships and companies under the equity method of accounting as it has significant influence over those entities, but because of terms of the ownership agreements Quicksilver does not meet the criteria for control which would require consolidation of the entities. The Company also consolidates its pro-rata share of oil and gas joint ventures. All significant inter-company transactions are eliminated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the

60

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

financial statements and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from the Company’s estimates. Significant estimates underlying these financial statements include the estimated quantities of proved natural gas and crude oil reserves used to compute depletion of natural gas and crude oil properties and the related present value of estimated future net cash flows therefrom (see Supplemental Information beginning on page 87), estimates of current revenues based upon expectations for actual deliveries and prices received, the estimated fair value of financial derivative instruments and the estimated fair value of asset retirement obligations.

Cash and Cash Equivalents

Cash equivalents consist of time deposits and liquid debt investments with original maturities of three months or less at the time of purchase.

Accounts Receivable

The Company’s customers are natural gas and crude oil purchasers. Each customer and/or counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although the Company does not require collateral, appropriate credit ratings are required and, in some instances, parental guarantees are obtained. Receivables are generally due in 30-60 days. When collections of specific amounts due are no longer reasonably assured, an allowance for doubtful accounts is established. During 2005, one purchaser accounted for approximately 10% of the Company’s total consolidated natural gas, NGL and crude oil sales. For 2004, two purchasers accounted for approximately 15% and 14% of the Company’s total consolidated sales and two purchasers accounted for approximately 17% and 12% of the Company’s total consolidated 2003 sales.

Hedging

The Company enters into financial derivative instruments to hedge price risk for its natural gas and crude oil sales and interest rate risk. Hedging is accounted for in accordance with Statements of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedge Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, which amended SFAS No. 133 (see note 4). The Company does not enter into financial derivatives for trading or speculative purposes.

All derivatives are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and losses that qualify as hedges are recognized in revenues or interest expense in the period in which the hedged transaction is recognized. Gains or losses on derivative instruments terminated prior to their original expiration date are deferred and recognized as income or expense in the period in which the hedged transaction is recognized. Fair value is determined by reference to published future market prices or interest rates. Ineffective portions of hedges, if any, are recognized currently in earnings.

The Company’s long-term contracts for delivery of 25,000 Mcfd and 10,000 Mcfd at a floor of $2.49 and $2.47, respectively, through March 2009 are not considered derivatives but have been designated as normal sales contracts under SFAS No. 133. For 2005, approximately 4,300 Mcfd of these volumes were third-party volumes controlled by the Company.

61

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

Parts and supplies

Parts and supplies consist of well equipment, spare parts and supplies carried on a first-in, first-out basis at the lower of cost or market.

Investments in Equity Affiliates

Income from equity affiliates is included as a component of operating income as the operations of the affiliates are associated with processing and transportation of the Company’s natural gas production.

Properties, Plant, and Equipment

The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, geological and geophysical expenses, dry holes, leasehold equipment and overhead charges directly related to acquisition, exploration and development activities are capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized.

The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves as determined by independent petroleum engineers. Excluded from amounts subject to depletion are costs associated with unevaluated properties. Natural gas and crude oil are converted to equivalent units based upon the relative energy content, which is six thousand cubic feet of natural gas to one barrel of crude oil.

Net capitalized costs are limited to the lower of unamortized cost net of deferred tax or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge the Company’s oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, (iii) the lower of cost or market value of unproved properties included in the cost being amortized less (iv) income tax effects related to differences between the book and tax basis of the natural gas and crude oil properties. Such limitations are imposed separately for the U.S. and Canadian cost centers.

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

Revenue Recognition

Revenues are recognized when title to the products transfer to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue, so that the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2005 and 2004, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

Environmental Compliance and Remediation

Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred. Environmental remediation costs, which improve the condition of a property, are capitalized.

62

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

Income Taxes

Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that will be in effect in years in which the temporary differences are expected to reverse. MGV, the Company’s Canadian subsidiary, computes taxes at rates in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested by MGV and thus not considered available for distribution to the parent Company. Net operating loss carry forwards and other deferred tax assets, are reviewed annually for recoverability, and if necessary, are recorded net of a valuation allowance.

Disclosure of Fair Value of Financial Instruments

The Company’s financial instruments include cash, time deposits, accounts receivable, notes payable, accounts payable, long-term debt and financial derivatives. The fair value of long-term debt is estimated at the present value of future cash flows discounted at rates consistent with comparable maturities for credit risk. The carrying amounts reflected in the balance sheet for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value.

Foreign Currency Translation

The Company’s Canadian subsidiary, MGV, uses the Canadian dollar as its functional currency. All balance sheet accounts of Canadian operations are translated into U.S. dollars at the year-end rate of exchange and statement of income items are translated at the weighted average exchange rates for the year. The resulting translation adjustments are made directly to a separate component of accumulated other comprehensive income within stockholders’ equity. Gains and losses from foreign currency transactions are included in the consolidated statement of income.

Earnings per share

Basic net income or loss per common share is computed by dividing the net income or loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income or loss per common share is computed using the treasury stock method, which also considers the impact to net income and common shares for the potential dilution from stock options, stock warrants and outstanding convertible securities.

63

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income per common share. Total per share amounts may not add due to rounding. No outstanding options were excluded from the diluted net income per share calculation for any of the years presented.

	Years Ended December 31,
	2005		2004		2003
	(in thousands, except per share data)
Income from continuing operations	$	87,272	$	31,272	$	18,505
Income from discontinued operations, net of income taxes		162		—		—
Income from before effect of change in accounting principle		87,434		31,272		18,505
Cumulative effect of change in accounting principle		—		—		2,297
Net income		87,434		31,272		16,208
Impact of assumed conversions—interest on 1.875% contingently convertible debentures, net of income taxes		1,901		317		—
Income available to stockholders assuming conversion
Of contingently convertible debentures	$	89,335	$	31,589	$	16,208
Weighted average common shares—basic		75,715		74,654		67,183
Effect of dilutive securities:
Employee stock options		1,718		1,544		1,351
Employee stock awards		113		—		—
Contingently convertible debentures		4,908		817		—
Weighted average common shares—diluted		82,455		77,015		68,534
Basic:
Income from continuing operations	$	1.15	$	0.42	$	0.28
Income from discontinued operations, net of income taxes		—		—		—
Cumulative effect of change in accounting principle		—		—		(0.04	)
Net income	$	1.15	$	0.42	$	0.24
Diluted:
Income from continuing operations	$	1.08	$	0.41	$	0.27
Income from discontinued operations, net of income taxes		—		—		—
Cumulative effect of change in accounting principle		—		—		(0.03	)
Net income	$	1.08	$	0.41	$	0.24

64

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

Stock-Based Employee Compensation

At December 31, 2005, the Company has two stock-based compensation plans, which are described more fully in Note 16. The Company accounted for its plans under the recognition and measurement principles of APB No. 25, Accounting for Stock Issued to Employees, and related Interpretations. No stock-based employee compensation cost other than that for restricted stock grants is reflected in net income, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings per share if the Company had applied fair value recognition provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation.

	Years Ended December 31,
	2005			2004			2003
	(in thousands, except per share data)
Net income	$	87,434		$	31,272		$	16,208
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of income taxes		(11,359	)		(4,524	)		(423	)
Pro forma net income from continuing operations	$	76,073		$	26,748		$	15,785
Net income
Basic—as reported	$	1.15		$	0.42		$	0.24
Basic—pro forma	$	1.00		$	0.36		$	0.23
Diluted—as reported	$	1.08		$	0.41		$	0.24
Diluted—pro forma	$	0.95		$	0.35		$	0.23

Recently Issued Accounting Standards

In December 2004, the Financial Accounting Standards Boards (“FASB”) issued SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123(R)”). This statement requires the cost resulting from all share-based payment transactions be recognized in the financial statements at their fair value on the grant date. SFAS No. 123(R) was adopted by the Company on January 1, 2006. The Company adopted this statement using the modified prospective application method described in the statement. Under the modified prospective application method, the Company applied the standard to new awards and to awards modified, repurchased, or cancelled after the required effective date. Additionally, compensation cost for the unvested portion of awards outstanding as of the required effective date will be recognized as compensation expense as the requisite service is rendered after the required effective date. The compensation cost for unvested awards granted before adoption of SFAS No. 123R shall be attributed to periods beginning January 1, 2006 using the attribution method that was used under SFAS No. 123. The Company estimates that adoption of this accounting standard will result in the recognition of $0.6 million of compensation expense and $0.1 million of deferred income tax benefits in 2006 for stock option grants awarded prior to adoption of SFAS No. 123(R).

In March 2005, the SEC released SAB No. 107. SAB No. 107 provides the SEC staff position regarding the application of SFAS No. 123(R) and certain SEC rules and regulations, as well as the staff’s views regarding the valuation of share-based payment arrangements for public companies. Additionally, SAB No. 107 highlights the importance of disclosures made related to the accounting for share-based payment transactions. The Company does not expect the adoption of SAB No. 107 to have a material impact on its financial position or results of operations.

The FASB issued FASB Interpretation No. 47 (“FIN 47”), Accounting for Conditional Asset Retirement Obligations, in March 2005. FIN 47 clarifies that the term ‘conditional asset retirement obligation’ as used in SFAS No. 143, Accounting for Retirement Obligations, refers to a legal obligation to perform an asset retirement

65

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Under FIN 47, the fair value of a liability for a conditional asset retirement obligation should be recognized when incurred. SFAS No. 143 notes that in some cases, sufficient information may not be available to reasonably estimate the fair value of the asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. There was no impact on the Company’s financial position, results of operations or cash flows.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS No. 154”). SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 will become effective for the Company’s fiscal year beginning January 1, 2006. The impact of SFAS No. 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS No. 154 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

The FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 and 140, in February 2006. SFAS No. 155 addresses accounting for beneficial interests in securitized financial instruments. The guidance allows fair value remeasurement for any hybrid financial instrument containing an embedded derivative that would otherwise require bifurcation and clarifies which interest-only and principal-only strips are not subject to SFAS No. 133. SFAS No. 155 also established a requirement to evaluate interests in securitized financial assets to identify any interests that are either freestanding derivatives or contain an embedded derivative requiring bifurcation. The statement is effective for all financial instruments issued or acquired after the beginning of the first fiscal year that begins after September 15, 2006. Management does not expect this statement will have a material impact on the Company’s financial position, results of operations or cash flows.

3.    DISCONTINUED DRILLING OPERATIONS

On July 28, 2005, Quicksilver purchased three drilling rigs and other associated assets for $5.6 million. Thereafter, the Company took over drilling operations and began construction of two additional drilling rigs. The Company sold the drilling assets and drilling rigs under construction on September 29, 2005 for $8.2 million. The purchaser of these assets agreed to conduct drilling operations on the Company’s Barnett Shale properties, using the acquired rigs at market rates and on other customary contract terms. During the fourth quarter of 2005, Quicksilver received an additional $0.37 million for inventory, furniture and fixtures. The Company’s estimated book value for all drilling-related assets sold was $8.23 million. The Company recorded a $0.16 million gain before income tax expense from the sale. During the two-month operating period when the rigs were owned by Quicksilver, revenue earned in drilling operations was $1.9 million and operating income before income taxes was $0.1 million.

