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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)

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:

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.

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.

DOCUMENTS INCORPORATED BY REFERENCE

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INDEX TO ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2005

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.

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:

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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.

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:

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:

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:

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:

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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:

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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:

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:

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:

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:

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

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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

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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.

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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:

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Drilling Activity

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

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Acquisition, Exploration and Development Capital Expenditures

Productive Oil and Gas Wells

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

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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.

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

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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.

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

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PART II.

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.

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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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)

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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

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:

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.

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.

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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.