4.    HEDGING

The Company hedges a portion of its equity production of natural gas and crude oil using various financial derivatives. All derivatives are evaluated using the hedge criteria established under SFAS Nos. 133 and 138. If hedge criteria are met, the change in a derivative’s fair value (for a cash flow hedge) is deferred in stockholders’ equity as a component of accumulated other comprehensive income. These deferred gains and losses are recognized into income in the period in which the hedged transaction is recognized in revenues to the extent the hedge is effective. The ineffective portions of hedges are recognized currently in earnings.

66

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

During 2005, the Company entered into fixed price firm natural gas sale commitments and hedged these commitments with financial price swaps that extend through March 2006. The financial price swaps qualify as fair value hedges. Hedge ineffectiveness resulted in $0.1 million of net gains, $0.1 million of net losses and $0.2 million of net gains in 2005, 2004, 2003, respectively.

On September 11, 2003, the Company entered into a fair value interest swap covering $40 million of its fixed rate 2003 Second Mortgage Notes. The swap converted the debt’s 7.5% fixed rate to a floating six-month LIBOR base rate plus 4.07% through the termination of the notes. The fair value of the swap was $50,000 as of December 31, 2003. In January 2004, the swap position was cancelled and the Company received a cash settlement of $0.3 million that will be recognized over the original maturity date for the swap, December 31, 2006. At December 31, 2005, $0.1 million of the gain remains to be recognized.

The change in carrying value of the Company’s derivatives, firm sale and purchase commitments accounted for as hedges and interest rate swaps in the Company’s balance sheet since December 31, 2004 resulted from the expiration of fixed price commodity swaps and all interest rate hedges, as well as an increase in market prices for natural gas and crude oil. The change in fair value of all cash flow hedges was reflected in accumulated other comprehensive income, net of deferred tax effects. Natural gas and crude oil derivative assets and liabilities reflected as current in the December 31, 2005 balance sheet represent the estimated fair value of contract settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas and crude oil as of the balance sheet date. These settlement amounts are not due and payable until the monthly period in which the related underlying hedged gas or oil sales transaction occurs. Settlement of the underlying hedged transactions occurs in the following 25 to 60 days.

The estimated fair values of all derivatives and the associated fixed price firm sale commitments of the Company as of December 31, 2005 and 2004 are provided below. The associated carrying values of these swaps are equal to the estimated fair values for each period presented. The assets and liabilities recorded in the balance sheet are netted where derivatives with both gain and loss positions are held by a single third party.

	As of December 31,
	2005		2004
	(in thousands)
Derivative assets:
Fixed price sale commitments	$	638	$	314
Natural gas financial collars		—		3,563
Crude oil financial collars		—		106
	$	638	$	3,983
Derivative liabilities:
Fixed price natural gas financial swaps	$	—	$	12,066
Natural gas financial collars		44,480		158
Floating price natural gas financial swaps		463		322
Crude oil financial collars		320		5
Fixed price sale commitments		35		—
Floating to fixed interest rate swap		—		233
	$	45,298	$	12,784

The fair value of all natural gas and crude derivatives and firm sale and purchase commitments accounted for as hedges as of December 31, 2005 and 2004 was estimated based on market prices of natural gas and crude

67

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

oil for the periods covered by the derivatives. The net differential between the prices in each derivative and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. The fair value of the interest rate swap was based upon counterparty estimates of the fair value of such swaps. As a result, the fair value of the Company’s derivatives and commitments does not necessarily represent the value a third party would pay or expect to receive to assume the Company’s contract positions. Derivatives assets of $0.6 million and $40.6 million of total derivative liabilities of $45.3 million have been classified as current at December 31, 2005 based on the maturity of the derivative instruments, resulting in $25.4 million of after-tax losses to be reclassified from accumulated other comprehensive income in 2006.

5.    FINANCIAL INSTRUMENTS

The Company has established policies and procedures for managing risk within its organization, including internal controls. The level of risk assumed by the Company is based on its objectives and capacity to manage risk.

Quicksilver’s primary risk exposure is related to natural gas and crude oil commodity prices. The Company has mitigated the downside risk of adverse price movements through the use of swaps, futures and forward contracts; however in doing so, it has also limited future gains from favorable price movements.

Commodity Price Risk

The Company enters into contracts to hedge its exposure to commodity price risk associated with anticipated future natural gas and crude oil production. These contracts have included physical sales contracts and derivatives including price ceilings and floors, no-cost collars and fixed price swaps. As of December 31, 2005, Quicksilver sells approximately 10 MMcfd and 25 MMcfd of natural gas under long-term contracts with floors of $2.47 per Mcf and $2.49 per Mcf, respectively through March 2009. Approximately 30.7 MMcfd of the Company’s natural gas production was sold under these contracts during 2005. The remaining 4.3 MMcfd sold under these contracts were third-party volumes controlled by the Company. These contracts are not considered derivatives, but rather have been designated as normal sales contracts under SFAS No. 133.

Natural gas price collars have been put in place to hedge 2006 U.S. production of approximately 38 MMcfd and Canadian production of approximately 23 MMcfd. Additionally, the Company has used price collar agreements to hedge approximately 500 Bbld of its crude oil production through the first half of 2006. U.S. and Canadian natural gas production of approximately 20 MMcfd and 10 MMcfd has also been hedged for the first quarter of 2007 using price collars. As a result of these various contracts, the Company benefits from significant predictability of its natural gas and crude oil revenues.

68

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

The following table summarizes the Company’s open financial derivative positions as of December 31, 2005 related to its natural gas and crude oil production.

Product	Type	Contract Period	Volume	Weighted Avg Price Per Mcf or Bbl	Fair Value
					(in thousands)
Gas	Collar	Jan 2006-Mar 2006	10,000 Mcfd	6.50-11.20	$	(812	)
Gas	Collar	Jan 2006-Mar 2006	10,000 Mcfd	6.50-11.20		(812	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.00-10.00		(964	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.00-10.00		(964	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.00-10.10		(949	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.00-10.17		(879	)
Gas	Collar	Jan 2006-Mar 2006	10,000 Mcfd	7.50-9.55		(2,372	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.50-9.55		(1,186	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.50-9.60		(1,160	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.50-10.55		(767	)
Gas	Collar	Jan 2006-Mar 2006	5,000 Mcfd	7.50-10.60		(747	)
Gas	Collar	Jan 2006-Mar 2006	10,000 Mcfd	9.50-12.01		(302	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	5.50-8.10		(2,695	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	5.50-8.25		(2,513	)
Gas	Collar	Apr 2006-Oct 2006	10,000 Mcfd	6.50-8.25		(5,044	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	6.50-8.25		(2,522	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	7.00-8.35		(2,394	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	7.00-8.35		(2,394	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	7.00-8.35		(2,394	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	8.00-10.10		(1,131	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	8.00-10.10		(1,131	)
Gas	Collar	Apr 2006-Oct 2006	10,000 Mcfd	8.00-10.20		(1,085	)
Gas	Collar	Apr 2006-Oct 2006	10,000 Mcfd	8.00-10.20		(1,085	)
Gas	Collar	Nov 2006-Mar 2007	10,000 Mcfd	7.50-9.65		(3,749	)
Gas	Collar	Nov 2006-Mar 2007	10,000 Mcfd	8.50-11.35		(2,254	)
Gas	Collar	Nov 2006-Mar 2007	10,000 Mcfd	8.50-11.50		(2,175	)
Oil	Collar	Jan 2006-Jun 2006	500 Bbld	47.00-62.20		(320	)
			Net Open Positions		$	(44,800	)

Utilization of the Company’s financial hedging program may result in natural gas and crude oil realized prices that vary from actual prices that the Company receives from the sale of natural gas and crude oil. As a result of the hedging programs, revenues from production in 2005, 2004 and 2003 were $41.8 million, $43.9 million and $39.8 million lower, respectively, than if the hedging programs had not been in effect.

Commodity price fluctuations affect the remaining natural gas and crude oil volumes as well as the Company’s NGL volumes. Natural gas volumes of 4.5 MMcfd are committed at market price through May 2006 and an additional 16.5 MMcfd of natural gas is committed at market price through September 2008. During 2005, over 7.2 MMcfd of Quicksilver’s natural gas production was sold under these contracts. Almost 9.3 MMcfd sold under these contracts were third-party volumes controlled by the Company.

The Company entered into various financial contracts to hedge exposure to commodity price risk associated with future contractual natural gas sales and purchases with financial swaps. These firm commitments are fixed price sales or purchases with third parties. As a result of the firm sale and purchase commitments, the associated financial price swaps qualify as fair value hedges. Marketing revenues were $0.1 million, $0.5 million and $0.3 million higher a result of its hedging activities in 2005, 2004 and 2003, respectively.

69

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

The following table summarizes our open financial swap positions and hedged firm commitments as of December 31, 2005 related to natural gas marketing.

Contract Period	Volume	Weighted Avg Price per Mcf		Fair Value
				(in thousands)
Natural Gas Sales Contracts
Jan 2006	6,000 Mcf	$	13.37	$	17
Jan 2006-Feb 2006	10,000 Mcf	$	7.27		(35	)
Jan 2006-Feb 2006	16,000 Mcf	$	12.21		22
Jan 2006-Feb 2006	54,500 Mcf	$	13.09		131
Jan 2006-Mar 2006	240,000 Mcf	$	12.90		461
Feb 2006-Mar 2006	16,350 Mcf	$	11.63		7
				$	603
Natural Gas Financial Derivatives
Jan 2006	10,000 Mcf		Floating Price	$	(5	)
Jan 2006	10,000 Mcf		Floating Price		(22	)
Jan 2006	20,000 Mcf		Floating Price		(19	)
Jan 2006	20,000 Mcf		Floating Price		(55	)
Feb 2006	10,000 Mcf		Floating Price		(8	)
Feb 2006	20,000 Mcf		Floating Price		(22	)
Jan 2006-Mar 2006	120,000 Mcf		Floating Price		(74	)
Jan 2006-Mar 2006	120,000 Mcf		Floating Price		(257	)
Feb 2006-Mar 2006	20,000 Mcf		Floating Price		(1	)
					(463	)
	Total-net			$	140

The fair values of fixed price and floating price natural gas and crude oil derivatives and associated firm commitments as of December 31, 2005 and 2004 were estimated based on market prices of natural gas and crude oil for the periods covered by the contracts. The net differential between the prices in each contract and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. As a result, the natural gas and crude oil financial swap and firm commitment fair value does not necessarily represent the value a third party would pay or expect to receive to assume the Company’s contract positions.

Interest Rate Risk

The Company manages its exposure associated with interest rates by entering into interest rate swaps. As of December 31, 2005, the Company had no interest rate swaps in effect. As of December 31, 2004, the interest payments for $75.0 million notional variable-rate debt were hedged with an interest rate swap that converted a floating three-month LIBOR base to a 3.74% fixed-rate through March 31, 2005. The liability associated with the swap was $0.2 million at December 31, 2004.

On September 10, 2003, the Company entered into an interest rate swap to hedge the $40.0 million of fixed-rate second lien notes issued on June 27, 2003. The swap converted the debt’s 7.5% fixed-rate debt to a floating six-month LIBOR base. The asset associated with the swap was $50,000 at December 31, 2003. In January 2004, the swap position was cancelled and the Company received a cash settlement of $0.3 million that is being

70

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

recognized over the original term of the swap, which ends December 31, 2006. The deferred gain remaining at December 31, 2005 is $0.1 million.

Credit Risk

Credit risk is the risk of loss as a result of non-performance by counterparties of their contractual obligations. The Company sells a portion of its natural gas production directly under long-term contracts, and the remainder of its natural gas and crude oil is sold to large trading companies and energy marketing companies, refineries and other users of petroleum products at spot or short-term contracts. Quicksilver also enters into hedge derivatives with financial counterparties. The Company monitors its exposure to counterparties by reviewing credit ratings, financial statements and credit service reports. Exposure levels are limited and parental guarantees are required according to Company policy. Each customer and/or counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. In this manner, the Company reduces credit risk.

While Quicksilver follows its credit policies at the time it enters into sales contracts, the credit worthiness of counter parties could change over time. The credit ratings of the parent companies of the two counter parties to the Company’s long-term gas contracts were downgraded in early 2003 and remain below the credit ratings required for the extension of credit to new customers.

Performance Risk

Performance risk results when a financial counterparty fails to fulfill its contractual obligations such as commodity pricing or volume commitments. Typically, such risk obligations are defined within the trading agreements. The Company manages performance risk through management of credit risk. Each customer and/or counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter.

Foreign Currency Risk

The Company’s Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, the Company is exposed to foreign currency exchange rate risk. During October and November 2004, Quicksilver loaned MGV approximately $11.4 million. To reduce its exposure to exchange rate risk, MGV entered into a forward contract that fixed the Canadian-to-US exchange rate. The balance of the loan was repaid at the end of November and upon settlement of the forward contract, MGV recognized a gain of $0.2 million.

6.    ACCOUNTS RECEIVABLE

Accounts receivable consist of the following:

	As of December 31,
	2005			2004
	(in thousands)
Accrued production receivables	$	48,392		$	24,351
Joint interest receivables		26,430			13,247
Other receivables		1,724			753
Allowance for bad debts		(425	)		(314	)
	$	76,121		$	38,037

71

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

7.    OTHER CURRENT ASSETS

Other current assets consist of:

	As of December 31,
	2005		2004
	(in thousands)
Parts and supplies	$	6,137	$	4,161
Hedge derivatives (see note 4)		602		2,383
Prepaid expenses and deposits		1,792		2,145
	$	8,531	$	8,689

8.    PROPERTIES, PLANT AND EQUIPMENT

Property and equipment includes the following:

	As of December 31,
	2005			2004
	(in thousands)
Oil and gas properties
Subject to depletion	$	1,079,662		$	838,134
Unevaluated costs		132,090			97,168
Accumulated depletion		(243,094	)		(195,415	)
Net oil and gas properties		968,658			739,887
Other equipment
Pipelines and processing facilities		157,396			70,851
General properties		14,086			12,597
Accumulated depreciation		(28,138	)		(20,725	)
Net other property and equipment		143,344			62,723
Property and equipment, net of accumulated depreciation and depletion	$	1,112,002		$	802,610

Unevaluated Natural Gas and Crude Oil Properties Excluded From Depletion

Under full cost accounting, the Company may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties excluded from natural gas and crude oil properties being amortized at December 31, 2005 and 2004 and the year in which they were incurred as follows:

	December 31, 2005 Costs Incurred During										December 31, 2004 Costs Incurred During
	2005		2004		2003		Prior		Total		2004		2003		2002		Prior		Total
	(in thousands)										(in thousands)
Acquisition costs	$	44,069	$	39,711	$	27,168	$	4,641	$	115,589	$	40,051	$	31,972	$	6,809	$	1,258	$	80,090
Exploration costs		7,559		8,658		284		—		16,501		16,125		845		108		—		17,078
Total	$	51,628	$	48,369	$	27,452	$	4,641	$	132,090	$	56,176	$	32,817	$	6,917	$	1,258	$	97,168

72

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

Costs are transferred into the amortization base on an ongoing basis, as the projects are evaluated and proved reserves established or impairment determined. Pending determination of proved reserves attributable to the above costs, the Company cannot assess the future impact on the amortization rate. As of December 31, 2005, approximately $78.4 million and $29.9 million of the total unevaluated costs of $132.1 million related to the Company’s Texas and Canadian coal bed methane projects, respectively. These costs will be transferred into the amortization base as the undeveloped projects and areas are evaluated. The Company anticipates that the majority of this activity should be completed over the next two to three years.

Capitalized Costs

Capitalized overhead costs that directly relate to exploration and development activities were $5.3 million, $3.1 million and $2.2 million for the years ended December 31, 2005, 2004 and 2003, respectively.

Depletion per Mcfe was $0.91, $0.78 and $0.68 for the years ended December 31, 2005, 2004 and 2003, respectively.

9.    OTHER ASSETS

Other assets consist of:

	As of December 31,
	2005			2004
	(in thousands)
Deferred financing costs	$	15,763		$	15,018
Less accumulated amortization		(7,320	)		(5,891	)
Net deferred financing costs		8,443			9,127
Hedge derivatives (see note 4)		—			1,600
Other		712			547
	$	9,155		$	11,274

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

10.    ACCRUED LIABILITIES

Accrued liabilities include the following:

	As of December 31,
	2005		2004
	(in thousands)
Accrued capital expenditures	$	32,033	$	18,597
Prepayments from partners		2,110		7,607
Accrued operating expenses		8,143		4,382
Revenue payable		5,288		3,834
Accrued property and production taxes		877		2,430
Accrued product purchases		1,192		1,421
Interest payable		1,355		1,112
Environmental liabilities		1,301		972
Other		357		1,549
	$	52,656	$	41,904

73

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

11.    NOTES PAYABLE AND LONG-TERM DEBT

Long-term debt consists of:

	As of December 31,
	2005			2004
	(in thousands)
Senior secured credit facility	$	357,788		$	180,422
Contingently convertible debentures, net of unamortized discount of $2,119 and $2,231		147,881			147,769
Second lien mortgage notes payable		70,000			70,000
Other loans		746			1,073
Deferred gain – fair value interest hedge		117			226
		576,532			399,490
Less current maturities		(70,493	)		(356	)
	$	506,039		$	399,134

Maturities are as follows, in thousands of dollars:

2006	$	70,493
2007		370
2008		—
2009		357,788
2010		—
Thereafter		150,000
	$	578,651

On July 28, 2004, the Company extended its senior secured credit facility to July 28, 2009 and provide for revolving credit loans and letters of credit from time to time in an aggregate amount not to exceed the lesser of the borrowing base or $600 million. At December 31, 2005, the current borrowing base was $600 million. The borrowing base is subject to annual redeterminations and certain other redeterminations, based upon several factors. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. funds being available for borrowing by the Company and Canadian funds being available for borrowing by the Company’s Canadian subsidiary, MGV Energy Inc. The Company’s interest rate options under the facility include rates based on LIBOR and specified bank rates. As borrowings increase, LIBOR margins increase in specified increments from 1.125% to a maximum of 1.75%. U.S. borrowings under the facility are guaranteed by most of Quicksilver’s domestic subsidiaries and are secured by Quicksilver’s and its subsidiaries’ oil and gas properties. Canadian borrowing under the facility are secured by MGV’s oil and gas properties. The lenders annually re-determine the global borrowing base under the facility in accordance with their customary practices for oil and gas loans based upon the estimated value of the Company’s year-end proved reserves. The loan agreements for the credit facility prohibit the declaration or payment of dividends by the Company and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio. The Company was in compliance with all such covenants at December 31, 2005. The senior credit facility was also used to issue letters of credit. At December 31, 2005, the Company had $1.0 million in letters of credit and $242.2 million available under the senior revolving credit facility.

74

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

On November 1, 2004, the Company sold $150 million $1.875% convertible subordinated debentures due November 1, 2024, which are contingently convertible into shares of Quicksilver’s common stock (subject to adjustment). As of December 31, 2005, the debentures were convertible into 4,908,128 shares of Quicksilver’s common stock. Each $1,000 debenture was issued at 98.5% of par and bears interest at an annual rate of 1.875% payable semi-annually on May 1 and November 1 of each year. Holders of the debentures can require the Company to repurchase all or a portion of their debentures on November 1, 2011, 2014 or 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into Quicksilver common stock at a rate of 32.7209 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events, holders of the debentures are not entitled to exercise their conversion rights unless the closing price of Quicksilver’s stock price 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 is $36.67 (120 % of the conversion price per share). Upon conversion, the Company has the option to deliver in lieu of Quicksilver common stock, cash or a combination of cash and Quicksilver common stock. At December 31, 2005, the fair value of the $150 million in principal amount of contingently convertible debentures was $227.7 million.

On June 27, 2003, the Company redeemed $53 million in principal amount of subordinated notes payable through the issuance of $70 million in principal amount of second lien mortgage notes due 2006 (“the Second Lien Mortgage Notes”). As a result of the redemption, the Company recognized additional interest expense of $3.8 million, consisting of a prepayment premium of $3.2 million and write-off of the remaining deferred financing costs of $1.5 million, partially offset by an associated deferred hedging gain of $0.9 million. A portion ($30 million) of the $70 million Second Mortgage Notes bear interest at a variable annual rate based upon the three-month LIBOR rate plus 5.48%, and the remainder ($40 million) bear interest at the fixed rate of 7.5% per annum. The Second Lien Mortgage Notes contain restrictive covenants, which, among other things, require maintenance of a minimum current ratio of at least 1.0, a ratio of net present value of proved reserves to total debt of at least 1.8 to 1.0; and a ratio of earnings before interest, taxes, depreciation and amortization and non-cash income and expense to interest expense (consolidated net interest expense and current maturities of debt) of at least 1.25 to 1.0 (calculated in each case in accordance with the provisions of the Second Mortgage Notes). At December 31, 2005, the Company was in compliance with all such restrictions. At December 31, 2005, the fair value of the $70 million in principal amount of the Second Lien Mortgage Notes approximated $70.8 million.

On September 11, 2003, the Company entered into a fair value interest swap covering the $40 million fixed rate Second Mortgage Notes. The swap converted the debt’s 7.5% fixed-rate to a floating six-month LIBOR base rate plus 4.07% through the termination of the notes. In January 2004, the swap position was closed, and the Company received $0.3 million. The gain on the swap settlement will be amortized through the original term of the swap, December 31, 2006.

12.    ASSET RETIREMENT OBLIGATIONS

SFAS No. 143, Accounting for Asset Retirement Obligations, was adopted by the Company as of January 1, 2003. At the time of adoption, all asset retirement obligations of the Company were identified and the fair value of the retirement costs were estimated as of the date the long-lived assets were placed into service. At January 1, 2003, the Company recognized asset retirement costs of $10.8 million and asset retirement obligations of $13.3 million. The cumulative-effect adjustment of $2.3 million included $1.3 million for additional depletion and depreciation of the asset retirement costs, $2.2 million for accretion of the fair value of the asset retirement obligation and $1.2 million for deferred tax benefits.

The Company records the fair value of the liability for asset retirement obligations in the period in which it is incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by

75

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

increasing the carrying amount of the long-lived asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is allocated to expense using a systematic method over the asset’s useful life. Changes in the liability for the asset retirement obligation are recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows. During the years ended December 31, 2005, 2004 and 2003, accretion expense was recognized and included in depletion, depreciation and accretion expense reported in the consolidated statement of income for the period.

The following table provides a reconciliation of the changes in the estimated asset retirement obligation from January 1, 2004 through December 31, 2005.

	2005			2004
	(in thousands)
Beginning asset retirement obligation	$	18,471		$	15,189
Additional liability incurred		2,123			2,538
Accretion expense		999			982
Change in estimates		(581	)		—
Sale of properties		(109	)		(680	)
Asset retirement costs incurred		(125	)		(267	)
Loss on settlement of liability		39			143
Currency translation adjustment		148			566
Ending asset retirement obligation	$	20,965		$	18,471

During the years ended December 31, 2005, 2004 and 2003, accretion expense was recognized and included in depletion, depreciation and accretion expense reported in the statement of income for the year. Asset retirement obligations at December 31, 2005 and 2004 are $21.0 million and $18.5 million, respectively, of which $0.1 million and $0.5 million, respectively, was classified as current.

13.    COMMITMENTS AND CONTINGENCIES

The Company leases office buildings and other property under operating leases. Future minimum lease payments, in thousands, for operating leases with initial non-cancelable lease terms in excess of one year as of December 31, 2005, were as follows:

2006	$	2,819
2007		2,494
2008		1,586
2009		1,233
Thereafter		—
Total lease commitments	$	8,132

In February 2006, the Company entered into an amendment to its lease agreement for additional office space at its Fort Worth offices. The lease amendment committed the Company to additional lease payments that total $0.6 million through 2009.

Rent expense for operating leases with terms exceeding one month was $2.3 million in 2005, $1.5 million in 2004 and $1.4 million in 2003.

As of December 31, 2005, the Company had approximately $1.0 million in letters of credit outstanding related to various state and federal bonding requirements.

76

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

In August 2001, a group of royalty owners, Athel E. Williams et al., brought suit against the Company and three of its subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd, one of Quicksilver’s subsidiaries, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who have yet to be determined. The pleadings of the plaintiffs seek damages in an unspecified amount and injunctive relief against future underpayments. The court heard arguments on class certification on November 8, 2002, and on December 6, 2002 the court issued a memorandum opinion granting class certification in part and denying it in part. On December 20, 2002, the Company filed a motion for clarification and reconsideration of the court’s order. That motion was denied on March 9, 2003. After an extended delay resulting from the retention of new counsel by the plaintiffs and the initiation of settlement discussions, on January 21, 2005, the Circuit Court issued an order certifying certain claims to proceed on behalf of a class. The Circuit Court also entered a scheduling order setting trial for January 2007, and denied Defendants’ request to stay proceedings in that court pending an appeal of the certification order.

Defendants have sought leave to appeal the certification order by filing an Application for Leave to Appeal on February 11, 2005 with the Michigan Court of Appeals. Defendants also requested that the Court of Appeals stay proceedings in the Circuit Court pending the consideration of its appeal, and requested that the Court of Appeals consider all matters in an expedited manner. On April 22, 2005, the Court of Appeals vacated the certification order and remanded the case to the trial court with instructions to address several particular issues by way of a new order. After limited discovery relating to those issues, the trial court held a follow-up certification hearing on June 1, 2005.

In late July of 2005, it was announced that the trial court judge, Judge Alton Davis, had been appointed to a seat on the Michigan Court of Appeals. The parties have not been advised as to who will be the new trial court judge over the case.

On August 18, 2005, shortly before ascending to the appellate court, Judge Davis entered new findings and conclusions again favoring certification. Defendants sought leave in the Court of Appeals Court to file supplemental a response to the trial courts’ new findings and conclusions. On January 20, 2006, the Court of Appeals entered an order granting the application for leave to appeal and expediting appellate proceedings. The request to supplement the original appellate filings was denied, but a new briefing schedule was put into place. Defendants’ appellate brief is due by February 24, 2006, and Plaintiffs’ brief is due within 28 days after the filing of the Company’s brief. The case (discovery and trial court proceedings) remains stayed pending the resolution of the appeal.

Based on information currently available to the Company, the Company’s management believes that the final resolution of this matter will not have a material effect on its financial position, results of operations, or cash flows.

The Company is subject to various possible contingencies, which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.

77

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

14.    INCOME TAXES

Deferred income taxes are established for all temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In addition, deferred tax balances must be adjusted to reflect tax rates that will be in effect in the years in which the temporary differences are expected to reverse. For years prior to 2004, the Company had accrued no U.S. deferred income taxes on MGV’s undistributed earnings or on the related translation adjustments pursuant to FAS No. 109, Accounting for Income Taxes, and APB No. 23, Accounting for Income Taxes – Special Areas as the Company expected that MGV’s undistributed earnings would be permanently reinvested for use in the development of its oil and gas reserves. In July 2004, however, a dividend distribution of $86.5 million was made by MGV to Quicksilver. The distribution represented the repayment of Quicksilver’s capital contributions that had been made to MGV for the period January 1, 2001 through July 27, 2004 in the amount of $114.4 million, Canadian. This dividend was reinvested in the U.S. under a qualified domestic reinvestment plan as defined under Internal Revenue Code Section 965 (b)(4). The funds were used for capital expenditures in the Barnett Shale exploration and development program. After application of the 85% dividend exclusion on estimated accumulated earnings and profits of approximately $15.5 million, a current U.S. federal income tax of approximately $0.8 million was accrued on this dividend distribution in 2004 and paid in 2005. No other deferred taxes have been accrued on MGV’s undistributed earnings and the Company continues to expect that the balance of MGV’s undistributed earnings will be permanently reinvested for use in the development of its oil and gas reserves.

Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2005 and 2004 are as follows:

	2005		2004
	(in thousands)
Current
Deferred tax asset
Deferred tax benefit on cash flow hedge losses	$	14,614	$	3,523
Non-current
Deferred tax assets
Deferred tax benefit on cash flow hedge losses	$	1,677	$	—
Net operating loss carry forwards		30,176		18,118
Other		130		233
Total deferred tax assets		31,983		18,351
Deferred tax liabilities
Properties, plant, and equipment		144,628		100,845
Deferred tax liability on cash flow hedge gains		—		593
Deferred tax liability on convertible debenture interest		2,997		419
Deferred tax liability on discontinued operations		86		—
Total deferred tax liabilities		147,711		101,857
Net deferred tax liabilities	$	115,728	$	83,506

78

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

The provisions for income taxes for the years ended December 31, 2005, 2004 and 2003 are as follows:

	2005			2004		2003
	(in thousands)
Current state income tax expense	$	51		$	70	$	79
Current federal income tax expense		(23	)		814		—
Current foreign income tax expense		462			301		182
Total current income tax expense		490			1,185		261
Deferred federal income tax expense		26,312			8,756		8,175
Deferred foreign income tax expense		13,900			4,233		1,561
Total deferred income tax expense		40,212			12,989		9,736
Total	$	40,702		$	14,174	$	9,997
Deferred federal income tax expense on discontinued operations	$	86		$	—	$	—

A reconciliation of the statutory federal income tax rate and the effective tax rate for the years ended December 31, 2005, 2004 and 2003 are as follows:

	2005		2004		2003
U.S. federal statutory tax rate	35.00	%	35.00	%	35.00	%
Dividend income from Canadian subsidiary	—		1.79	%	—
Permanent differences	.11	%	.12	%	.18	%
State income taxes net of federal deduction	.03	%	.10	%	.18	%
Foreign income taxes	(3.36	)%	(5.77	)%	(.27	)%
Other	.02	%	(.05	)%	(.02	)%
Effective income tax rate	31.80	%	31.19	%	35.07	%

Income tax benefits recognized as additional paid-in capital for the years ended December 31, 2005, 2004 and 2003 are as follows:

	2005		2004		2003
	(in thousands)
Income tax benefit recognized on employee stock option exercises	$	6,536	$	4,243	$	739

Included in deferred tax assets are net operating losses of approximately $86.2 million that are available for carryover beginning in the year 2006 to reduce future U.S. taxable income. The net operating losses will expire in 2006 through 2025. These net operating losses have not been reduced by a valuation allowance, because management believes that future taxable income will more likely than not be sufficient to utilize substantially all of its tax carry forwards prior to their expirations. However, under Internal Revenue Code Section 382, a change of ownership was deemed to have occurred for our predecessor, MSR Exploration Ltd. (“MSR”) in 1998. Due to the limitations imposed by Section 382, a portion of MSR’s net operating losses could not be utilized and are not included in deferred tax assets.

15.    EMPLOYEE BENEFITS

Quicksilver has a 401(k) retirement plan available to all employees with three months of service and who are at least 21 years of age. The Company may make discretionary contributions to the plan. Company contributions were $1.0 million, $0.3 million and $0.2 million for the years ended December 31, 2005, 2004 and 2003, respectively.

79

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

The Company initiated a self-funded health benefit plan effective July 1, 2001. The plan has been reinsured on an individual claim and total group claim basis. Quicksilver is responsible for payment of the first $50,000 for each individual claim. The claim liability for the total group was $1.8 million, $2.2 million and $1.1 million for the plan years ended June 30, 2005, 2004 and 2003, respectively. Aggregate level reinsurance is in place for payment of claims up to $1 million over and above the estimated maximum claim liability of $2.1 million for the plan year ending June 30, 2006. Administrative expenses for the plan years ended June 30, 2005, 2004 and 2003 were $0.3 million, $0.4 million and $0.4 million, respectively.

16.    STOCKHOLDERS’ EQUITY

Stock Split

On June 1, 2005, the Company announced that its Board of Directors declared a three-for-two split of the Company’s outstanding common stock effected in the form of a stock dividend. The stock dividend was payable on June 30, 2005, to stockholders of record at the close of business on June 15, 2005. The split did not affect treasury shares.

On June 1, 2004, 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 June 30, 2004, to holders of record at the close of business on June 15, 2004. The split did not affect treasury shares.

The capital stock accounts, all share data and earnings per share data included in the consolidated financial statements and notes give effect to the June 2005 stock split, applied retroactively, to all periods presented.

Common Stock, Preferred Stock and Treasury Stock

The Company is authorized to issue 100 million shares of common stock with a par value per share of one cent ($0.01) and 10 million shares of preferred stock with a par value per share of one cent ($0.01). At December 31, 2005, the Company had 76,079,041 shares of common stock outstanding and one share of special voting preferred stock outstanding.

The following table shows common share and treasury share activity since January 1, 2003:

	Common Shares Issued	Treasury Shares Held
Opening Balance January 1, 2003	65,849,337	2,570,502
Stock options exercised	429,800	8,402
Stock issuance	10,500,000	—
Balance at December 31, 2003	76,779,137	2,578,904
Stock options exercised	973,014	(10,293	)
Balance at December 31, 2004	77,752,151	2,568,611
Stock options exercised	747,988	—
Stock issuance	149,971	2,458
Balance at December 31, 2005	78,650,110	2,571,069

Stockholder Rights Plan

On March 11, 2003, the Company’s board of directors declared a dividend distribution of one preferred share purchase right for each outstanding share of common stock of the Company outstanding on March 26,

80

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

2003. As amended through December 31, 2005, each right, when it becomes exercisable, entitles stockholders to buy one one-thousandth of a share of the Company’s Series A Junior Participating Preferred Stock at an exercise price of $180.00.

The rights will be exercisable only if such a person or group acquires 15% or more of the common stock of Quicksilver or announces a tender offer the consummation of which would result in ownership by such a person or group (an “Acquiring Person”) of 15% or more of the common stock of the Company. This 15% threshold does not apply to certain members of the Darden family and affiliated entities, which collectively owned, directly or indirectly, approximately 35% of the Company’s common stock at December 31, 2005.

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

On October 4, 1999, the Board of Directors adopted the Company’s 1999 Stock Option and Retention Stock Plan (the “1999 Plan”), which was approved at the annual stockholders’ meeting held in June 2000. Upon approval of the 1999 Plan, 3.9 million shares of common stock were reserved for issuance pursuant to grants of incentive stock options, non-qualified stock options, stock appreciation rights and retention stock awards. Pursuant to an amendment approved at the annual shareholders meeting held in May 2004, an additional 3.6 million shares were reserved for issuance pursuant to the 1999 Plan.

In February 2004, the Board of Directors adopted the Company’s 2004 Non-Employee Director Equity Plan (the “2004 Plan”), which was approved at the annual stockholders’ meeting held in May 2004. There were 750,000 shares reserved under the 2004 Plan, which provides for the grant of non-qualified options and restricted stock awards to Quicksilver’s non-employee directors.

Under terms of the 1999 Plan and 2004 Plan, retention stock awards and options may be granted to officers, employees and non-employee directors at an exercise price that is not less than 100% of the fair market value on the date of grant. Incentive stock options and non-qualified options may not be exercised more than ten years from date of grant.

During February through April 2005, the Company awarded 159,257 shares at a weighted average price of $33.62. The retention stock awards will vest ratably over a three-year period. As of December 31, 2005, forfeited stock awards totaled 11,817 shares at a weighted average price of $33.08 and 8,198 shares at a weighted average price of $30.86 were vested under terms of the 1999 Plan. In May 2005, non-employee directors received grants under the 2004 Plan for a total of 2,960 shares at a price of $33.78. The non-employee directors’ stock awards vest over a twelve-month period.

81

A summary of stock option transactions under the plans is as follows:

	2005				2004				2003
	Shares		Wtd Avg Exercise Price		Shares		Wtd Avg Exercise Price		Shares		Wtd Avg Exercise Price
Outstanding at beginning of year	3,653,755		$	14.34	1,888,068		$	2.97	2,214,633		$	2.50
Granted	16,100			24.90	2,766,744			17.99	156,282			7.63
Exercised	(747,988	)		3.87	(983,307	)		2.31	(446,604	)		2.13
Forfeited	(81,172	)		12.64	(17,750	)		11.01	(36,243	)		5.64
Outstanding at the end of year	2,840,695		$	17.13	3,653,755		$	14.34	1,888,068		$	2.97
Exercisable at end of year	2,190,679		$	18.65	874,745		$	3.30	1,370,772		$	2.55
Weighted average fair value of options granted			$	17.67			$	6.62			$	4.12

Pro forma information regarding net income and earnings per share is required by SFAS No. 123, and has been determined as if the Company had accounted for its employee stock options under the fair value method of that statement. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions:

	2005	2004	2003
Wtd avg grant date	Jan 14, 2005	Jul 6, 2004	Feb 21, 2003
Risk-free interest rate	4.0%	2.7%	2.8%
Expected life (in years)	7.0	4.1	6.0
Expected volatility	38.2%	45.4%	54.9%
Dividend yield	—	—	—

The following table summarizes information about stock options outstanding at December 31, 2005.

	Options Outstanding				Options Exercisable
Range of Exercisable Prices	Shares	Wtd Avg Remaining Contractual Life	Wtd Avg Exercise Price		Shares	Wtd Avg Exercise Price
$    3-6	176,269	0.8	$	4.91	176,269	$	4.91
6-11	113,556	2.1		7.65	88,222		7.73
11-16	679,557	4.1		11.17	110,577		12.00
16-22	1,775,135	3.0		20.85	1,775,135		20.85
22-25	93,722	4.5		23.78	38,635		23.71
30-35	2,456	9.2		33.09	1,841		33.09
	2,840,695	3.1	$	17.13	2,190,679	$	18.65

17.    OTHER REVENUE

Other revenue consists of the following:

	For the Years Ended December 31,
	2005			2004		2003
	(in thousands)
Tax credit revenue	$	1,229		$	221	$	(582	)
Marketing		(137	)		928		1,208
Processing and transportation		3,152			1,407		1,286
	$	4,244		$	2,556	$	1,912

82

Until expiration of the tax credit at December 31, 2002, certain properties of the Company earned Internal Revenue Code Section 29 income tax credits. Code Section 29 allowed a credit against regular federal income tax liability for certain eligible gas production.

On March 31, 2000, the Company sold, to a bank, Section 29 tax credits relating to production from certain wells located in Michigan. Cash proceeds received from the sale were $25 million and were recorded as unearned revenue. Revenue was recognized as reserves were produced. The purchase and sale agreement and ancillary agreements with the bank included a production payment in favor of Quicksilver burdening future production on the properties. Revenue of $3.7 million and $9.4 million was recognized in 2002 and 2001, respectively, in other revenue. During 1997, other tax credits attributable to properties owned by the Company were conveyed through the sale of certain working interests to a bank by entities who contributed properties to the Company at the time of its formation. Revenue of $1.4 million and $1.5 million was recognized in 2002 and 2001, respectively, in other revenue.

On July 3, 2003, Quicksilver repurchased interests owned by the bank as a result of the Company’s tax credit sales. Quicksilver paid $6.3 million to acquire all such interests in the Section 29 tax-eligible properties. As a result of the repurchase, the Company recorded, in the first quarter of 2003, a $0.5 million reduction of deferred revenue previously recognized.

18.    CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The following subsidiaries of Quicksilver may in the future become guarantors of certain indebtedness of Quicksilver: Mercury Michigan, Inc., Terra Energy Ltd., GTG Pipeline Corporation, Cowtown Pipeline Funding, Inc., Cowtown Pipeline Management, Inc., Terra Pipeline Company, Beaver Creek Pipeline, LLC, Cowtown Pipeline LP, and Cowtown Gas Processing, LP (collectively, the “Guarantor Subsidiaries”). Each of the Guarantor Subsidiaries is 100% owned by Quicksilver. It is anticipated that any guarantees would be full and unconditional and joint and several. The condensed consolidating financial statements below present the financial position, results of operations and cash flows of Quicksilver, the expected Guarantor Subsidiaries and non-guarantor subsidiaries of Quicksilver as currently contemplated by the Company.

Condensed Consolidating Balance Sheets

	December 31, 2005
	Quicksilver Resources Inc.		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Quicksilver Resources Inc. Consolidated
	(amounts in thousands)
ASSETS
Current assets	$	101,587	$	201,458	$	62,105	$	(251,566	)	$	113,584
Property and equipment, net		638,355		141,193		332,454		—			1,112,002
Investments in subsidiaries (equity method)		290,951		8,932		—		(291,530	)		8,353
Other assets		8,000		—		1,155		—			9,155
Total assets	$	1,038,893	$	351,583	$	395,714	$	(543,096	)	$	1,243,094
LIABILITIES
Current liabilities	$	247,065	$	124,780	$	91,911	$	(251,566	)	$	212,190
Long-term liabilities		408,213		24,542		214,534					647,289
Stockholders’ equity		383,615		202,261		89,269		(291,530	)		383,615
Total liabilities and stockholders’ equity	$	1,038,893	$	351,583	$	395,714	$	(543,096	)	$	1,243,094

83

	December 31, 2004
	Quicksilver Resources Inc.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Quicksilver Resources Inc. Consolidated
	(amounts in thousands)
ASSETS
Current assets	$	57,804	$	137,095	$	28,796	$	(157,499	)	$	66,196
Property and equipment, net		486,327		97,094		219,189		—			802,610
Investments in subsidiaries (equity method)		228,438		9,438		—		(229,622	)		8,254
Other assets		9,153		7		2,114		—			11,274
Total assets	$	781,722	$	243,634	$	250,099	$	(387,121	)	$	888,334
LIABILITIES
Current liabilities	$	148,115	$	52,148	$	40,687	$	(157,499	)	$	83,451
Long-term liabilities		329,331		24,556		146,720					500,607
Stockholders’ equity		304,276		166,930		62,692		(229,622	)		304,276
Total liabilities and stockholders’ equity	$	781,722	$	243,634	$	250,099	$	(387,121	)	$	888,334

Condensed Consolidating Statement of Income

	Year Ended December 31, 2005
	Quicksilver Resources Inc.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Quicksilver Resources Inc. Consolidated
	(amounts in thousands)
Revenues	$	165,194	$	52,678		$	97,044	$	(4,468	)	$	310,448
Operating expenses		111,552		18,243			36,906		(4,468	)		162,233
Income from equity affiliates		62		852			—		—			914
Income from operations		53,704		35,287			60,138		—			149,129
Equity in net earnings of subsidiaries		61,716		—			—		(61,716	)		—
Interest expense and other		14,174		(43	)		7,024		—			21,155
Income tax provision		13,974		12,366			14,362		—			40,702
Net income from continuing operations		87,272		22,964			38,752		(61,716	)		87,272
Gain from discontinued operations, net		162		—			—		—			162
Net income	$	87,434	$	22,964		$	38,752	$	(61,716	)	$	87,434
	Year Ended December 31, 2004
	Quicksilver Resources Inc.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Quicksilver Resources Inc. Consolidated
	(amounts in thousands)
Revenues	$	100,126	$	38,099		$	42,925	$	(1,421	)	$	179,729
Operating expenses		87,179		13,641			20,815		(1,421	)		120,214
Income from equity affiliates		75		1,103			—		—			1,178
Income from operations		13,022		25,561			22,110		—			60,693
Equity in net earnings of subsidiaries		32,539		—			—		(32,539	)		—
Interest expense and other		13,600		(14	)		1,661		—			15,247
Income tax provision		689		8,951			4,534		—			14,174
Net income	$	31,272	$	16,624		$	15,915	$	(32,539	)	$	31,272

84

	Year Ended December 31, 2003
	Quicksilver Resources Inc.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Quicksilver Resources Inc. Consolidated
	(amounts in thousands)
Revenues	$	95,481	$	34,789		$	11,540		$	(861	)	$	140,949
Operating expenses		75,517		12,694			6,432			(861	)		93,782
Income from equity affiliates		86		1,245			—			—			1,331
Income from operations		20,050		23,340			5,108			—			48,498
Equity in net earnings of subsidiaries		18,784		—			—			(18,784	)		—
Interest expense and other		20,093		(11	)		(86	)		—			19,996
Income tax provision		160		8,095			1,742			—			9,997
Net income before accounting change		18,581		15,256			3,452			(18,784	)		18,505
Cumulative effect of accounting change		2,373		13			(89	)		—			2,297
Net income	$	16,208	$	15,243		$	3,541		$	(18,784	)	$	16,208

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2005
	Quicksilver Resources Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Quicksilver Resources Inc. Consolidated
	(amounts in thousands)
Cash flow provided by operations	$	58,242		$	40,201		$	46,024		$	—	$	144,467
Cash flow used for investing activities		(181,613	)		(45,691	)		(91,964	)		—		(319,268	)
Cash flow provided by financing activities		121,933			—			50,493			—		172,426
Effect of exchange rates on cash		—			—			746			—		746
Net increase (decrease) in cash & equivalents		(1,438	)		(5,490	)		5,299			—		(1,629	)
Cash & equivalents at beginning of period		10,428			1,080			4,439			—		15,947
Cash & equivalents at end of period	$	8,990		$	(4,410	)	$	9,738		$	—	$	14,318

	Year Ended December 31, 2004
	Quicksilver Resources Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Quicksilver Resources Inc. Consolidated
	(amounts in thousands)
Cash flow provided by operations	$	48,415		$	9,749		$	26,683		$	—	$	84,847
Cash flow used for investing activities		(103,201	)		(9,071	)		(93,626	)		—		(205,898	)
Cash flow provided by financing activities		62,549			—			71,840			—		134,389
Effect of exchange rates on cash		—			—			(1,507	)		—		(1,507	)
Net increase (decrease) in cash & equivalents		7,763			678			3,390			—		11,831
Cash & equivalents at beginning of period		2,665			402			1,049			—		4,116
Cash & equivalents at end of period	$	10,428		$	1,080		$	4,439		$	—	$	15,947

85

	Year Ended December 31, 2003
	Quicksilver Resources Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Quicksilver Resources Inc. Consolidated
	(amounts in thousands)
Cash flow provided by operations	$	41,351		$	4,567		$	3,684		$	—	$	49,602
Cash flow used for investing activities		(75,230	)		(4,848	)		(57,666	)		—		(137,744	)
Cash flow provided by financing activities		28,193			—			51,176			—		79,369
Effect of exchange rates on cash		—			—			3,773			—		3,773
Net increase (decrease) in cash & equivalents		(5,686	)		(281	)		967			—		(5,000	)
Cash & equivalents at beginning of period		8,351			683			82			—		9,116
Cash & equivalents at end of period	$	2,665		$	402		$	1,049		$	—	$	4,116

19.    SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for interest and income taxes is as follows:

	For the Years Ended December 31,
	2005		2004		2003
	(in thousands)
Interest	$	21,466	$	14,742	$	19,543
Income taxes		888		72		66

Other non-cash transactions are as follows:

	For the Years Ended December 31,
	2005			2004			2003
	(in thousands)
Noncash changes in working capital related to acquisition of property and equipment – net	$	(31,475	)	$	(16,651	)	$	(10,593	)
Distribution of equity to Mercury Exploration Company	$	—		$	—		$	(515	)
Tax benefit recognized on employee stock option exercises		6,536			4,243			739
Treasury stock (acquired) reissued:
10,293 shares for non-employee director stock option exercise		—			189			—
8,402 shares for employee stock option exercise		—			—			(200	)

20.    RELATED PARTY TRANSACTIONS

As of December 31, 2005, members of the Darden family, Mercury Exploration Company (“Mercury”) and Quicksilver Energy L.P., entities that are owned by members of the Darden family, beneficially owned approximately 35% of the Company’s outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.

Quicksilver and its associated entities paid $1.03 million, $0.86 million, and $0.78 million for rent in 2005, 2004 and 2003, respectively, for rent on buildings owned by Pennsylvania Avenue LP (“PALP”), a Mercury affiliate. Rental rates were determined based on comparable rates charged by third parties. In February 2006, the Company entered into an amendment to its lease with PALP to increase the amount of office space covered thereby. In conjunction with this lease amendment, the Company also agreed to sublease a portion of the property it leases from PALP to Mercury. At December 31, 2005, the Company had future lease obligations to Pennsylvania of $3.8 million through 2009. The lease amendment increases future lease obligations to PALP by $0.6 million. The Company also paid $11,400 and $5,600 in 2005 and 2004, respectively, for the use of an airplane owned by Panther City Aviation LLC, a limited liability company owned in part by Thomas Darden.

86

During 2003, Quicksilver paid $2.05 million of $2.05 million note payable to Mercury associated with the acquisition of assets from Mercury. The note was retired upon the repayment. Mercury paid $0.1 million in both 2005 and 2004 to reimburse us for property and casualty insurance, workers compensation insurance and health insurance premiums we paid for the benefit of Mercury.

21.    SEGMENT INFORMATION

The Company operates in two geographic segments, the United States and Canada. Both areas are engaged in the exploration and production segment of the oil and gas industry. The Company evaluates performance based on operating income.

	United States		Canada		Corporate			Consolidated
	(in thousands)
2005
Revenues	$	212,704	$	97,744	$	—		$	310,448
Depletion, depreciation and accretion		35,509		19,089		615			55,213
Operating income (loss)		106,730		61,992		(19,593	)		149,129
Fixed assets—net		777,330		332,580		2,092			1,112,002
Property and equipment costs incurred		241,245		118,680		1,044			360,969
2004
Revenues	$	136,580	$	43,149	$	—		$	179,729
Depletion, depreciation and accretion		30,808		9,282		601			40,691
Operating income (loss)		50,763		23,465		(13,535	)		60,693
Fixed assets—net		581,575		219,369		1,666			802,610
Property and equipment costs incurred		126,512		104,580		665			231,757
2003
Revenues	$	129,235	$	11,714	$	—		$	140,949
Depletion, depreciation and accretion		29,036		2,562		469			32,067
Operating income (loss)		51,898		5,202		(8,602	)		48,498
Fixed assets—net		496,102		106,789		1,685			604,576
Property and equipment costs incurred		78,936		69,297		255			148,488

22.    SUPPLEMENTAL INFORMATION (UNAUDITED)

Proved oil and gas reserves estimates were prepared by independent petroleum engineers with Schlumberger Data and Consulting Services, LaRoche Petroleum Consultants, Ltd. and Netherland, Sewell & Associates, Inc. The reserve reports were prepared in accordance with guidelines established by the Securities and Exchange Commission and, accordingly, were based on existing economic and operating conditions. Natural gas and crude oil prices in effect as of the date of the reserve reports were used without any escalation except in those instances where the sale of production was covered by contract, in which case the applicable contract prices, including fixed and determinable escalations, were used for the duration of the contract, and thereafter the year-end price was used (See “Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves” below for a discussion of the effect of the different prices on reserve quantities and values.) Operating costs, production and ad valorem taxes and future development costs were based on current costs with no escalation.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of the Company’s natural gas and crude oil reserves or the costs that would be incurred to obtain equivalent reserves.

87

The changes in proved reserves for the years ended December 31, 2003, 2004 and 2005 were as follows:

	Natural Gas (MMcf)						Crude Oil (MBbl)						NGL (MBbl)
	United States		Canada		Total		United States		Canada		Total		United States		Canada		Total
December 31, 2002	637,984		53,602		691,586		16,002		—		16,002		2,216		—		2,216
Revisions	(9,137	)	2,363		(6,774	)	(2,022	)	1		(2,021	)	(165	)	2		(163	)
Extensions and discoveries	45,081		93,591		138,672		—		—		—		—		—		—
Purchases in place	1,204		—		1,204		—		—		—		—		—		—
Production	(31,612	)	(2,924	)	(34,536	)	(807	)	(1	)	(808	)	(133	)	(2	)	(135	)
December 31, 2003	643,520		146,632		790,152		13,173		—		13,173		1,918		—		1,918
Revisions	(18,350	)	(12,105	)	(30,455	)	(43	)	—		(43	)	(44	)	1		(43	)
Extensions and discoveries	28,752		131,796		160,548		3		—		3		2,447		—		2,447
Purchases in place	5,000		3,461		8,461		—		—		—		—		—		—
Sales in place	(602	)	—		(602	)	(3,377	)	—		(3,377	)	(6	)	—		(6	)
Production	(30,644	)	(8,707	)	(39,351	)	(689	)	—		(689	)	(128	)	(1	)	(129	)
December 31, 2004	627,676		261,077		888,753		9,067		—		9,067		4,187		—		4,187
Revisions	(7,898	)	(21,155	)	(29,053	)	(2,883	)	—		(2,883	)	(1,233	)	3		(1,230	)
Extensions and discoveries	128,038		79,813		207,851		280		—		280		6,884		—		6,884
Purchases in place	236		—		236		4		—		4		5		—		5
Sales in place	(65	)	—		(65	)	—		—		—		—		—		—
Production	(31,944	)	(14,825	)	(46,769	)	(553	)	—		(553	)	(220	)	(3	)	(223	)
December 31, 2005	716,043		304,910		1,020,953		5,915		—		5,915		9,623		—		9,623
Proved developed reserves
December 31, 2003	569,979		83,698		653,677		8,734		—		8,734		1,405		—		1,405
December 31, 2004	556,999		149,453		706,452		4,587		—		4,587		2,464		—		2,464
December 31, 2005	593,630		199,859		793,489		4,986		—		4,986		5,153		—		5,153

88

The capitalized costs relating to oil and gas producing activities and the related accumulated depletion, depreciation and accretion as of December 31, 2005, 2004 and 2003 were as follows:

	United States			Canada			Consolidated
	(in thousands)
2005
Proved properties	$	779,661		$	300,001		$	1,079,662
Unevaluated properties		102,206			29,884			132,090
Accumulated DD&A		(210,495	)		(32,599	)		(243,094	)
Net capitalized costs	$	671,372		$	297,286		$	968,658
2004
Proved properties	$	644,527		$	193,607		$	838,134
Unevaluated properties		57,929			39,239			97,168
Accumulated DD&A		(180,975	)		(14,440	)		(195,415	)
Net capitalized costs	$	521,481		$	218,406		$	739,887
2003
Proved properties	$	577,322		$	88,135		$	665,457
Unevaluated properties		27,110			22,809			49,919
Accumulated DD&A		(155,183	)		(4,618	)		(159,801	)
Net capitalized costs	$	449,249		$	106,326		$	555,575

Costs incurred in oil and gas property acquisition, exploration and development activities during the years ended December 31, 2005, 2004 and 2003 were as follows:

	United States		Canada		Consolidated
	(in thousands)
2005
Proved acreage	$	821	$	1,620	$	2,441
Unproved acreage		48,419		3,784		52,203
Development costs		24,007		82,388		106,395
Exploration costs		109,148		9,829		118,977
Total	$	182,395	$	97,621	$	280,016
2004
Proved acreage	$	11,907	$	2,942	$	14,849
Unproved acreage		31,857		7,144		39,001
Development costs		45,213		71,094		116,307
Exploration costs		25,673		22,631		48,304
Total	$	114,650	$	103,811	$	218,461
2003
Proved acreage	$	3,215	$	3,388	$	6,603
Unproved acreage		24,063		6,739		30,802
Development costs		37,682		41,820		79,502
Exploration costs		9,411		17,066		26,477
Total	$	74,371	$	69,013	$	143,384

89

Results of operations from producing activities for the years ended December 31, 2005, 2004 and 2003 are set forth below:

	United States		Canada		Consolidated
	(in thousands)
2005
Natural gas, crude oil & NGL sales	$	209,715	$	96,489	$	306,204
Oil & gas production expense		69,609		16,663		86,272
Depletion expense		30,174		17,347		47,521
		109,932		62,479		172,411
Income tax expense		38,476		21,005		59,481
Results from producing activities	$	71,456	$	41,474	$	112,930
2004
Natural gas, crude oil & NGL sales	$	134,268	$	42,905	$	177,173
Oil & gas production expense		55,224		10,402		65,626
Depletion expense		26,444		8,980		35,424
		53,600		23,523		76,123
Income tax expense		18,410		7,908		26,318
Results from producing activities	$	34,190	$	15,615	$	49,805
2003
Natural gas, crude oil & NGL sales	$	127,339	$	11,698	$	139,037
Oil & gas production expense		48,572		3,952		52,524
Depletion expense		25,681		2,428		28,109
		53,086		5,318		58,404
Income tax expense		18,580		2,107		20,687
Results from producing activities	$	34,506	$	3,211	$	37,717

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of the Company’s natural gas and crude oil properties. An estimate of such value should consider, among other factors, anticipated future prices of natural gas and crude oil, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

Under the Standardized Measure, future cash inflows were estimated by applying year-end prices, adjusted for contracts with price floors but excluding hedges, to the estimated future production of the year-end reserves. These prices have varied widely and have a significant impact on both the quantities and value of the proved reserves as reduced prices cause wells to reach the end of their economic life much sooner and also make certain proved undeveloped locations uneconomical, both of which reduce reserves. The following representative natural gas and crude oil year-end prices were used in the Standardized Measure. These prices were adjusted by field for appropriate regional differentials.

	At December 31,
	2005		2004		2003
Natural gas—Henry Hub-Spot	$	10.08	$	6.18	$	5.97
Natural gas—AECO		8.41		5.18		5.32
Crude oil—WTI Cushing		61.06		43.36		32.55

90

Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved natural gas and crude oil properties. Tax credits and net operating loss carry forwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.

The standardized measure of discounted cash flows related to proved oil and gas reserves at December 31, 2005, 2004 and 2003 were as follows:

	United States			Canada			Consolidated
	(in thousands)
2005
Future revenues	$	7,387,151		$	2,487,289		$	9,874,440
Future production costs		(1,974,844	)		(494,056	)		(2,468,900	)
Future development costs		(179,141	)		(145,303	)		(324,444	)
Future income taxes		(1,719,136	)		(539,167	)		(2,258,303	)
Future net cash flows		3,233,166			1,308,763			4,822,793
10% discount—calculated difference		(2,283,052	)		(715,609	)		(2,998,661	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	1,230,978		$	593,154		$	1,824,132
2004
Future revenues	$	4,241,385		$	1,306,819		$	5,548,204
Future production costs		(1,456,005	)		(295,443	)		(1,751,448	)
Future development costs		(116,559	)		(145,297	)		(261,856	)
Future income taxes		(836,557	)		(238,141	)		(1,074,698	)
Future net cash flows		1,832,264			627,938			2,460,202
10% discount—calculated difference		(1,133,990	)		(355,481	)		(1,489,471	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	698,274		$	272,457		$	970,731
2003
Future revenues	$	4,125,685		$	746,722		$	4,872,407
Future production costs		(1,342,167	)		(122,164	)		(1,464,331	)
Future development costs		(117,330	)		(60,696	)		(178,026	)
Future income taxes		(851,337	)		(162,636	)		(1,013,973	)
Future net cash flows		1,814,851			401,226			2,216,077
10% discount—calculated difference		(1,120,056	)		(247,280	)		(1,367,336	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	694,795		$	153,946		$	848,741

91

The primary changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2005, 2004, 2003 were as follows:

	As of December 31,
	2005			2004			2003
	(in thousands)
Net changes in price and production costs	$	734,930		$	(82,974	)	$	140,623
Development costs incurred		44,399			61,069			44,167
Revision of estimates		(29,506	)		(30,509	)		(27,901	)
Changes in estimated future development costs		43,939			3,183			(12,703	)
Purchase and sale of reserves, net		824			(23,367	)		1,832
Extensions and discoveries		515,810			219,656			170,660
Net change in income taxes		(405,724	)		(21,638	)		(99,013	)
Sales of oil and gas net of production costs		(219,932	)		(111,987	)		(86,843	)
Accretion of discount		134,428			120,065			86,775
Other		34,233			(11,508	)		16,293
Net increase	$	853,401		$	121,990		$	233,890

23.    SELECTED QUARTERLY DATA (UNAUDITED)

	Mar 31		Jun 30		Sep 30		Dec 31
	(In thousands, except per share data)
2005
Operating revenues	$	55,249	$	68,540	$	83,773	$	102,886
Operating income		19,943		30,026		41,228		57,932
Net income from continuing operations		10,754		17,185		24,693		34,640
Net income		10,754		17,185		24,755		34,740
Basic net income per share from continuing operations	$	0.14	$	0.23	$	0.33	$	0.46
Basic net income per share		0.14		0.23		0.33		0.46
Diluted net income per share from continuing operations		0.14		0.21		0.31		0.43
Diluted net income per share		0.14		0.21		0.31		0.43
2004
Operating revenues	$	39,777	$	41,980	$	45,544	$	52,428
Operating income		12,012		13,172		16,109		19,400
Net income		5,937		7,500		7,889		9,946
Basic net income per share	$	0.08	$	0.10	$	0.11	$	0.13
Diluted net income per share		0.08		0.10		0.10		0.13

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

ITEM 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us (including our consolidated subsidiaries) in reports that we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported on a timely basis.

92

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in the Exchange Act Rule 13a-15(f). Our management conducted an assessment of our internal control over financial reporting based on the framework established by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework. Based on this assessment, our management has concluded that, as of December 31, 2005, our internal control over financial reporting is effective. Our independent registered public accounting firm, Deloitte & Touche LLP, have issued an attestation report on management’s assessment of our internal control over financial reporting, as stated in their report included herein.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

93

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Quicksilver Resources Inc. Fort Worth, Texas

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Quicksilver Resources Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2005 of the Company and our report dated March 1, 2006 expressed an unqualified opinion on those financial statements.

/s/    Deloitte & Touche LLP

Fort Worth, Texas

March 1, 2006

94

ITEM 9B.    Other Information

None.

95

PART III

ITEM 10.    Directors and Executive Officers of the Registrant

The information concerning our directors is set forth under “Corporate Governance Matters – the Board of Directors” in the proxy statement for our May 23, 2006 annual meeting of stockholders is incorporated herein by reference. The information concerning any changes to the procedure by which a security holder may recommend nominees to the board of directors is set forth under “Corporate Governance Matters – Committees of the Board” in the proxy statement for our May 23, 2006 annual meeting of stockholders is incorporated herein by reference. Certain information concerning our executive officers is set forth under the heading “Business – Executive Officers” in Item 1 of this annual report. The information concerning compliance with Section 16(a) of the Exchange Act is set forth under “Section 16(a) Beneficial Ownership Reporting Compliance” in the proxy statement for our May 23, 2006 annual meeting of stockholders is incorporated herein by reference.

The information concerning our audit committee is set forth under “Corporate Governance Matters – Committees of the Board” in the proxy statement for our May 23, 2006 annual meeting of stockholders is incorporated herein by reference.

The information regarding our Code of Ethics is set forth under “Corporate Governance Matters – Corporate Governance Principles, Processes and Code of Business Conduct and Ethics” in the proxy statement for our May 23, 2006 annual meeting of stockholders is incorporated herein by reference.

ITEM 11.    Executive Compensation

The information set forth under “Executive Compensation” in our proxy statement for our May 23, 2006 annual meeting of stockholders is incorporated herein by reference.

ITEM 12.    Security Ownership of Management and Certain Beneficial Owners and Management and Related Stockholder Matters

The information set forth under “Security Ownership of Management and Certain Beneficial Holders” in the proxy statement for our May 23, 2006 annual meeting of stockholders is incorporated herein by reference. The information regarding our equity plans under which shares of our common stock are authorized for issuance as set forth under “Equity Compensation Plan Information” in the proxy statement for our May 17, 2005 annual meeting of stockholders is incorporated herein by reference.

ITEM 13.    Certain Relationships and Related Transactions

The information set forth under “Transactions with Management and Certain Stockholders” in the proxy statement for our May 23, 2006 annual meeting of stockholders is incorporated herein by reference.

ITEM 14.    Principal Accountant Fees and Services

The information set forth under “Independent Registered Public Accountants” in the proxy statement for our May 23, 2006 annual meeting of stockholders is incorporated herein by reference.

96

PART IV

ITEM 15.    Exhibits and Financial Statement Schedules

(a) The following documents are filed as part of this report:

1. Financial Statements:

The following financial statements of ours and the report of our Independent Auditors thereon are included on pages 52 through 92 of this Form 10-K.

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2005 and 2004

Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003

Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the years ended December 31, 2005, 2004 and 2003

Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003

Notes to Consolidated Financial Statements for the Years Ended December 31, 2005, 2004 and 2003

2. Financial Statement Schedules:

All schedules are omitted because the required information is inapplicable or the information is presented in the financial statements or the notes thereto.

(b) Exhibits:

Exhibit No.	Sequential Description
3.1	Second Restated Certificate of Incorporation of Quicksilver Resources Inc. (filed as Exhibit 4.2 to the Company’s Form 8-A/A filed December 21, 2005 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 4.3 to the Company’s Form 8-A/A filed December 21, 2005 and included herein by reference).
3.3	Bylaws of Quicksilver Resources Inc. (filed as Exhibit 4.2 to the Company’s Form S-4, File No. 333-66709, filed November 3, 1998 and included herein by reference).
3.4	Amendment to the Bylaws of Quicksilver Resources Inc., adopted November 30, 1999 (filed as Exhibit 3.4 to the Company’s Form 10-K filed March 27, 2001 and included herein by reference).
3.5	Amendment to the Bylaws of Quicksilver Resources Inc., adopted June 5, 2001 (filed as Exhibit 3.2 to the Company’s Form 10-Q filed August 14, 2001 and included herein by reference).
3.6	Amendment to the Bylaws of Quicksilver Resources Inc., adopted March 11, 2003 (filed as Exhibit 3.8 to the Company’s Form 10-K filed March 26, 2003 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 JPMorgan Chase Bank, as Trustee (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 JPMorgan ChaseBank, 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).

97

Exhibit No.	Sequential Description
4.3	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 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 Registration Statement on 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 10.2 to the Company’s Form 8-K filed April 19, 2005 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. 2004 Amended and Restated Non-Employee Director Equity Plan (filed as Appendix B to the Company’s Proxy Statement filed April 18, 2005 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	Description of Non-Employee Director Compensation for Quicksilver Resources Inc. (filed as Exhibit 10.6 to the Company’s Form 10-Q filed May 10, 2005 and included herein by reference).
+10.12	Description of Quicksilver Resources Inc. 2005 Bonus Plan for Executive Officers (filed as Exhibit 10.1 to the Company’s Form 8-K filed February 1, 2006 and included herein by reference).
+10.13	Separation, Settlement and Complete Release Agreement, dated August 31, 2005, between Quicksilver Resources Inc. and Mark D. Whitley (filed as Exhibit 10.1 to the Company’s Form 8-K filed September 26, 2005 and included herein by reference).
+10.14	Consulting Agreement, dated October 24, 2005, between Quicksilver Resources Inc. and Bill Lamkin (filed as Exhibit 10.1 to the Company’s Form 8-K filed October 24, 2005 and included herein by reference).

98

Exhibit No.	Sequential Description
+10.15	Change in Control Retention Incentive Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 30, 2004 and included herein by reference).
+10.16	Key Employee Change in Control Retention Incentive Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed August 30, 2004 and included herein by reference).
+10.17	Executive Change in Control Retention Incentive Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed August 30, 2004 and included herein by reference).
+10.18	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).
10.19	Credit Agreement, dated as of July 28, 2004, among Quicksilver Resources Inc., as Borrower, Bank One, NA, Global Administrative Agent, and the other agents and financial institutions listed therein (filed as Exhibit 10.1 to the Company’s Form 10-Q filed August 6, 2004 and included herein by reference).
10.20	Credit Agreement, dated as of July 28, 2004, among MGV Energy, Inc., as Borrower, Bank One, NA, Canada Branch, Canadian Administrative Agent, Bank One, NA, Global Administrative Agent, and the financial institutions listed therein (filed as Exhibit 10.2 to the Company’s Form 10-Q filed August 6, 2004 and included herein by reference).
10.21	First Amendment to Combined Credit Agreements, dated as of September 24, 2004, among Quicksilver Resources Inc., MGV Energy and the agents and combined lenders identified therein (filed as Exhibit 10.2 to the Company’s Form 8-K filed October 12, 2004 and included herein by reference).
10.22	Second Amendment to Combined Credit Agreements, dated as of January 11, 2005, among Quicksilver Resources Inc., MGV Energy Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.17 to the Company’s Form 10-K filed March 16, 2005 and included herein by reference).
10.23	Third Amendment to Combined Credit Agreements, dated as of June 17, 2005, among Quicksilver Resources Inc., MGV Energy Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 28, 2005 and included herein by reference).
10.24	Fourth Amendment to Combined Credit Agreements, dated as of November 30, 2005, among Quicksilver Resources Inc., MGV Energy Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.2 to the Company’s Form 8-K, filed December 1, 2005 and included herein by reference).
10.25	Note Purchase Agreement, dated June 27, 2003, between Quicksilver Resources Inc. and the Purchasers identified therein (filed as Exhibit 4.2 to the Company’s Form 10-Q filed August 14, 2003 and included herein by reference).
10.26	First Amendment to Note Purchase Agreement, dated as of January 30, 2004, between Quicksilver Resources Inc. and the Purchasers identified therein. (filed as Exhibit 4.1 to the Company’s Form 10-Q filed May 7, 2004 and included herein by reference).
10.27	Second Amendment to Note Purchase Agreement, dated as of July 28, 2004, among Quicksilver Resources Inc., certain of its subsidiaries listed therein, BNP Paribas, Collateral Agent, and the Purchasers identified therein (filed as Exhibit 4.1 to the Company’s Form 10-Q filed August 6, 2004 and included herein by reference).
10.28	Third Amendment to Note Purchase Agreement, dated as of September 14, 2004, among Quicksilver Resources Inc., certain of its subsidiaries listed therein, BNP Paribas, Collateral Agent, and the Purchasers identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed September 20, 2004 and included herein by reference).

99

Exhibit No.	Sequential Description
10.29	Fourth Amendment to Note Purchase Agreement, dated as of April 12, 2005, among Quicksilver Resources Inc., certain of its subsidiaries listed therein, BNP Paribas, Collateral Agent, and the Purchasers identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
10.30	Fifth Amendment to Note Purchase Agreement, dated as of June 24, 2005, among Quicksilver Resources Inc., certain of its subsidiaries listed therein, BNP Paribas, Collateral Agent, and the Purchasers identified therein (filed as Exhibit 10.2 to the Company’s Form 8-K filed June 28, 2005 and included herein by reference).
10.31	Sixth Amendment to Note Purchase Agreement, dated as of November 28, 2005, among Quicksilver Resources Inc., certain of its subsidiaries listed therein, BNP Paribas, Collateral Agent, and the Purchasers identified therin (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 1, 2005 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 Netherland, Sewell & Associates, Inc.
* 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.

+ Identifies management contracts and compensatory plans or arrangements.

100

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.

	QUICKSILVER RESOURCES INC. (the “Registrant”)
	By:	/s/    GLENN DARDEN
Dated: March 1, 2006		Glenn Darden President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on behalf of the registrant and in the capacities and on the dates indicated have signed this report below.

SIGNATURE	TITLE	DATE
/s/    THOMAS F. DARDEN         Thomas F. Darden	Chairman of the Board; Director	March 1, 2006
/s/    GLENN DARDEN         Glenn Darden	President and Chief Executive Officer (Principal Executive Officer); Director	March 1, 2006
/s/    PHILIP W. COOK         Philip W. Cook	Senior Vice President – Chief Financial Officer (Principal Financial Officer)	March 1, 2006
/s/    D. WAYNE BLAIR         D. Wayne Blair	Vice President, Controller and Chief Accounting Officer (Principal Accounting Officer)	March 1, 2006
/s/    ANNE DARDEN SELF         Anne Darden Self	Director	March 1, 2006
/s/    JAMES HUGHES         James Hughes	Director	March 1, 2006
/s/    STEVEN M. MORRIS         Steven M. Morris	Director	March 1, 2006
/s/    W. YANDELL ROGERS, III         W. Yandell Rogers, III	Director	March 1, 2006
/s/    MARK J. WARNER         Mark J. Warner	Director	March 1, 2006

101

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF THE REGISTRANT

NAME OF SUBSIDIARY	STATE/JURISDICTION OF INCORPORATION/ ORGANIZATION	NAME UNDER WHICH BUSINESS IS CONDUCTED	PERCENTAGE INTEREST OWNED
MGV Energy Inc.	Canada	MGV Energy Inc.	100
Mercury Michigan Inc.	Michigan	Mercury Michigan Inc.	100
Beaver Creek Pipeline, L.L.C.	Michigan	Beaver Creek Pipeline, L.L.C.	100
Terra Energy Ltd.	Michigan	Terra Energy Ltd.	100
GTG Pipeline Corporation	Virginia	GTG Pipeline Corporation	100
Cowtown Pipeline Funding, Inc.	Delaware	Cowtown Pipeline Funding, Inc.	100
Cowtown Pipeline Management, Inc.	Texas	Cowtown Pipeline Management, Inc.	100
Cowtown Drilling, Inc.	Texas	Cowtown Drilling, Inc.	100

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-69496, 333-89204, 333-92196 and 333-130597 on Form S-3, and Registration Statement Nos. 333-94387, 333-91526, 333-113617 and 333-116180 on Form S-8 of our reports dated March 1, 2006, relating to the consolidated financial statements of Quicksilver Resources Inc. and subsidiaries and to management’s report on the effectiveness of internal control over financial reporting (which report on the financial statements expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003), appearing in this Annual Report on Form 10-K of Quicksilver Resources Inc. and subsidiaries for the year ended December 31, 2005.

DELOITTE & TOUCHE LLP

Fort Worth, Texas

March 1, 2006

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Schlumberger Data and Consulting Services consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Quicksilver Resources Inc. (the “Company”) for the year ended December 31, 2005. We further consent to the use of information contained in our reports, as of December 31, 2005, 2004 and 2003, setting forth the estimates of revenues from the Company’s oil and gas reserves in such Annual Report on Form 10-K. We further consent to the incorporation by reference of such Annual Report on Form 10-K into Registration Statement Nos. 333-69496, 333-89204, 333-92196, 333-122361 and 333-130597 on Form S-3 and Registration Statement Nos. 333-94387, 333-91526, 333-113617 and 333-116180 on Form S-8 of the Company.

SCHLUMBERGER DATA AND CONSULTING SERVICES
By:	/S/ JOSEPH H. FRANTZ, JR.
	Joseph H. Frantz, Jr. USLE Consulting Services Manager

Dallas, Texas

March 1, 2006

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

LaRoche Petroleum Consultants, Ltd. consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Quicksilver Resources Inc. (the “Company”) for the year ended December 31, 2005. We further consent to the use of information contained in our report, as of December 31, 2005 and 2004, setting forth the estimates of revenues from the Company’s oil and gas reserves in such Annual Report on Form 10-K. We further consent to the incorporation by reference of such Annual Report on Form 10-K into Registration Statement Nos. 333-69496, 333-89204, 333-92196, 333-122361 and 333-130597 on Form S-3 and Registration Statement Nos. 333-94387, 333-91526, 333-113617 and 333-116180 on Form S-8 of the Company.

LaROCHE PETROLEUM CONSULTANTS, LTD.
By:	/S/ JOE A. YOUNG
	Joe A. Young Partner

Dallas, Texas

March 1, 2006

EX-23.4

Exhibit 23.4

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Netherland Sewell & Associates, Inc. consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Quicksilver Resources Inc. (the “Company”) for the year ended December 31, 2005. We further consent to the use of information contained in our reports, as of December 31, 2003, setting forth the estimates of revenues from the Company’s oil and gas reserves in such Annual Report on Form 10-K. We further consent to the incorporation by reference of such Annual Report on Form 10-K into Registration Statement Nos. 333-69496, 333-89204, 333-92196, 333-122361 and 333-130597 on Form S-3 and Registration Statement Nos. 333-94387, 333-91526, 333-113617 and 333-116180 on Form S-8 of the Company.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/S/ C. H. (SCOTT) REES III
	C. H. (Scott) Rees III President and Chief Operating Officer

Dallas, Texas

March 1, 2006

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Glenn Darden, certify that:

1. I have reviewed this annual report on Form 10-K of Quicksilver Resources Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 1, 2006

/s/    GLENN DARDEN

Glenn Darden

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Philip W. Cook, certify that:

1. I have reviewed this annual report on Form 10-K of Quicksilver Resources Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 1, 2006

/S/    PHILIP W. COOK

Philip W. Cook

Senior Vice President – Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, in connection with the Annual Report on Form 10-K of Quicksilver Resources Inc. (the “Company”) for the fiscal year ended December 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Philip W. Cook, Senior Vice President – Chief Financial Officer of the Company, and Glenn Darden, President and Chief Executive Officer of the Company, each certifies that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Report.

Date: March 1, 2006

By:    /s/ Philip W. Cook	By:    /s/ Glenn Darden
Philip W. Cook	Glenn Darden
Senior Vice President-Chief Financial Officer	President and Chief Executive Officer